2002 Annual Report.pdf

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I
FERC Form No.1:
ANNUAL REPORT OF MAJOR ELECTRIC
UTILITIES,LICENSEES AND OTHERS
This report is mandatory under the Federal Power Act,Sections 3,4(a),304 and 309.
and 18 CFR 141.1.Failure to report may result in criminal fines,civil penalties and othersanctionsasprovidedbylaw.The Federal Energy Regulatory Commission does notconsiderthisreporttobeofaconfidentialnature.
Exact Legal Name of Respondent (Company)Year of Report
Avista Corp-Dec.31,2_0002
ERC FORM No.1 (REV.12-98)
INSTRUCTIONSFOR FILING THE
FERC FORM NO.1
GENERAL INFORMATION
I.Purpose
This form is a regulatory support requirement (18 CFR 141.1).It is designed to collect financial andoperationalinformationfrommajorelectricutilities,Licensees and others subject to the jurisdiction of theFederalEnergyRegulatoryCommission.This report is also secondarily considered to be a nonconfidential public useformsupportingastatisticalpublication(Financial Statistics of Selected Electric Utilities),published by theEnergyInformationAdministration.
II.Who Must Submit
Each major electric utility,licensee,or other,as classified in the Commission's Uniform System of AccountsPrescribedforPublicUtilitiesandLicenseesSubjecttotheProvisionsofTheFederalPowerAct(18 CFR 101),mustsubmitthisform.
Note:Major means having,in each of the three previous calendar years,sales or transmission service thatexceeds
one of the following:
(1)one million megawatt hours of total annual sales,
(2)100 megawatt hours of annual sales for resale,
(3)500 megawatt hours of annual power exchanges delivered,or
(4)500 megawatt hours of annual wheeling for others (deliveries plus Losses).
III.What and Where to Submit
(a)Submit this form electronically through the Form 1 Submission Software and an original and six (6)conformed paper copies,properly filed in and attested,to:
Office of the Secretary
Federal Energy Regulatory Commission
888 First Street,NE.
Room lA
Washington,DC 20426
Retain one copy of this report for your files.
Include with the original and each conformed paper copy of this form the subscription statement required by 182.F.R.385.2011(c)(5).Paragraph (c)(5)of 18 C.F.R.385.2011 requires each respondent submitting dataelectronicallytofileasubscriptionstatingthatthepapercopiescontainthesameinformationasthe electronicfiling,that the signer knows the contents of the paper copies and electronic filing,and that the contents asstatedinthecopiesandelectronicfilingaretruetothebestknowledgeandbeliefofthesigner.(b)Submit,immediately upon publication,four (4)copies of the Latest annual report to stockholders and anyLnnualfinanCialOFStatisticalreportregularlypreparedanddistributedtobondholders,security analysts,or.ndustry associations.(Do not include monthly and quarterly reports.Indicate by checking the appropriate box on'age 4,List of Schedules,if the reports to stockholders will be submitted or if no annual report to stockholders
s prepared.)Mail these reports to:
Chief Accountant
Federal Energy Regulatory Commission
888 First Street,NE.
Washington,DC 20426
(c)For the CPA certification,submit with the original submission,or within 30 days after the filing date forhisform,a Letter or report (not applicable to respondents classified as Class C or Class D prior to January 1,984):
(i)Attesting to the conformity,in all material aspects,of the below listed (schedules and)pages with
me Commission's applicable UnifoDm Systems of Accounts (including applicable notes relating thereto and the Chief:countant's published accounting releases),and
(ii)Signed by independent certified public accountants or an independent Licensed public accountantartifiedorLicensedbyaregulatoryauthorityofaStateorotherpoliticalsubdivisionoftheU.S.(See 18 CFR.10-41.12 for specific qualifications.)
C FORM NCI.1 (REV.12-99)Page i
GENERAL INFORMATION (continued)
III.What and Where to Submit (Continued)
(c)Continued
Reference
Schedules Pages
Comparative Balance Sheet 110-113
Statement of Income 114-117
Statement of Retained Earnings 118-119
Statement of Cash Flows 120-121
Notes to Financial Statements 122-123
When accompanying this form,insert the Letter or report immediately following the cover sheet.When submitting
after the filing date for this form,send the letter or report to the office of the Secretary at the address
indicated at III (a).
Use the following format for the Letter or report 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 for the year ended on
which we have reported separately under date of .We have also reviewed 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 circomstances.
Based on our review,in our opinion the accompanying schedules identified in the preceding paragraph (except as
noted below)conform in all material respects with the accounting requirements of the Federal Energy Regulatory
Commission as set forth in its applicable Uniform System of Accounts and published accounting releases.
State in the letter or report,which,if any,of the pages above do not conform to the Commission's
requirements.Describe the discrepancies that exist.
(d)Federal,State and Local Govermnents and other authorized users may obtain additional blank copies to meet
their requirements free of charge from:
Public Reference and Files Maintenance Branch
Federal Energy Regulatory Commission
888 First Street,NE.Room 2A ES-1
Washington,DC 20426
[phone]
IV.When to Submit
Submit this report form on or before April 30th of the year following the year covered by this report .
V.Where to Send Comments on Public Reporting Burden
The public reporting burden for this collection of information is estimated to average 1,217 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.Send comments regarding this burden
estimate or any aspect of this collection of information,including suggestions for reducing this burden,to the
Federal Energy Regulatory Commission,888 First Street N.E.,Washington,DC 20426 (Attention:Mr.Michael Miller,
CI-1);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 this collection of information does not display a valid control number.(44 U.S.C.3512(a)).
FERC FORM NO.1 (REV.12-99)Page ii
GENERAL INSTRUCTIONS
I.Prepare this report in conformity with the Uniform System of Accounts (18 CFR 101)(U.S.of A.).Interpret
all accounting words and phrases in accordance with the U.S.of A.
II.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 year,and use for
statement of income accounts the current year's amounts.
III.Complete each question fully and accurately,even if it has been answered in a previous annual 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 2,3,and 4.
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).The date of the resubmission
must be reported in the header for all form pages,whether or not they are changed from the previous filing.
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,submit the electronic filing using the Form 1 Submission Software and an original and
six (6)conformed paper copies of the entire form,as well as the appropriate number of copies of the subscription
statement indicated at instruction III (a).Resubmissions must be nwnbered sequentially on the cover page of the
paper copies of the form.In addition,the cover page of each paper copy must indicate that the filing is a
resubmission.Send the resubmissions to the address indicated at instruction III (a).
VIII.Do not make references to reports of previous years or to other reports in lieu of required entries,except
as specifically authorized.
IX.Wherever (schedule)pages refer to figures from a previous year,the figures reported must be based upon
those shown by the annual report of the previous year,or an appropriate explanation given as to why the different
figures were used.
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.
ERC FORM NO.1 (REV.12-99)Page lii
EXCERPTS FROM THE LAW
Federal Power Act,16 U.S.C.791a-825r)
"Sec.3.The words defined in this section shall have the following meanings for purposes of this Act,to wit:
...(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 shalt 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 an 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 forebay reservoirs directly connected therewith,the primary line or Lines
transmitting power therefrom 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 be rules and regulations or other prescribe as necessary or
appropriate to assist the Commission in the proper administration of this Act.The Commission my prescribe the
manner and form in which such reports shalt 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."
"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 form or 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 filed..."
General Penalties
"Sec.315.(a)Any licensee or public utility which willfully fails,within the time prescribed by the Commission,
to comply with any order of the Commission,to file any report required under this Act or any rule or regulation of
the Commission thereunder,to submit any information of document required by the Commission in the course of an
investigation conducted under this Act ...shall forfeit to the United States an amount not exceeding 51,000 to be
fixed by the Commission after notice and opportunity for hearing..."
FERC FORM NO.1 (ED.12-91)Page iv
FERC FORM NO.1:
ANNUAL REPORT OF MAJOR ELECTRIC UTILITIES,LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent 02 Year of Report
Avista Corp·Dec.31,2002
03 Previous Name and Date of Change (if name changed during year)
Avista Corp.//
04 Address of Principal Office at End of Year (Street,City,State,Zip Code)
1411 E.Mission Avenue,Spokane,WA 99202
05 Narne of ConstactPerson 06
Sn
orfContaCcerson
07 Address of Contact Person (Street,City,State,Zip Code)081411EhoCnAnvenuPrSspok/anne,WA,9099T2his
Report Is 10 Date of ReportAreaCode(1)An Original (2)A Resubmission (Mo,Da,Yr)
[phone] 04/30/2003
ATTESTATION
The undersigned officer certifies that he/she has examined the accompanying report:that to the best of his/her knowledge,information,and belief,all statements of fact contained in the accompanying report are true and the accompanying report is a correct statement of the business andaffairsoftheabovenamedrespondentinrespecttoeachandeverymattersetforththereinduringtheperiodfromandincludingJanuary1toandincludingDecember31oftheyearofthereport.
01 Name 03 Signature 04 Date Signed02M.eMalquist
04 30/003
Senior Vice President and CFO
..e 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 anyfalse,fictitious or fraudulent statements as to any matter within its jurisdiction.
ERC FORM No.1 (ED.12-91)Page 1
Name of Respondent This R ort Is:Date of Report Year of Report
(1)An Original (Mo,Da,Yr)2002AvistaCorpDec.31,(2)A Resubmission 04/30/2003
LIST OF SCHEDULES (Electric Utility)
Enter in column (c)the terms "none,""not applicable,"or "NA,"as appropriate,where no information or amounts have been reported for
certain pages.Omit pages where the respondents are "none,""not applicable,"or "NA".
Line Title of Schedule Reference Remarks
No.I PageNo.
(a)(b)(c)
1 General Information 101
2 Control Over Respondent 102 None
3 Corporations Controlled by Respondent 103
4 Officers 104
5 Directors 105
6 Important Changes During the Year 108-109
7 Comparative Balance Sheet 110-113
8 Statement of income for the Year 114-117
9 Statement of Retained Earnings for the Year 118-119
10 Statement of Cash Flows 120-121
11 Notes to Financial Statements 122-123
12 Statement of Accum Comp Income,Comp Income,and Hedging Activities 122(a)(b)
13 Summary of Utility Plant &Accumulated Provisions for Dep,Amort &Dep 200-201
14 Nuclear Fuel Materials 202-203 None
15 Electric Plant in Service 204-207
16 Electric Plant Leased to Others 213 None
17 Electric Plant Held for Future Use 214 None
18 Construction Work in Progress-Electric 216
19 Accumulated Provision for Depreciation of Electric Utility Plant 219
20 investment of Subsidiary Companies 224-225
21 Materials and Supplies 227
22 Allowances 228-229 None
23 Extraordinary Property Losses 230 None
24 Unrecovered Plant and Regulatory Study Costs 230 None
25 Other Regulatory Assets 232
26 Miscellaneous Deferred Debits 233
27 Accumulated Deferred Income Taxes 234
28 Capital Stock 250-251
29 Other Paid-in Capital 253 None
30 Capital Stock Expense 254
31 Long-Term Debit 256-257
32 Reconciliation of Reported Net income with Taxable Inc for Fed Inc Tax 261
33 Taxes Accrued,Prepaid and Charged During the Year 262-263
34 Accumulated Deferred Investment Tax Credits 266-267
35 Other Deferred Credits 269
36 Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273 None
FERC FORM NO.1 (ED.12-96)Page 2
Name of Respondent This Report Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)Dec.31,2002AvistaCorp(2)A Resubmission 04/30/2003
Ll3T OF SCHEDULES (Electric Utility)(continued)
Enter in column (c)the terms "none,""not applicable,"or "NA,"as appropriate,where no information or amounts have been reported forcertainpages.Omit pages where the respondents are "none,""not applicable,"or "NA".
Line Title of Schedule Reference RemarksNo.Page No.
(a)(b)(c)
37 Accumulated Deferred Income Taxes-Other Property 274-275
38 Accumulated Deferred Income Taxes-Other 276-277
39 Other Regulatory Liabilities 278
40 Electric Operating Revenues 300-301
41 Sales of Electricityby Rate Schedules 304
42 Sales for Resale 310-311
43 Electric Operation and Maintenance Expenses 320-323
44 Purchased Power 326-327
45 Transmission of Electricityfor Others 328-330
46 Transmission of Electricity by Others 332
47 Miscellaneous General Expenses-Electric 335
48 Depreciation and Amortization of Electric Plant 336-337
49 Regulatory Commission Expenses 350-351
50 Research,Developmentand Demonstration Activities 352-353 None
51 Distribution of Salaries and Wages 354-355
52 Common Utility Plantand Expenses 356
53 Electric Energy Account 401
54 Monthly Peaks and Output 401
55 Steam Electric Generating Plant Statistics (Large Plants)402-403
56 Hydroelectric Generating Plant Statistics (Large Plants)406-407
57 Pumped Storage Generating Plant Statistics (Large Plants)408-409 None
58 Generating PlantStatistics (Small Plants)410-411
59 Transmission Line Statistics 422-423
60 Transmission Lines Added During Year 424-425
61 Substations 426-427
'"Footnote Data 450
Stockholders'Reports Check appropriate box:
Four copies will be submitted
O No annual report to stockholders is prepared
RC FORM NO.1 (ED.12-96)Page 3
\
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)
(2)A Resubmission 04/30/2003 Dec.31,2002
GENERAL INFORMATION
1.Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept,and address of office where any other corporate books of account
are kept,if different from that where the general corporate books are kept.
M.K.Malquist,Senior Vice President and Chief Financial Officer
1411 E.Mission Avenue
spokane,WA 99202
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
3.If at any time during the year the property of respondent was held by a receiver or trustee,give (a)name of
receiver or trustee,(b)date such receiver or trustee took possession,(c)the authority by which the receivership or
trusteeship was created,and (d)date when possession by receiver or trustee ceased.
Not Applicable
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,Oregon,and California
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...Enter the date when such independent accountant was initially engaged:
(2)No
FERC FORM No.1 (ED.12-87)PAGE 101
Name of Respondent This Report is:Date of Report Year of Report(1)Q An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp(2)A Resubmission 04/30/2003
CORPORATIONS CONTROLLED BY R SPONDENT
1.Report below the names of all corporations,business trusts,and similar organizations,controlled directly or indirectly by respondentatanytimeduringtheyear.If control ceased prior to end of year,give particulars (details)in a footnote.|2.If control was by other means than a direct holding of voting rights,state in a footnote the manner in which control was held,naminganyintermediariesinvolved.
3.If control was held jointly with one or more other interests,state the fact in a footnote and name the other interests.
Definitions
1.See the Uniform System of Accounts for a definition of control.
2.Direct control is that which is exercised without interposition of an intermediary.
3.Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.4.Joint control is that in which neither interest can effectivelycontrol or direct action without the consent of the other,as where thevotingcontrolisequallydividedbetweentwoholders,or each party holds a veto power over the other.Joint control may exist bymutualagreementorunderstandingbetweentwoormorepartieswhotogetherhavecontrolwithinthemeaningofthedefinitionoficontrolintheUniformSystemofAccounts,regardless of the relative voting rights of each party.
Line Name of Company Controlled Kind of Business Percent Voting FootnoteNo.Stock Owned Ref.(a)(b)(c)(d)
1 Avista Capital Parent company to all of the
2 Company's subsidiaries.100
3
4 Avista Advantage,Inc.Provides various energy 100
5 services,such as Internet-
6 based specialty billing and
7 information services.
8
9 Avista Communications,Inc.An Integrated Communications 100 Currently inactive
I10Provider(ICP)that provided
11 local telecommunications
12 solutions and designed,built
13 and managed metropolitan
14 area fiber optic networks.
15
16 Avista Development,Inc.Nonoperating company which 100
17 maintains a small investment
"portfolio of real estate and
19 other investments.
20
21 Avista Energy,Inc.Wholesale electricity and 99.82
22 natural gas trading and
23 marketing.
24
25 Avista Laboratories,Inc.Develops proton exchange 100
26 membrane (PEM)fuel cell
27 technology and fuel cell
RC FORMNO.1 (ED.12-96)Page 103
Name of Respondent This Re ort Is:Date of Report Year of Report
(1)An Original (Mo,Da,Yr)2002AvistaCorpDec.31,(2)A Resubmission 04/30/2003
CORPORATIONS CONTROLLED BY RESPONDENT
1.Report below the names of all corporations,business trusts,and similar organizations,controlled directly or indirectly by respondent
at any time during the year.If control ceased prior to end of year,give particulars (details)in a footnote.
2.If control was by other means than a direct holding of voting rights,state in a footnote the manner in which control was held,naming
any intermediaries involved.
3.If control was held jointly with one or more other interests,state the fact in a footnote and name the other interests.
Definitions
1.See the Uniform System of Accounts for a definition of control.
2.Direct control is that which is exercised without interposition of an intermediary.
3.Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4.Joint control is that in which neither interest can effectively control or direct action without the consent of the other,as where the
voting control is equally divided between two holders,or each party holds a veto power over the other.Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts,regardless of the relative voting rights of each party.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
1 components.
2
3 Avista Power,LLC.Owns electric 100
4 generation assets.
5
6 Avista Services,Inc.Offers products/services to 100 Currently Inactive
7 utility customers.
8
9 Avista Turbine Power,Inc.Receives assignments of 100
10 purchase power agreements.
11
12 Avista Rathdrum,LLC Owns electric 100
13 generation assets.
14
15 Avista Ventures,Inc.Invests in emerging business 100
16 opportunities.
17
18 Pentzer Corporation Within Avista Capital;100
19 parent company of Advanced
20 Manufacturing and
21 Development.
22
23 Advanced Manufacturing and Development,Inc.Manufacturer of electronic 93
24 and mechanical equipment
25 for the computer and
26 instrumentation industries
27 and fabricates video arcade
FERC FORM NO.1 (ED.12-96)Page 103.1
Name of Respondent This Report Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp(2)A Resubrnission 04/30/2003 '
CORPORATIONS CONTROLLED BY RESPONDENT
1.Report below the names of all corporations,business trusts,and similar organizations,controlled directly or indirectly by respondentatanytimeduringtheyear.If control ceased prior to end of year,give particulars (details)in a footnote.2.If control was by other means than a direct holding of voting rights,state in a footnote the manner in which control was held,naminganyintermediariesinvolved.
3.If control was held jointly with one or more other interests,state the fact in a footnote and name the other interests.
Definitions
1.See the Uniform System of Accounts for a definition of control.
2.Direct control is that which is exercised without interposition of an intermediary.
3.Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.4.Joint control is that in which neither interest can effectively control or direct action without the consent of the other,as where thevotingcontrolisequallydividedbetweentwoholders,or each party holds a veto power over the other.Joint control may exist bymutualagreementorunderstandingbetweentwoormorepartieswhotogetherhavecontrolwithinthemeaningofthedefinitionofcontrolintheUniformSystemofAccounts,regardless of the relative voting rights of each party.
Line Name of Company Controlled Kind of Business Percent Voting FootnoteNo.Stock Owned Ref.(a)(b)(c)(d)
1 games.
2
3 Avista Receivables Corporation Acquires and sells accounts 100
4 receivable of Avista Corp.
5
6 INDIRECT CONTROL:
7 Rathdrum Power,LLC Develops and owns electric 49
8 generation assets.
9
10 Coyote Springs 2,LLC Develops and owns electric 50
11 generation assets.
12
13 H2 Fuel,LLC Subsidiary of Avista Labs.70
14 Develop and commercialize
15 technologies for
16 manufacturing hydrogen and
17 hydrocarbon fuels.
18
19 Spokane Energy,LLC Marketing of Energy 100
20
21
22
23
24
25
26
27
BC FORM NO.1 (ED.12-96)Page 103.2
Name of Respondent This Re ort Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)2002AvistaCorpDec.31,(2)A Resubmission 04/30/2003
OFFICERS
1.Report below the name,title and salary for each executive officer whose salary is $50,000 or more.An "executive officer"of a
respondent includes its president,secretary,treasurer,and vice president in charge of a principal business unit,division or function
(such as sales,administration or finance),and any other person who performs similar policy making functions.
2.If a change was made during the year in the incumbent of any position,show name and total remuneration of the previous
incumbent,and the date the change in incumbency was made.
Line Title 'Name of Òfficer Salary
for YearNo(a)(b)(c)
1 Chairman of the Board,President,and
2 Chief Executive Officer G.G.Ely 497,115
3
4 Senior Vice President and Chief Financial Officer M.K.Malquist 51,827
5 (effective 11/15/02)
6
7 Senior Vice President and General Counsel D.J.Meyer 249,415
8
9 Senior Vice President (title change effective 11/15/02)J.E.Eliassen 251,494
10
11 Senior Vice President S.L.Morris 216,523
12
13 Vice President and Treasurer R.R.Peterson 153,219
14
15 Vice President and Corporate Secretary T.L.Syms 140,381
16
17 Vice President R.D.Woodworth 167,288
18
19 Vice President and Controller C.M.Burmeister -Smith 169,394
20
21 Vice President D.A.Brukardt 166,231
22
23 Vice President K.O.Norwood 150,688
24
25 Vice Pres¡dent K.S.Feltes 154,252
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (ED.12-96)Page 104
Name of Respondent This Re ort Is:Date of Report Year of Report
(1)An Original (Mo,Da,Yr)2002AvistaCorp.Dec.31,(2)A Resubmission 04/30/2003
DIRECTORS
1.Report below the information called for concerning each director of the respondent who held office at any time during the year.Include in column (a),abbreviated
titles of the directors who are officers of the respondent.
2.Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
LIAè Name (and Title)of Director Principal Business Address
No-(a)(b)
1 David A.Clack***325 E.Sprague Avenue,Spokane WA 99202
2
3 Eugene W.Meyer (completed term 05/02)3 Plumbridge Lane,Hilton Head Island,SC 29928
4
5 R.John Taylor***111 Main Street,Lewiston ID 83501
6
7 Sarah M.R.(Sally)Jewell 6750 S.228th Street,Kent WA 98032
8
9 John F.Kelly 19300 Pacific Highway South,Seattle WA 98188
10
11 Bobby Schmidt (resigned 05/02)5 Trails End,Hilton Head Island,SC 29926
12
13 Daniel J.Zaloudek (completed term 05/02)8405 S.Canton,Tulsa OK 74137
14
15 Jessie J.Knight,Jr.Emerald Plaza,402 W.Broadway,Suite 1000,San Diego,CA
16 92101
17
18 Erik J.Anderson 801 Second Ave 13th Floor,Seattle WA 98104
19
20 Kristianne Blake***P.O.Box 28338,Spokane WA 99228
21
22 Gary G.Ely**1411 E.Mission Ave,Spokane,WA 99202
23 (Chairman,President,&CEO)
24
25 Roy Lewis Eiguren P.O.Box 2720,Boise,ID 83701
26
27
'28
29
I 30
31
32
33
,34
35
36
37
38
39
40
41
42
43
'44
45
46
47
48
I
FERC FORM NO.1 (ED.12-95)Page 105
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)g An Original Dec.31,2002
(2)A Resubmission 04/30/2003
IM 'ORTANT CHANGES DURING THE YEAR
Give particulars (details)concerning the matters indicated below.Make the statements explicit and precise,and number them in
accordance with the inquiries.Each inquiry should be answered.Enter "none,""not applicable,"or "NA"where applicable.If
information which answers an inquiry is given elsewhere in the report,make a reference to the schedule in which it appears.
1.Changes in and important additions to franchise rights:Describe the actual consideration given therefore and state from whom the
franchise rights were acquired.If acquired without the payment of consideration,state that fact.
2.Acquisition of ownership in other companies by reorganization,merger,or consolidation with other companies:Give names of
companies involved,particulars concerning the transactions,name of the Commission authorizing the transaction,and reference to
Commission authorization.
3.Purchase or sale of an operating unit or system:Give a brief description of the property,and of the transactions relating thereto,
and reference to Commission authorization,if any was required.Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4.Important leaseholds (other than leaseholds for natural gas lands)that have been acquired or given,assigned or surrendered:Giveeffectivedates,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 Page 106,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 i to 11 above,such notes may be included on this page.
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED.12-96)Page 108
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
IMPORTANTCHANGES DURING THE YEAR (Continued)
1.None
2.None
3.None
4.None
5.None
6.Reference is made to Notes 3,13,14,and 15 of Notes to Financial Statements,Page 122 of this report.
7.None
8.Average annual wage increases were 3.86%in 2002 for non-exempt personnel.Annual average wage increases were 4.26%
for exempt employees.Bargaining unit employees were granted increases ranging from 3.0%to 4.0%.
9.Reference is made to Note 24 of Notes to Financial Statements,Page 122 of this report.
10.None
11.N/A
12.See Page 122 of this report.
FERC FORM NO.1 (ED.12-96)Page 109
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)
(2)[¯]A Resubmission 04/30/2003 Dec.31,2002
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Ref.Balance at Balance atLineTitleofAccountPageNo.Beginning of Year End of YearNo.(a)(b)(c)(d)
1 UTILITY PLANT
2 Utility Plant (101-106,114)200-201 2,277,779,491 2,370,810,931
3 Construction Work in Progress (107)200-201 54,964,082 17,581,119
4 TOTAL Utility Plant (Enter Total of lines 2 and 3)2,332,743,573 2,388,392,050
5 (Less)Accum.Prov.for Depr.Amort.Depl.(108,111,115)200-201 767,101,656 824,688,269
6 Net Utility Plant (Enter Total of line 4 less 5)1,565,641,917 1,563,703,781
7 Nuclear Fuel (120.1-120.4,120.6)202-203 0 0
8 (Less)Accum.Prov.for Amort.of Nucl.Fuel Assemblies (120.5)202-203 0 0
9 Net Nuclear Fuel (Enter Total of line 7 less 8)0 0
10 Net Utility Plant (Enter Total of lines 6 and 9)1,565,641,917 1,563,703,781
11 Utility Plant Adjustments (116)122 0 0
12 Gas Stored Underground -Noncurrent (117)O 0
13 OTHER PROPERTY AND INVESTMENTS
14 Nonutility Property (121)221 3,741,058 3,156,010
15 (Less)Accum.Prov.for Depr.and Amort.(122)224,549 107,826
16 Investments in Associated Companies (123)0 0
17 Investment in Subsidiary Companies (123.1)224-225 350,746,583 256,737,740
18 (For Cost of Account 123.1,See Footnote Page 224,line 42)
19 Noncurrent Portion of Allowances 228-229 0 0
20 Other Investments (124)50,536,283 46,498,833
21 Special Funds (125-128)12,076,598 11,182,354
22 TOTAL Other Property and Investments (Total of lines 14-17,19-21)416,875,973 317 467,111
23 CURRENT AND ACCRUED ASSETS
24 Cash (131)-513,763 10,048,633
25 Special Deposits (132-134)2,890,636 2,465,146
26 Working Fund (135)423,725 384,217
27 Temporary Cash Investments (136)7,648,782 24,126,777
28 Notes Receivable (141)O 0
29 Customer Accounts Receivable (142)49,675,97 28,898,856
30 Other Accounts Receivable (143)5,295,153 4,238,495
31 (Less)Accum.Prov.for Uncollectible Acct.-Credit (144)2,949,912 2,688,665
32 Notes Receivable from Associated Companies (145)182,111,918 137,275,825
33 Accounts Receivable from Assoc.Companies (146)-2,022,783 740,428
34 Fuel Stock (151)227 3,395,773 3,261,065
35 Fuel Stock Expenses Undistributed (152)227 0 0
36 Residuals (Elec)and Extracted Products (153)227 0 0
37 PlantMaterials and Operating Supplies (154)227 9,015,27 8,449,512
38 Merchandise (155)227 0 0
39 Other Materials and Supplies (156)227 0 0
40 Nuclear Materials Held for Sale (157)202-203/227 0 0
41 Allowances (158.1 and 158.2)228-229 0 0
42 (Less)Noncurrent Portion of Allowances O O
43 Stores Expense Undistributed (163)227 578,289 494,542
44 Gas Stored Underground -Current (164.1)6,168,382 7,563,672
45 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)631,780 563,856
46 Prepayments (165)2,185,343 2,916,606
47 Advances for Gas (166-167)0 0
48 Interest and Dividends Receivable (171)250,267 27,487
49 Rents Receivable (172)737,960 676,514
50 Accrued Utility Revenues (173)0 0
51 Miscellaneous Current and Accrued Assets (174)1,018,091 322,206
52 Derivative Instrument Assets (175)0 0
FERC FORM NO.1 (ED.12-94)Page 110
Name of Respondent This Report Is:Date of Report Year of ReportAvistaCorp.(1)An Original (Mo,Da,Yr)
(2)A Resubmission 04/30/2003 Dec.31,2002
COMPARATIVE BALANCE SHEET (ASSETSAND OTHER DEBITS)continue1)
Ref.Balance at Balance atLineTitleofAccountNo.(a)Page No.Beginning of Year End of Year
(b)(c)(d)53 Derivative Instrument Assets -Hedges (176)O 60,322,23854TOTALCurrentandAccruedAssets(Enter Total of lines 24 thru 53)266,540,888 290,087,41055DEFERREDDEBITSWijÌ56UnamortizedDebtExpenses(181)26,075,057 21,921,64057ExtraordinaryPropertyLosses(182.1)230 0 058UnrecoveredPlantandRegulatoryStudyCosts(182.2)230 0 059OtherRegulatoryAssets(182.3)232 445,035,675 248,746,93160Prelim.Survey and Investigation Charges (Electric)(183)7,973,065 12,130,41861Prelim.Sur.and Invest.Charges (Gas)(183.1,183.2)0 062ClearingAccounts(184)-2,081,155 1,416,42363TemporaryFacilities(185)0 064MiscellaneousDeferredDebits(186)233 109,424,216 81,406,92165Def.Losses from Disposition of Utility Pit.(187)
O O66Research,Devel.and Demonstration Expend.(188)352-353 0 067UnamortizedLossonReaquiredDebt(189)15,147,127 29,206,73068AccumulatedDeferredIncomeTaxes(190)234 27,044,942 37,595,30469UnrecoveredPurchasedGasCosts(191)52,679,575 11,514,48670TOTALDeferredDebits(Enter Total of lines 56 thru 69)681,298,502 443,938,85371TOTALAssetsandOtherDebits(Enter Total of lines 10,11,12,22,54,70)2,930,357,280 2,615,197,155
FERC FORM NO.1 (ED.12-94)Page 111
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)
(2)A Resubmission 04/30/2003 Dec.31,2002
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
I Ref.Balance at Balance atLineTitleofAccount
No.(a)Page No.Beginning of Year End of Year
(b)(c)(d)
1 PROPRIETARY CAPITAL ؾif
2 Common Stock Issued (201)250-251 617,737,210 623,091,721
3 Preferred Stock Issued (204)250-251 35,000,000 33,250,000
4 Capital Stock Subscribed (202,205)252 0 0
5 Stock Liability for Conversion (203,206)252 0 0
6 Premium on Capital Stock (207)252 0 0
7 Other Paid-In Capital (208-211)253 0 0
8 Installments Received on Capital Stock (212)252 0 0
9 (Less)Discount on Capital Stock (213)254 0 0
10 (Less)Capital Stock Expense (214)254 11,924,026 11,927,830
11 Retained Earnings (215,215.1,216)118-119 -106,447,403 60,386,146
12 Unappropriated Undistributed Subsidiary Earnings (216.1)118-119 226,474,938 65,750,804
13 (Less)Reaguired Capital Stock (217)250-251 0 0
14 Accumulated Other Comprehensive Income (219)122(a)(b)0 -18,809,177
15 TOTAL Proprietary Capital (Enter Total of lines 2 thru 13)760,840,719 751,741,664
16 LONG-TERM DEBT
17 Bonds (221)256-257 401,300,000 401,300,000
18 (Less)Reaquired Bonds (222)256-257 0 0
19 Advances from Associated Companies (223)256-257 O O
20 Other Long-Term Debt (224)256-257 931,000,000 703,778,874
21 Unamortized Premium on Long-Term Debt (225)O O
22 (Less)Unamortized Discount on Long-Term Debt-Debit (226)2,546,888 2,160,866
23 TOTAL Long-Term Debt (Enter Total of lines 16 thru 21)1,329,753,112 1,102,918,008
24 OTHER NONCURRENT LIABILITIES
25 Obligations Under Capital Leases -Noncurrent (227)O 621,526
26 Accumulated Provision for Property Insurance (228.1)O O
27 Accumulated Provision for injuries and Damages (228.2)1,476,494 1,446,348
28 Accumulated Provision for Pensions and Benefits (228.3)18,184,215 50,209,349
29 Accumulated Miscellaneous Operating Provisions (228.4)O 0
30 Accumulated Provision for Rate Refunds (229)0 0
31 TOTAL OTHER Noncurrent Liabilities (Enter Total of lines 24 thru 29)19,660,709 52,277,223
32 CURRENT AND ACCRUED LIABILITIES vt =
33 Notes Payable (231)O O
34 Accounts Payable (232)52,930,348 36.247,518
35 Notes Payable to Associated Companies (233)0 0
36 Accounts Payable to Associated Companies (234)20,512,592 18,524,753
37 Customer Deposits (235)3,820,410 4,533,815
38 Taxes Accrued (236)262-263 -20,229,945 22,522,183
39 Interest Accrued (237)18,583,369 20,307,075
40 Dividends Declared (238)99,026 0
41 Matured Long-Term Debt (239)0 0
42 Matured Interest (240)O O
43 Tax Collections Payable (241)374,374 -754
44 Miscellaneous Current and Accrued Liabilities (242)515,408 20,279,696
45 Obligations Under Capital Leases-Current (243)0 0
FERC FORM NO.1 (ED.12-89)Page 112
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)
(2)A Resubmission 04/30/2003 Dec.31,2002
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITSXContinued)
Ref.Balance at Balance atLineTitleofAccountPageNo.Beginningof Year End of YearNo.(a)(b)(c)(d)
46 Derivative Instrument Liabilities (244)O O47DerivativeInstrumentLiabilities-Hedges (245)0 50,057,63348TOTALCurrent&Accrued Liabilities (Enter Total of lines 32 thru 44)76,605,582 172,471,91949DEFERREDCREDITSNRA50CustomerAdvancesforConstruction(252)981,208 913,115
51 Accumulated Deferred investment Tax Credits (255)266-267 718,884 669,57652DeferredGainsfromDispositionofUtilityPlant(256)O O53OtherDeferredCredits(253)269 230,560,198 29,705,40654OtherRegulatoryLiabilities(254)278 11,931,064 20,174,50255UnamortizedGainonReaquiredDebt(257)1,728,475 4,118,795
56 Accumulated Deferred Income Taxes (281-283)272-277 497,577,329 480,206,94757TOTALDeferredCredits(Enter Total of lines 47 thru 53)743,497,158 535,788,341580059006000
61 0 062006300640065006600670068006900700071TOTALLiabandOtherCredits(Enter Total of lines 14,22,30,45,54)2,930,357,280 2,615,197,155
FERC FORM NO.1 (ED.12-89)Page 113
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
STATEMENT OF INCOME FORTHE YEAR
1.Report amounts for accounts 412 and 413,Revenue and Expenses from Utility Plant Leased to Others,in another Utility column (i,
k,m,o)in a similar manner to a utility department.Spread the amount(s)over Lines 02 thru 24 as appropriate.Include these amounts
in columns (c)and (d)totals.
2.Report amounts in account 414,Other Utility Operating income,in the same manner as accounts 412 and 413 above.
3.Report data for lines 7,9,and 10 for Natural Gas companies using accounts 404.1,404.2,404.3,407.1 and 407.2.
4.Use pages 122-123 for important notes regarding the statement of income or any account thereof.
5.Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount
may need to be made to the utility's customers or which may result in a material refund to the utility with respect to power or gas
purchases.State for each year affected the gross revenues or costs to which the contingency relates and the tax effects together with
an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to
power and gas purchases.
6.Give concise explanations concerning significant amounts of any refunds made or received during the year
Line Account (Ref.)TOTAL
No Page No.Current Year Previous Year
(a)(b)(c)(d)
1 UTILITY OPERATING INCOME Ѿggggg
2 Operating Revenues (400)300-301 893,963,515 1 230 847 199
3 Operating Expenses 0&¾
4 Operation Expenses (401)320-323 606,132,796 994,242,604
5 Maintenance Expenses (402)320-323 23,968,182 26,266,457
6 Depreciation Expense (403)336-337 60,293,549 58,204,870
7 Amort.&Depl.of Utility Plant (404-405)336-337 8,430,074 6,845,019
8 Amort.of Utility Plant Acq.Adj.(406)336-337 99,048 99,048
9 Amort.Property Losses,Unrecov Plant and Regulatory Study Costs (407)-3,582 -4,095
10 Amon.of Conversion Expenses (407)
11 Regulatory Debits (407.3)253,985 228,676
12 (Less)Regulatory Credits (407.4)17,987,205 23,255,978
13 Taxes Other Than Income Taxes (408.1)262-263 63,597,147 53,294,525
14 income Taxes -Federal (409.1)262-263 34,872,176 -92,830,192
15 -Other (409.1)262-263 2,348,133 -5,747,504
16 Provision for Deferred income Taxes (410.1)234,272-277 -7,069,837 108,321,574
17 (Less)Provision for Deferred Income Taxes-Cr.(411.1)234,272-277 5,080,399 5,441,839
18 Investment Tax Credit Adj.-Net (411.4)266 -49,308 -49,308
19 (Less)Gains from Disp.of Utility Plant (411.6)
20 Losses from Disp.of Utility Plant (411.7)
21 (Less)Gains from Disposition of Allowances (411.8)
22 Losses from Disposition of Allowances (411.9)
23 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 22)769,804,759 1,120,173,857
24 Net Util Oper Inc (Enter Tot line 2 less 23)Carry fwd to P117,line 25 124,158,756 110,673,342
FERC FORM NO.1 (ED.12-96)Page 114
Name of Respondent This Re ort Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
STATEMENT OF INCOME FORTHE YEAR (Continued)
resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases,and asummaryoftheadjustmentsmadetobalancesheet,income,and expense accounts.
7.If any notes appearing in the report to stockholders are applicable to this Statement of Income,such notes may be included onpages122-123.
B.Enter on pages 122-123 a concise explanation of only those changes in accounting methods made during the year which had aneffectonnetincome,including the basis of allocations and apportionments from those used in the preceding year.Also give theapproximatedollareffectofsuchchanges.
9.Explain in a footnote if the previous year's figures are different from that reported in prior reports.
10.If the columns are insufficient for reporting additional utility departments,supply the appropriate account titles,lines 2 to 23,andreporttheinformationintheblankspaceonpages.122-123 or in a footnote.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY Line
NnCurrentYearPreviousYearCurrentYearPreviousYearCurrentYearPreviousYear(e)(f)(g)(h)(i)(j)
584,141,003 922,204,500 309,822,512 308,642,699 2
353,588,329 747,476,434 252,544,467 246,766,170 4
19,988,552 22,619,436 3,979,630 3,647,021 5
46,180,880 44,592,733 14,112,669 13,612,137 6
7,497,026 6,036,769 933,048 808,250 7
99,048 99,048 8
-3,582 -4,095 9
10
253,985 228,676 11
17,987,205 23,255,978 12
43,185,433 34,313,701 20,411,714 18,980,824 13
25,158,719 -92,594,583 9,713,457 -235,609 14
1,430,132 -3,984,607 918,001 -1,762,897 15
2,201,171 101,367,176 -9,271,008 6,954,398 16
4,997,556 5,137,185 82,843 304,654 17
-49,308 -49,308 18
19
20
21
22
476,340,947 831,528,849 293,463,812 288,645,008 23
107,800,056 90,675,651 16,358,700 19,997,691 24
FERC FORM NO.1 (ED.12-96)Page 115
Name of Respondent This Re ort Is:Date of Report Year of Report
(1)An Original (Mo,Da,Yr)Avista Corp.Dec.31 2002(2)A Resubmission 04/30/2003 '
STATEMENT OF INCOME FORTHE YEAR (Continued)
Line OTHER UTILITY OTHER UTILITY OTHER UTILITY
Current Year Previous Year Current Year Previous Year Current Year Previous Year
(k)(l)(m)|(n)(o)(p)
4
5
6
7
8
9
10
11
12
13
I14
15
16
17
18
19
20
21
22
23
24
FERC FORM NO.1 (ED.12-96)Page 116
Name of Respondent This Report Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)Avista Corp.(2)A Resubmission 04/30/2003 Dec.31,2002
JTATEMENT OF INCOME FOR THi!YEAR (Continued)
Line Account (Ref.)TOTALNo-Page No.Current Year Previous Year(a)(b)(c)(d)
25 Net Utility Operating Income (Carried forward from page 114)124,158,756 110,673,342
26 Other Income and Deductions
27 Other Income
28 Nonutilty Operating Income
29 Revenues From Merchandising,Jobbing and Contract Work (415)574,461 138,517
30 (Less)Costs and Exp.of Merchandising,Job.&Contract Work (416)705,555 127,752
31 Revenues From Nonutility Operations (417)361,455 378,855
32 (Less)Expenses of Nonutility Operations (417.1)1,914,750 2,131,887
33 Nonoperating Rental income (418)-3,022 -23,907
34 Equity in Earnings of Subsidiary Companies (418.1)119 -4,212,474 -11,090,218
35 Interest and Dividend Income (419)23,649,106 34,250,252
36 Allowance for Other Funds Used During Construction (419.1)768,323 1,073,225
37 Miscellaneous Nonoperating Income (421)1,922,152 -173,649
38 Gain on Disposition of Property (421.1)210,724 84,243
I 39 TOTAL Other Income (Enter Total of lines 29 thru 38)20,650,420 22,377,679
40 Other Income Deductions
41 Loss on Disposition of Property (421.2)68,722 23,458
42 Miscellaneous Amortization (425)340 1,323,416 1,323,907
43 Miscellaneous Income Deductions (426.1-426.5)340 2,537,596 2,983,159
44 TOTAL Other Income Deductions (Total of lines 41 thru 43)3,929,734 4,330,524
45 Taxes Applic.to Other Income and Deductions er
46 Taxes Other Than IncomeTaxes (408.2)262-263 38,000 7,458
47 Income Taxes-Federal (409.2)262-263 3,329,302 12,085,770
48 Income Taxes-Other (409.2)262-263 -464,555 -494,842
49 Provision for Deferred Inc.Taxes (410.2)234,272-277 3,845,351 4,292,806
50 (Less)Provision for Deferred Income Taxes-Cr.(411.2)234,272-277 -406,167 -40,693
51 investment Tax Credit Adj.-Net (411.5)
52 (Less)Investment Tax Credits (420)
53 TOTAL Taxes on Other Income and Deduct.(Total of 46 thru 52)7,154,265 15,931,885
54 Net Other Income and Deductions (Enter Total lines 39,44,53)9,566,421 2,115,270
55 Interest Charges
56 Interest on Long-Term Debt (427)93,113,627 96,517,793
57 Amort.of Debt Disc.and Expense (428)5,538,126 3,481,482
58 Amortization of Loss on Reaquired Debt (428.1)3,323,214 2,167,105
59 (Less)Amort.of Premium on Debt-Credit (429)
60 (Less)Amortization of Gain on Reaquired Debt-Credit (429.1)9,905
61 Interest on Debt to Assoc.Companies (430)340
62 Other Interest Expense (431)340 1,621,673 672,192
63 (Less)Allowance for Borrowed Funds Used During Construction-Cr.(432)1,178,216 2,195,821
64 Net Interest Charges (Enter Total of lines 56 thru 63)102,418,424 100,632,846
65 Income Before Extraordinary Items (Total of lines 25,54 and 64)31,306,753 12,155,766
66 Extraordinary Items
67 Extraordinary Income (434)
68 (Less)Extraordinary Deductions (435)
69 Net Extraordinary Items (Enter Total of line 67 less line 68)
70 Income Taxes-Federal and Other (409.3)262-263
71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70)
72 Net Income (Enter Total of lines 65 and 71)31,306,753 12,155,766
FERC FORM NO.1 (ED.12-96)Page 117
Name of Respondent This Re ort Is:Date of Report Year of Report
(1)An Original (Mo,Da,Yr)2002AvistaCorpDec.31,(2)A Resubmission 04/30/2003
STA EMENT OF RETAINED EARNINGS FOR THE YEAR
1.Report all changes in appropriated retained earnings,unappropriated retained earnings,and unappropriated undistributed
subsidiary earnings for the year.
2.Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433,436
-439 inclusive).Show the contra primary account affected in column (b)
3.State the purpose and amount of each reservation or appropriation of retained earnings.
4.List first account 439,Adjustments to Retained Earnings,reflecting adjustments to the opening balance of retained earnings.Follow
by credit,then debit items in that order.
5.Show dividends for each class and series of capital stock.
6.Show separately the State and Federal income tax effect of items shown in account 439,Adjustments to Retained Earnings.
7.Explain in a footnote the basis for determining the amount reserved or appropriated.If such reservation or appropriation is to be
recurrent,state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
8.If any notes appearing in the report to stockholders are applicable to this statement,include them on pages 122-123.
Line Contra Primary Amount
No.Item Account Affected(a)(b)(c)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Year 107 995,524
2 Changes
3 Adjustments to Retained Earnings (Account 439)
4 Of this amount,$65,852,544 represents prior year dividends from subsidiaries.66,471,070
5 This amount was previously reported as Unappropriated Undistributed
6 Subsidiary Earnings,Acct.216.10 and is now part of Unappropriated Retained
7 Earnings,Acct.216.00.
8
9 TOTAL Credits to Retained Earnings (Acct.439)66,471,070
10 Debits to Acct.439 -458,678
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acct.439)-458,678
16 Balance Transferred from Income (Account 433 less Account 418.1)35,519,227
17 Appropriations of Retained Earnings (Acct.436)
18
19
20
21
22 TOTAL Appropriations of Retained Earnings (Acct.436)
23 Dividends Declared-Preferred Stock (Account 437)
24 -2,402,094
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acct.437)-2,402,094
30 Dividends Declared-Common Stock (Account 438)ÃT
31 -22,955,092
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acct.438)-22,955,092
37 Transfers from Acct 216.1,Unapprop.Undistrib.Subsidiary Earnings 90,659,116
38 Balance -End of Year (Total 1,9,15,16,22,29,36,37)58,838,025
APPROPRIATED RETAINED EARNINGS (Account 215)
FERC FORM NO.1 (ED.12-96)Page 118
Name of Respondent This R ort Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)2002AvistaCorpDec.31,(2)A Resubmission 04/30/2003
STA EMENT OF RETAINED EARNINGS FOR THE YEAR
1.Report all changes in appropriated retained earnings,unappropriated retained earnings,and unappropriated undistributedsubsidiaryearningsfortheyear.
2.Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433,436
-439 inclusive).Show the contra primary account affected in column (b)
3.State the purpose and amount of each reservation or appropriation of retained earnings.
4.List first account 439,Adjustments to Retained Earnings,reflecting adjustments to the opening balance of retained earnings.Followbycredit,then debit items in that order.
5.Show dividends for each class and series of capital stock.
6.Show separately the State and Federal income tax effect of items shown in account 439,Adjustments to Retained Earnings.7.Explain in a footnote the basis for determining the amount reserved or appropriated.If such reservation or appropriation is to berecurrent,state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.8.If any notes appearing in the report to stockholders are applicable to this statement,include them on pages 122-123.
Line Ôontra Primary AmountNo.Item Account Affected(a)(b)(c)
39 1,548,121
40
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215)1,548,121
APPROP.RETAINED EARNINGS -AMORT.Reserve,Federal (Account 215.1)gig46TOTALApprop.Retained Earnings-Amort.Reserve,Federal (Acct.215.1)
47 TOTAL Approp.Retained Earnings (Acct.215,215.1)(Total 45,46)1,548,121
48 TOTAL Retained Earnings (Account 215,215.1,216)(Total 38,47)60,386,146
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account 216.1)g¿¾
49 Balance-Beginning of Year (Debit or Credit)226,474,938
50 Equity in Earnings for Year (Credit)(Account 418.1)-4,212,474
51 (Less)Dividends Received (Debit)89,796,369
52 Adjustments (Prior year dividends to Corp.and Sub Expense in Account 417.12)-66,715,291
53 Balance-End of Year (Total lines 49 thru 52)65,750,804
FERC FORM NO.1 (ED.12-96)Page 119
Name of Respondent This Re ort Is:Date of Report Year of Repon
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
STATEMENT OF CASH FLOWS
1.If the notes to the cash flow statement in the respondents annual stockholders report are applicable to this statement,such notes should be included
in page 122-123.Information about non-cash investing and financing activities should be provided on Page 122-123.Provide also on pages 122-123 a
reconciliation between "Cash and Cash Equivalents at End of Year"with related amounts on the balance sheet.
2.Under "Other"specify significant amounts and group others.
3.Operating Activities -Other:Include gains and losses pertaining to operating activities only.Gains and losses pertaining to investing and financing
activities should be reported in those activities.Show on Page 122-123 the amount of interest paid (net of amounts capitalized)and income taxes paid.
Line L)escription (See instruction No.5 tor Explanation of Codes)Amounts
No.(a)(b)
1 Net Cash Flow from Operating Activities:
2 Net income 31 306 753
3 Noncash Charges (Credits)to Income:ik
4 Depreciation and Depletion 60,293,548
5 Amortization -8,112,744
6
7
8 Deferred Income Taxes (Net)-7,898,717
9 Investment Tax Credit Adjustment (Net)-49,308
10 Net (Increase)Decrease in Receivables 18,152,007
11 Net (Increase)Decrease in Inventory -543,149
12 Net (Increase)Decrease in Allowances Inventory
13 Net increase (Decrease)in Payables and Accrued Expenses 43,968,375
14 Net (increase)Decrease in Other Regulatory Assets 167,944,943
15 Net Increase (Decrease)in Other Regulatory Liabilities 13,329,566
16 (Less)Allowance for Other Funds Used During Construction 1,814,175
17 (Less)Undistributed Earnings from Subsidiary Companies -4,212,474
18 Other (provide details in footnote):
19 Non-Monetary Power Transaction 747,354
20 Power and Gas Deferrals 99,222,518
21 Other Non-Currrent Assets/Liabilities -220,199,190
22 Net Cash Provided by (Used in)Operating Activities (Total 2 thru 21)200,560,255
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuel)-64,740,336
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant 398,337
30 (Less)Allowance for Other Funds Used During Construction -1,814,175
31 Other (provide details in footnote):
32 Other Property &Investments 917,323
33
34 Cash Outflows for Plant (Total of lines 26 thru 33)-61,610,501
35
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
38
39 Investments in and Advances to Assoc.and Subsidiary Companies 44,836,094
40 Contributions and Advances from Assoc.and Subsidiary Companies 89,796,369
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
FERC FORM NO.1 (ED.12-96)Page 120
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)g An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
STATEMENT OF CASH FLOWS
4.Investing Activities include at Other (line 31)net cash outflow to acquire other companies.Provide a reconciliation of assets acquired with liabilities
assumed on pages 122-123.Do not include on this statement the dollar amount of Leases capitalized per US of A General Instruction 20;instead
provide a reconciliation of the dollar amount of Leases capitalized with the plant cost on pages 122-123.
5.Codes used:
(a)Net proceeds or payments.(c)Include commercial paper.
(b)Bonds,debentures and other long-term debt.(d)Identify separately such items as investments,fixed assets,intangibles,etc.
6.Enter on pages 122-123 clarifications and explanations.
Line Description (See Instruction No.5 for Explanationof Öodes)Amounts
No.(a)(b)
46 Loans Made or Purchased
47 Collections on Loans
48
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):
54
55
56 Net Cash Provided by (Used in)Investing Activities
57 Total of lines 34 thru 55)73,021,962
58
59 Cash Flows from Financing Activities:
60 Proceeds from issuance of:
61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock 7,034,492
64 Other (provide details in footnote):
I65
66 Net increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68
69
70 Cash Provided by Outside Sources (Total 61 thru 69)7,034,492
71
72 Payments for Retirement of:
73 Long-term Debt (b)-201,835,104
74 Preferred Stock -1,750,000
75 Common Stock
76 Other (provide details in footnote):
77
78 Net Decrease in Short-Term Debt (c)-25,000,000
79
80 Dividends on Preferred Stock -2,402,094
81 Dividends on Common Stock -23,054,118
82 Net Cash Provided by (Used in)Financing Activities
83 (Total of lines 70 thru 81)-247,006,824
84
85 Net increase (Decrease)in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83)26.575,393
87
88 Cash and Cash Equivalents at Beginning of Year 10,449,380
89
90 Cash and Cash Equivalents at End of Year 37,024,773
FERC FORM NO.1 (ED.12-96)Page 121
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)g An Original 04/30/2003 Dec.31,2002
(2)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 Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4.Where Accounts 189,Unamortized Loss on Reacquired Debt,and 257,Unamortized Gain on Reacquired Debt,are not used,give
an explanation,providing the rate treatment given these items.See General Instruction 17 of the Uniform System of Accounts.
5.Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6.If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121,such notes may be included herein.
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED.12-96)Page 122
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
Avista Corporation(Avista Corp.or the Company)is an energy company engaged in the generation,transmission and distribution of
energy as well as other energy-related businesses.The utility portion of the Company,doing business as Avista Utilities,an operating
division of Avista Corp.and not a separate entity,represents the regulated utility operations.Avista Utilities provides electric and
natural gas distribution and transmission services in eastern Washington and northern Idaho.Avista Utilities also provides natural gas
distribution service in northeast and southwest Oregon and in the South Lake Tahoe region of California.Avista Capital,a wholly
owned subsidiary of Avista Corp.,is the parent company of all of the subsidiary companies engaged in the other non-utility lines of
business.
The Company's operations are exposed to risks including,but not limited to,the effects of legislative and governmental regulations,
the price and supply of purchased power,fuel and natural gas,recoverabilityof power and natural gas costs,streamflow and weather
conditions,availability of generation facilities,competition,technology and availability of funding.In addition,the energy business
exposes the Company to the financial,liquidity,credit and commodity price risks associated with wholesale purchases and sales.
Basis ofReporting
The consolidated financial statements include the assets,liabilities,revenues and expenses of the Company and its subsidiaries.The
accompanying financial statements include the Company's proportionate share of utility plant and related operations resulting from its
interests in jointlyowned plants (See Note 7).
Use of Estimates
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United
States of America requires management to make estimates and assumptions that affect amounts reported in the consolidated financial
statements.Changes in these estimates and assumptions are considered reasonably possible and may have a material impact on the
consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein.
System ofAccounts
The accounting records of the Company's utility operations are maintained in accordance with the uniform system of accounts
prescribed by the Federal Energy Regulatory Commission (FERC)and adopted by the appropriate state regulatory commissions.
Regulation
The Company is subject to state regulation in Washington,Idaho,Montana,Oregon and California.The Company is subject to
federal regulation by the FERC.
Business Segments
Financial information for each of the Company's lines of business is reported in the Schedule of Informationby Business Segments.
Such information is an integral part of these consolidated financial statements.The business segment presentation reflects the basis
currently used by the Company's management to analyze performance and determine the allocation of resources.Avista Utilities'
business is managed based on the total regulated utility operation.The Energy Trading and Marketing line of business operations
primarily include non-regulated electricity and natural gas marketing and trading activities including derivative commodity instruments
such as futures,options,swaps and other contractual arrangements.The Information and Technology line of business operations
includes utility internet billing services and fuel cell technology.The Other line of business includes other investments and operations
of various subsidiaries as well as the operations of Avista Capital on a parent company only basis.
Avista Utilities Operating Revenues
Operating revenues for Avista Utilities related to the sale of energy are generally recorded when service is rendered or energy is
delivered to customers.The determination of the energy sales to individual customers is based on the reading of their meters,which
occurs on a systematic basis throughout the month.At the end of each month,the amount of energy delivered to customers since the
FERC FORM NO.1 (ED.12-88)Page 123
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded.Accounts receivable
includes unbilled energy revenues of $6.1 million (net of $40.9 million of unbilled receivables sold)and $11.1 million (net of $46.6
million of unbilled receivables sold)as of December 31,2002 and 2001,respectively.See Note 3 for information with respect to the
sale of accounts receivable.
Research andDevelopmentExpenses
Company-sponsored research and development expenditures are expensed as incurred.The majority of the Company's research and
development expenses are related to the Informationand Technology line of business.Research and development expenses totaled
$3.8 million,$8.4 million and $8.1 million in 2002,2001 and 2000,respectively.
AdvertisingExpenses
The Company expenses advertising costs as incurred.Advertisingexpenses totaled $1.3 million,$1.8 million and $1.2 million in
2002,2001 and 2000,respectively.
Taxes other than income taxes
Taxes other than income taxes include state excise taxes,city occupational and franchise taxes,real and personal property taxes and
certain other taxes not based on net income.These taxes are generally based on revenues or the value of property.Utilityrelated taxes
collected from customers are recorded as both operating revenue and expense and totaled $33.1 million,$26.3 million and $23.5
million in 2002,2001 and 2000,respectively.
OtherIncome-Net
Other income-net consisted of the following items for the years ended December 31 (dollars in thousands):
2002 2001 2000
Interest income $7,716 $19,049 $10,351
Interest on power and natural gas deferrals 9,597 12,995 1,473
Impairment of non-operating assets -(8,240)
Net gain (loss)on the disposition of assets (33)2,884 21,048
Minority interest 242 217 694
Other expense (8,064)(10,839)(10,234)
Other income 8,009 4,615 2,529
Total $17,467 $20,681 $25,861
Income Taxes
The Company and its eligible subsidiaries file consolidated federal income tax returns.Subsidiaries are charged or credited with the
tax effects of their operations on a stand-alone basis.The Company's federal income tax returns were examined with all issues
resolved,and all payments made,through the 1998 return.
The Company accounts for income taxes using the liability method.Under the liability method,a deferred tax asset or liability is
determined based on the enacted tax rates that will be in effect when the differences between the financial statement carrying amounts
and tax basis of existing assets and liabilities are expected to be reported in the Company's consolidated income tax returns.The
deferred tax expense for the period is equal to the net change in the deferred tax asset and liability accounts from the beginning to the
end of the period.The effect on deferred taxes of a change in tax rates is recognized in income in the period that includes the
enactment date.
Stock-Based Compensation
The Company follows the disclosure only provisions of SFAS No.123,"Accounting for Stock-Based Compensation."Accordingly,
employee stock options are accounted for under Accounting Principle Board Opinion (APB)No.25,"Accounting for Stock Issued to
Employees."Stock options are granted at exercise prices not less than the fair value of common stock on the date of grant.Under
APB No.25,no compensation expense is recognized pursuant to the Company's stock option plans.
FERC FORM NO.1 (ED.12-88)Page 123.1
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
If compensation expense for the Company's stock option plans were determined consistent with SFAS No.123,net income and
earnings per common share would have been the following pro forma amounts for the years ended December 31:
2002 2001 2000
Net income (dollars in thousands):
As reported $31,307 $12,156 $91,679
Pro forma $28,256 $9,355 $89,850
Basic earnings per common share
As reported $0.60 $0.21 $1.49
Pro forma $0.54 $0.15 $1.45
Diluted earnings per common share
As reported $0.60 $0.20 $1.47
Pro forma $0.54 $0.15 $1.43
Comprehensive Income
The Company's comprehensive income is comprised of net income,foreign currency translation adjustments,unfunded accumulated
benefit obligation,unrealized gains and losses on interest rate swap agreements and unrealized gains and losses on investments
available-for-sale.
EarningsPer Common Share
Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of
common shares outstanding for the period.Diluted earnings per common share is calculated by dividingincome available for common
stock by diluted weighted average common shares outstanding during the period,including common stock equivalent shares
outstanding using the treasury stock method,unless such shares are anti-dilutive.Common stock equivalent shares include shares
issuable upon exercise of stock options and convertible stock.See Note 22 for earnings per common share calculations.
Cash and Cash Equivalents
For the purposes of the Consolidated Statements of Cash Flows,the Company considers all temporary investments with a purchased
maturity of three months or less to be cash equivalents.Cash and cash equivalents include cash deposits from counterparties.See
Note 6 for further information with respect to cash deposits from counterparties.
Temporary Investments
Temporary investments consist of marketable equity securities classified as "available for sale."The Company did not have any
temporary investments in marketable equity securities as of December 31,2002.The unrealized gain on temporary investments
totaled $1.4 million as of December 31,2001,net of taxes,and is reflected as a component of accumulated other comprehensive
income in the Consolidated Statements of Capitalization.
Allowance for DoubtfulAccounts
The Company maintains an allowance for doubtful accounts to sufficiently 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 following table documents the activity in the allowance for doubtful accounts during the years ended December 31 (dollars in
thousands):
2002 2001 2000
Allowance as of the beginning of the year $50,211 $14,404 $4,267
Additions expensed during the year 3,469 39,947 11,835
Net deductions (6,771)(4,140)(1,698)
Allowance as of the end of the year $46,909 $50,211 $14,404
FERC FORM NO.1 (ED.12-88)Page 123.2
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Inventory
Inventoryconsists primarily of materials and supplies,fuel stock and natural gas stored.Inventoryis recorded at the lower of cost or
market,primarilyusing the average cost method.
Utility Plant in Service
The cost of additions to utility plant in service,including an allowance for funds used during construction and replacements of units of
property and improvements,is capitalized.Costs of depreciable units of property retired plus costs of removal less salvage are charged
to accumulated depreciation.
Allowancefor Funds Used During Construction
The Allowance for Funds Used During Construction (AFUDC)represents the cost of both the debt and equity funds used to finance
utility plant additions during the construction period.In accordance with the uniform system of accounts prescribed by regulatory
authorities,AFUDC is capitalized as a part of the cost of utility plant and is credited currently as a non-cash item in the Consolidated
Statements of Income and Comprehensive Income in the line item capitalized interest.The Company generally is permitted,under
established regulatory rate practices,to recover the capitalized AFUDC,and a fair return thereon,through its inclusion in rate base and
the provisionfor depreciation after the related utility plant is placed in service.Cash inflow related to AFUDC does not occur until the
related utility plant is placed in service.
The effective AFUDC rate was 9.72 percent for the second half of 2002,9.03 percent for the first half of 2002 and 2001,and 10.67
percent in 2000.The Company's AFUDC rates do not exceed the maximum allowable rates as determined in accordance with the
requirements of regulatory authorities.
Depreciation
For utility operations,depreciation expense is estimated by a method of depreciation accounting utilizing unit rates for hydroelectric
plants and composite rates for other utility plant.Such rates are designed to providefor retirements of properties at the expiration of
their service lives.The rates for hydroelectric plants include annuity and interest components,in which the interest component is 9
percent.For utility operations,the ratio of depreciation provisions to average depreciable property was 2.92 percent in 2002,2.84
percent in 2001 and 2.72 percent in 2000.
The average service lives and remaining average service lives,respectively,for the following broad categories of utility property are:
electric thermal production -35 and 14 years;hydroelectric production -100 and 76 years;electric transmission -60 and 25 years;
electric distribution -40 and 28 years;and natural gas distribution property -44 and 27 years.
Goodwill
Goodwill arising from acquisitions represents the excess of the purchase price over the estimated fair value of net assets acquired.The
Company evaluates goodwill for impairment on at least an annual basis.Goodwill is included in non-utility properties and
investments-net in the Consolidated Balance Sheets and totaled $7.3 million and $13.7 million as of December 31,2002 and 2001,
respectively.The level of goodwill as of December 31,2002 and 2001 was supported by the value attributed to the operations
acquired.See Note 2 for changes in accounting for goodwilleffectiveJanuary 1,2002.
Regulatory DeferredCharges and Credits
The Company prepares its consolidated financial statements in accordance with the provisions of SFAS No.71,"Accounting for the
Effects of Certain Types of Regulation."The Company prepares its financial statements in accordance with SFAS No.71 because (i)
the Company's rates for regulated services are established by or subject to approval by an independent third-party regulator,(ii)the
regulated rates are designed to recover the Company's cost of providing the regulated services and (iii)in view of demand for the
regulated services and the level of competition,it is reasonable to assume that rates can be charged to and collected from customers at
levels that will recover the Company's costs.SFAS No.71 requires the Company to reflect the impact of regulatory decisions in its
financial statements.SFAS No.71 requires that certain costs and/or obligations (such as incurred power and natural gas costs not
currently recovered through rates,but expected to be recovered in the future)are reflected as deferred charges on the balance sheet.
These costs and/or obligations are not reflected in the statement of income until the period during which matching revenues are
recognized.If at some point in the future the Company determines that it no longer meets the criteria for continued application of
FERC FORM NO.1 (ED.12-88)Page 123.3
Name of Respondent This Report is:Date of Report Year of Report
(1)_X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
SFAS No.71 with respect to all or a portion of the Company's regulated operations,the Company could be required to write off its
regulatory assets.The Company could also be precluded from the future deferral of costs not recovered through rates at the time such
costs were incurred,even if such costs were expected to be recovered in the future.
The Company's primary regulatory assets include power and natural gas deferrals (see "Power Cost Deferrals"and "Natural Gas Cost
Deferrals"below for further information),investment in exchange power (see "Investment in Exchange Power-Net"below for further
information),regulatory assets for deferred income taxes (see Note 10 for further information),unamortized debt expense (see
"Unamortized Debt Expense"below for furtherinformation),regulatory asset offsetting energy commodity derivative liabilities (see
Note 4 for further information),demand side management programs,conservation programs and the provision for postretirement
benefits.Those items without a specific line on the Consolidated Balance Sheets are included in other regulatory assets.Other
regulatory assets consisted of the following as of December 31 (dollars in thousands):
2002 2001
Regulatory asset offsetting energy commodity derivative liabilities $-$157,529
Regulatory asset for postretirement benefit obligation 4,728 5,200
Demand side management and conservation programs 23,733 28,813
Other 1,274 1.218
Total $29.735 $192,760
Deferred credits include,among other items,regulatory liabilities created when the Centralia Power Plant (Centralia)was sold and the
gain on the general office building salelleaseback which is being amortized over the life of the lease,and are included on the
Consolidated Balance Sheets as other non-current liabilities and deferred credits.
Investmentin Exchange Power-Net
The investment in exchange power represents the Company's previous investment in Washington Public Power Supply System Project
3 (WNP-3),a nuclear project that was terminated prior to completion.Under a settlement agreement with the Bonneville Power
Administration in 1985,Avista Utilities began receiving power in 1987,for a 32.5-year period,related to its investment in WNP-3.
Through a settlement agreement with the Washington Utilities and Transportation Commission (WUTC)in the Washington
jurisdiction,Avista Utilities is amortizing the recoverable portion of its investment in WNP-3 (recorded as investment in exchange
power)over a 32.5 year period beginning in 1987.For the Idaho jurisdiction,Avista Utilities has fully amortized the recoverable
portion of its investment in exchange power.
Unamortized Debt Expense
Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt,as well as premiums paid to
repurchase debt,which are amortized over the average remaining maturity of outstanding debt in accordance with regulatory
accounting practices under SFAS No.71.
Natural Gas Benchmark Mechanism
The Idaho Public Utilities Commission (IPUC),WUTC and Oregon Public Utilities Commission (OPUC)approved Avista Utilities'
Natural Gas Benchmark Mechanism in 1999.The mechanism eliminated the majority of natural gas procurement operations within
Avista Utilities and consolidated gas procurement operations under Avista Energy,the Company's non-regulated subsidiary.The
ownership of the natural gas assets remains with Avista Utilities;however,the assets are managed by Avista Energy through an
Agency Agreement.Avista Utilities continues to manage natural gas procurement for its California operations,which currently
represents approximately four percent of its total natural gas therm sales.
The Natural Gas Benchmark Mechanism provides benefits to retail customers and allows Avista Energy to retain a portion of the
benefits associated with asset optimization and the efficiencies gained in purchasing natural gas for Avista Utilities.In the first quarter
of 2002,the IPUC and the OPUC approved the continuation of the Natural Gas Benchmark Mechanism and related Agency
Agreement through March 31,2005.In January 2003,the WUTC approved the continuation of the Natural Gas Benchmark
Mechanism and related Agency Agreement through January 29,2004.Hearings will be held before the WUTC during 2003 to
determine whether or not the Natural Gas Benchmark Mechanism and related Agency Agreement will be extended beyond January 29,
FERC FORM NO.1 (ED.12-88)Page 123.4
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
2004.
In accordance with SFAS No.71,profits recognized by Avista Energy on natural gas sales to Avista Utilities,including gains and
losses on natural gas contracts,are not eliminated in the consolidated financial statements.This is due to the fact that costs incurred
by Avista Utilities for natural gas purchases to serve retail customers and for fuel for electric generation are expected to be recovered
through future retail rates.
Avista Utilities'natural gas purchases from Avista Energy totaled $114.8 million,$249.8 million and $175.9 million in 2002,2001
and 2000,respectively.These costs are reflected as resource costs in the Consolidated Statements of Income and Comprehensive
Income.
Power Cost Deferrals
Avista Utilities defers the recognition in the income statement of certain power supply costs as approved by the WUTC.Deferred
power supply costs are recorded as a deferred charge on the balance sheet for future review and the opportunity for recovery through
retail rates.The power supply costs deferred include certain differences between actual power supply costs incurred by Avista Utilities
and the costs included in base retail rates.This difference in power supply costs primarily results from changes in short-term
wholesale market prices,changes in the level of hydroelectric generation and changes in the level of thermal generation (including
changes in fuel prices).Avista Utilities accrues interest on deferred power costs in the Washington jurisdiction at a rate,which is
adjusted semi-annually,of 8.9 percent as of December 31,2002.Total deferred power costs for Washington customers were $123.7
million and $140.2 million as of December 31,2002 and 2001,respectively.
In June 2002,the WUTC issued an order that became effectiveJuly 1,2002.The order provides for an overall rate of return of 9.72
percent and a return on equity of 11.16 percent.The order providedfor no incremental rate increase to Avista Utilities'Washington
electric customers above the rates in effect at that time.Rate increases previouslyapproved by the WUTC totaling 31.2 percent (a 25
percent temporary surcharge approved in September 2001 for the recovery of deferred power costs and a 6.2 percent increase
approved in March 2002)were restructured.The general increase to base retail rates was 19.3 percent (or $45.7 million in annual
revenues)and the remaining 11.9 percent represents the continued recovery of deferred power costs over a period currently projected
to continue into 2009.
In the June 2002 rate order,the WUTC approved the establishment of an Energy Recovery Mechanism (ERM).The ERM replaced a
series of temporary deferral mechanisms that were in place in Washington since mid-2000.The ERM allows Avista Utilities to
increase or decrease electric rates periodicallywith WUTC approval to reflect changes in power supply costs.The ERM provides for
Avista Utilities to incur the cost of,or receive the benefit from,the first $9 million in annual power supply costs above or below the
amount included in base retail rates.As the ERM was implemented on July 1,2002,the Company's expense or benefit was limited to
$4.5 million for 2002.Under the ERM,90 percent of annual power supply costs exceeding or below the initial $9 million ($4.5
million for 2002)will be deferred for future surcharge or rebate to Avista Utilities'customers.The remaining 10 percent will be an
expense of,or benefit to,the Company.
Avista Utilities has a power cost adjustment (PCA)mechanism in Idaho that allows it to modify electric rates periodically with IPUC
approval to recover or rebate a portion of the differencebetween actual and allowed net power supply costs.The PCA mechanism
allows for the deferral of 90 percent of the differencebetween actual net power supply expenses and the authorized level of net power
supply expenses approved in the last Idaho general rate case.Avista Utilities accrues interest on deferred power costs in the Idaho
jurisdiction at a rate,which is adjusted annually,of 2 percent as of December 31,2002.In October 2002,the IPUC issued an order
extending a 19.4 percent PCA surcharge for Idaho electric customers.The PCA surcharge will remain in effect until October 2003.
The IPUC directed Avista Utilities to file a status report 60 days before the PCA surcharge expires.If review of the status report and
the actual balance of deferred power costs support continuation of the PCA surcharge,the IPUC has indicated that it anticipates the
PCA surcharge will be extended for an additional period.Total deferred power costs for Idaho customers were $31.5 million and
$73.1 million as of December 31,2002 and 2001,respectively.
Natural Gas Cost Deferrals
Under established regulatory practices in each respective state,Avista Utilities is allowed to adjust its natural gas rates periodically
(with appropriate regulatory approval)to reflect increases or decreases in the cost of natural gas purchased.Differences between
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(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
actual natural gas costs and the natural gas costs allowed in rates are deferred and charged or credited to expense when regulators
approve inclusion of the cost changes in rates.Total deferred natural gas costs were $11.5 million and $52.7 million as of December
31,2002 and 2001,respectively.
DeferredRevenue
In December 1998,the Company received cash proceeds of $143.4 million from a transaction in which the Company assigned and
transferred certain rights under a long-term power sales contract to a fundingtrust.The proceeds were recorded as deferred revenue
and were being amortized into revenues over the 16-year period of the long-term sales contract.Pursuant to the WUTC order in
September 2001,the Company was directed to offset $53.8 million of the Washington share of the deferred revenue against deferred
power costs.The IPUC order in October 2001 directed the Company to amortize the remaining Idaho share ($34.6 million)of the
deferred revenue against deferred power costs over the 15-month period between October 2001 and December 2002.The balance was
fully amortized as of December 31,2002.
Reclassifications
Certain prior period amounts were reclassified to conform to current statement format.These reclassifications were made for
comparative purposes and to conform to changes in accounting standards and have not affected previously reported total net income or
common equity.
NOTE 2.NEW ACCOUNTING STANDARDS
In June 2001,the Financial Accounting Standards Board (FASB)issued SFAS No.142,"Goodwill and Other Intangible Assets"
which applies to acquired intangible assets whether acquired singly,as part of a group,or in a business combination.This statement
requires that goodwill not be amortized;however,goodwill for each reporting unit must be evaluated for impairment on at least an
annual basis using a two-step approach.The first step used to identify potential impairment compares the estimated fair value of a
reporting unit to its carrying amount,including goodwill.If the fair value of a reporting unit is less than its carrying amount,the
second step of the impairment evaluation,which compares the implied fair value of goodwill to its carrying amount,is performed to
determine the amount of the impairment loss,if any.This statement also provides standards for financial statement disclosures of
goodwilland other intangible assets and related impairment losses.The Company adopted this statement on January 1,2002.
In April 2002,the Company completed its transitional test of goodwill.Accordingly,the Company determined that goodwill related
to Advanced Manufacturing and Development,a subsidiary of Avista Ventures included in the Other business segment,was impaired.
This was due to a change in forecasted earnings based on the decline in the performance of the business.The fair value of the
reporting unit was determined using the present value of projected future cash flows.The Company recorded an impairment of $4.1
million,net of taxes,as a cumulative effect of accounting change in the Consolidated Statement of Income and Comprehensive
Income.
Goodwill amortization was $1.8 million,net of taxes,for 2001.Net income and basic and diluted earnings per common share would
have been $14.0 million,$0.24 and $0.24,respectively,excluding goodwill amortization for 2001.Goodwill amortization was $2.2
million,net of taxes,for 2000.Net income and basic and diluted earnings per common share would have been $93.9 million,$1.54
and $1.52,respectively,excluding goodwill amortization for 2000.
In June 2001,the FASB issued SFAS No.143,"Accounting for Asset Retirement Obligations"which addresses financial accounting
and reporting for obligations associated with the retirement of tangible long-livedassets and the associated asset retirement costs.This
statement requires the recording of the fair value of a liability for an asset retirement obligation in the period in which it is incurred.
When the liability is initially recorded,the associated costs of the asset retirement obligation will be capitalized as part of the carrying
amount of the related long-livedasset.The liability will be accreted to its present value each period and the related capitalized costs
will be depreciated over the useful life of the related asset.Upon retirement of the asset,the Company will either settle the retirement
obligation for its recorded amount or incur a gain or loss.The adoption of this statement on January 1,2003 did not have a material
impact on the Company's financial condition or results of operations.The Company recovers certain asset retirement costs through
rates charged to customers as a portion of its depreciation expense.As of December 31,2002,the Company had estimated retirement
costs of $185.4 million included in accumulated depreciation.
FERC FORM NO.1 (ED.12-88)Page 123.6
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(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubrnission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
In June 2002,the FASB issued SFAS No.146,"Accounting for Costs Associated with Exit or Disposal Activities"which nullifies
EITF Issue No.94-3,"Liability Recognition for Certain Employee TerminationBenefits and Other Costs to Exit an Activity (including
Certain Costs Incurred in a Restructuring)."This statement requires that a liability for a cost associated with an exit or disposal
activity be recognized when the liability is incurred.Under EITF Issue No.94-3,a liability for an exit cost was recognized at the date
of an entity's commitment to an exit plan.This statement also requires the initial measurement of the liability at fair value.This
statement is effectivefor exit or disposal activities that are initiated after December 31,2002.The adoption of this statement did not
have any impact on the Company's financial condition or results of operations.
In December 2002,the FASB issued SFAS No.148,"Accounting for Stock-Based Compensation -Transition and Disclosure"which
amends SFAS No.123 "Accounting for Stock-Based Compensation."This statement provides alternative methods of transition for a
voluntary change to the fair value method of accounting for stock-based compensation.In addition,this statement requires the
disclosure of pro forma net income and earnings per common share had the Company adopted the fair value method of accounting for
stock-based compensation in a more prominent place in the financial statements (Note 1).This statement also requires the disclosure
of pro forma net income and earnings per common share in interim as well as annual financial statements.The alternative transition
methods and annual financial statement disclosures are effective for fiscal years ending after December 15,2002.Interim disclosures
are required for periods ending after December 15,2002.The adoption of this statement affects the Company's disclosures.As the
Company has not elected to adopt the fair value method of accounting for stock-based compensation,the adoption of this statement
does not have any impact on the Company's financial condition or results of operations.
In November 2002,the FASB issued Interpretation No.45,"Guarantor'sAccounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others."This interpretation clarifies the requirements of SFAS No.5,"Accounting
for Contingencies"relating to a guarantor's accounting for,and disclosure of,the issuance of certain types of guarantees.This
interpretation requires that upon issuance of a guarantee,the guarantor must recognize a liability for the fair value of the obligation it
assumes under that guarantee.The initial recognition and measurement provisions of this interpretation are to be applied on a
prospective basis to guarantees issued or modified subsequent to December 31,2002 and are not expected to have a material impact on
the Company's financial condition or results of operations.The disclosure requirements of this interpretation are effectivefor financial
statements issued for periods that end after December 15,2002.See Note 16 for disclosure of the Company's guarantees.
In January 2003,the FASB issued Interpretation No.46,"Consolidation of Variable Interest Entities."In general,a variable interest
entity does not have equity investors with voting rights or it has equity investors that do not providesufficient financial resources for
the entity to support its activities.Variable interest entities are commonly referred to as special purpose entities or off-balance sheet
structures;however,this FASB interpretation applies to a broader group of entities.This interpretation requires a variable interest
entity to be consolidated by the primary beneficiary of that entity.The primary beneficiary is subject to a majority of the risk of loss
from the variable interest entity's activities or it is entitled to receive a majority of the entity's residual returns.The interpretation also
requires disclosure of variable interest entities that a company is not required to consolidate but in which it has a significant variable
interest.The consolidation requirements of this interpretation apply immediately to variable interest entities created after January 31,
2003 and apply to existing entities for the first fiscal year or interim period beginning after June 15,2003.Certain disclosure
requirements apply to all financial statements issued after January 31,2003,regardless of when the variable interest entity was
established.
The application of this FASB interpretation will require the Company to consolidate WP Funding LP effectiveJuly 1,2003.WP
Funding LP is an entity that was formed for the purpose of acquiring the natural gas-fired combustion turbine generating facility in
Rathdrum,Idaho (Rathdrum CT).WP Funding LP purchased the Rathdrum CT from the Company with funds providedby unrelated
investors of which 97 percent represented debt and 3 percent represented equity.The Company operates the Rathdrum CT and leases
it from WP Funding LP and currently makes lease payments of $4.5 million per year.The total amount of WP Funding LP debt
outstanding that is not included on the Company's balance sheet was $54.5 million as of December 31,2002.The lease term expires
in February 2020;however,the current debt matures in October 2005 and will need to be refinanced at that time.Based on current
information,the difference between the book value of the debt and equity of WP Funding LP and the book value of the Rathdrum CT
is approximately $15.5 million ($10.1 million,net of taxes).The Company intends to request regulatory accounting orders to record
this amount as a regulatory asset upon the consolidation of WP Funding LP.
NOTE 3.ACCOUNTS RECEIVABLE SALE
FERC FORM NO.1 (ED.12-88)Page 123.7
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(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
In 1997,Avista Receivables Corp.(ARC),formerly known as WWP Receivables Corp.,was formed as a wholly owned,
bankruptcy-remote subsidiary of the Company for the purpose of acquiring or purchasing interests in certain accounts receivable,both
billed and unbilled,of the Company.On May 29,2002,ARC,the Company and a third-party financial institution entered into a
three-year agreement whereby ARC can sell without recourse,on a revolvingbasis,up to $100.0 million of those receivables.ARC is
obligated to pay fees that approximate the purchaser's cost of issuing commercial paper equal in value to the interests in receivables
sold.On a consolidated basis,the amount of such fees is included in operating expenses of the Company.As of December 31,2002
and 2001,$65.0 million and $75.0 million,respectively,in accounts receivables were sold.
NOTE 4.UTILITY ENERGY COMMODITY DERIVATIVE ASSETS AND LIABILITIES
SFAS No.133,as amended by SFAS No.138,establishes accounting and reporting standards for derivative instruments,including
certain derivative instruments embedded in other contracts,and for hedging activities.It requires the recording of all derivatives as
either assets or liabilities in the balance sheet measured at estimated fair value and the recognition of the unrealized gains and losses.
In certain defined conditions,a derivativemay be specifically designated as a hedge for a particular exposure.The accounting for
derivatives depends on the intended use of the derivatives and the resulting designation.
Avista Utilities enters into forwardcontracts to purchase or sell energy.Under forwardcontracts,Avista Utilities commits to purchase
or sell a specified amount of energy at a specified time,or during a specified period,in the future.Certain of these forward contracts
are considered derivative instruments.Avista Utilities also records derivative commodity assets and liabilities for over-the-counter and
exchange-traded derivative instruments as well as certain long-term contracts.These contracts are entered into to manage Avista
Utilities'loads and resources as discussed in Note 5.In conjunction with the issuance of SFAS No.133,the WUTC and the IPUC
issued accounting orders requiring Avista Utilities to offset any derivative assets or liabilities with a regulatory asset or liability.This
accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until
the period of settlement.The order provides for Avista Utilities to not recognize the unrealized gain or loss on utility derivative
commodity instruments in the Consolidated Statements of Income and Comprehensive Income.Such realized gains or losses are
recognized in the period of settlement subject to current or future recovery in retail rates.
Avista Utilities believes substantially all of its purchases and sales contracts for both capacity and energy qualifyas normal purchases
and sales under SFAS No.133 and are not required to be recorded as derivative commodity assets and liabilities.Contracts that are
not considered derivatives under SFAS No.133 are generally accounted for at cost until they are settled unless there is a decline in the
fair value of the contract that is determined to be other than temporary.
As of December 31,2002,the utility derivative commodity asset balance was $60.3 million,the derivativecommodity liability
balance was $50.1 million and the offsetting net regulatory liability was $10.2 million.As of December 31,2001,the utility derivative
commodity asset balance was $1.9 million,the derivativecommodity liability balance was $159.4 million and the offsetting net
regulatory asset was $157.5 million.Utility derivativeassets and liabilities,as well as the offsetting net regulatory asset or liability,
can change significantly from period to period due to the settlement of contracts,the entering of new contracts and changes in
commodity prices.The derivative commodity asset balance is included in Deferred Charges -Utility energy commodity derivative
assets and the derivative commodity liability balance is included in Non-Current Liabilities and Deferred Credits -Utility energy
commodity derivative liabilities on the Consolidated Balance Sheet.The offsetting net regulatory asset is included in Deferred
Charges -Other regulatory assets and the offsetting net regulatory liability is included in Non-Current Liabilities and Deferred Credits
-Other non-current liabilities and deferred credits on the Consolidated Balance Sheet.
Interpretations that may be issued by the Derivatives Implementation Group,a task force created to assist the FASB in answering
questions that companies have in implementing SFAS No.133,may change the conclusions that the Company has reached regarding
accounting for energy contracts.As a result,the accounting treatment and financial statement impact could change in future periods.
NOTE 5.ENERGY COMMODITY TRADING
FERC FORM NO.1 (ED.12-88)Page 123.8
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(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
The Company's energy-related businesses are exposed to risks relating to,but not limited to,changes in certain commodity prices and
counterparty performance.In order to manage the various risks relating to these exposures,Avista Utilities utilizes electric,natural gas
and related derivativecommodity instruments,such as forwards,futures,swaps and options,and Avista Energy engages in the trading
of such instruments.Avista Utilities and Avista Energy have policies and procedures to manage risks inherent in these activities.The
Company has a Risk Management Committee,separate from the units that create such risk exposure,that is overseen by the Audit
Committee of the Company's Board of Directors,to monitor compliance with the Company's risk management policies and
procedures.
Avista Utilities
Avista Utilities sells and purchases electric capacity and energy at wholesale to and from utilities and other entities under long-term
contracts having terms of more than one year.In addition,Avista Utilities engages in an ongoing process of resource optimization
which involves short-term purchases and sales in the wholesale market in pursuit of an economic selection of resources to serve retail
and wholesale loads.Avista Utilities makes continuing projections of (1)future retail and wholesale loads based on,among other
things,forward estimates of factors such as customer usage and weather as well as historical data and contract terms and (2)resource
availability based on,among other things,estimates of streamflows,generating unit availability,historic and forward market
information and experience.On the basis of these continuing projections,Avista Utilities purchases and sells energy on an annual,
quarterly,monthly,daily and hourly basis to match actual resources to actual energy requirements.This process includes hedging
transactions.
Avista Utilities manages the impact of fluctuations in electric energy prices by establishing volume limits for the imbalance between
projected loads and resources and through the use of derivative commodity instruments for hedging purposes.Any imbalance is
required to remain within limits,or management action or decisions are triggered to address larger imbalance situations and manage
the exposure to market risk.Avista Energy is responsible for the daily management of natural gas supplies to meet the requirements of
Avista Utilities'customers in the states of Washington,Idaho and Oregon.
In addition,Avista Utilities utilizes derivative commodity instruments for hedging price risk associated with natural gas.The Risk
Management Committee has limited the types of commodity instruments Avista Utilities may use to those related to electricity and
natural gas commodities and those instruments are to be used for hedging price fluctuations associated with the management of energy
resources owned or controlled by Avista Utilities.The market values of natural gas derivative commodity instruments held by Avista
Utilities as of December 31,2002 and 2001,were a $24.6 million net liability and a $133.2 million net liability,respectively.The
significant liability position as of December 31,2001 was a result of forward commitments to purchase natural gas entered into during
2000 and the first part of 2001 at prices in excess of the market price for natural gas as of December 31,2001.The decrease from
December 31,2001 to December 31,2002 reflects the settlement of contracts during the period as well as an increase in the forward
price of natural gas.Realized losses are reflected as adjustments through purchased gas cost adjustments,the ERM or the PCA
mechanism.
Market Risk
Market risk is,in general,the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by
supply and demand.Market risk includes the fluctuation in the market price of associated derivative commodity instruments.Market
risk is influenced to the extent that the performance or nonperformance by market participants of their contractual obligations and
commitments affect the supply of,or demand for,the commodity.
Avista Utilities and Avista Energy manage,on a portfolio basis,the market risks inherent in their activities subject to parameters
established by the Company's Risk Management Committee.Market risks are monitored by the Risk Management Committee to
ensure compliance with the Company's risk management policies.Avista Utilities measures exposure to market risk through daily
evaluation of the imbalance between projected loads and resources.Avista Energy measures the risk in its portfolio on a daily basis
FERC FORM NO.1 (ED.12-88)Page 123.9
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(1)_X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIALSTATEMENTS (Continued)
utilizing a VAR model and monitors its risk in comparison to established thresholds.
Credit Risk
Credit risk relates to the risk of loss that Avista Utilities and/or Avista Energy would incur as a result of non-performance by
counterparties of their contractual obligations to deliver energy and make financial settlements.Credit risk includes not only the risk
that a counterparty may default due to circumstances relating directly to it,but also the risk that a counterparty may default due to
circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty.Avista Utilities
and Avista Energy seek to mitigate credit risk by applying specific eligibility criteria to existing and prospective counterparties and by
actively monitoring current credit exposures.These policies include an evaluation of the financial condition and credit ratings of
counterparties,collateral requirements or other credit enhancements,such as letters of credit or parent company guarantees,and the use
of standardized agreements that allow for the netting or offsetting of positive and negative exposures associated with a single
counterparty.
Credit risk also involves the exposure that counterparties perceive related to performance by Avista Utilities and Avista Energy to
perform deliveries and settlement of energy transactions.These counterparties may seek assurance of performance in the form of
letters of credit,prepayment or cash deposits,and,in the case of Avista Energy,parent company (Avista Capital)performance
guarantees.In periods of price volatility,the level of exposure can change significantly,with the result that sudden and significant
demands may be made against the Company's capital resource reserves (credit facilities and cash).Avista Utilities and Avista Energy
actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements.
Other Operating Risks
In addition to commodity price risk,Avista Utilities'commodity positions are subject to operational and event risks including,among
others,increases in load demand,transmission or transport disruptions,fuel quality specifications,forced outages at generating plants
and disruptions to information systems and other administrative tools required for normal operations.Avista Utilities also has
exposure to weather conditions and natural disasters that can cause physical damage to property,requiring immediate repairs to restore
utility service.
NOTE 6.CASH DEPOSITSWITH AND FROM COUNTERPARTIES
Cash deposits from counterparties totaled $92.7 million and $15.7 million as of December 31,2002 and 2001,respectively,and are
included in other current liabilities on the Consolidated Balance Sheets.These funds are held by Avista Utilities and Avista Energy to
mitigate the potential impact of counterparty default risk.These amounts are subject to return if conditions warrant because of
continuing portfolio value fluctuations with those parties or substitution of collateral.
Cash deposited with counterparties totaled $35.7 million and $1.5 million as of December 31,2002 and 2001,respectively,and are
included in prepayments and other current assets on the Consolidated Balance Sheets.
As is common industry practice,Avista Utilities and Avista Energy maintain margin agreements with certain counterparties.Margin
calls are triggered when exposures exceed predetermined contractual limits.Price movements in electricity and natural gas can
generate exposure levels in excess of these contractual limits.From time to time,margin calls are made and/or received by Avista
Utilities and Avista Energy.Negotiating for collateral in the form of cash,letters of credit,or parent company performance guarantees
is a common industry practice.
NOTE 7.JOINTLY OWNED ELECTRIC FACILITIES
The Company has a 50 percent ownership interest in a combined cycle natural gas-fired turbine power plant,the Coyote Springs 2
Generation Plant (Coyote Springs 2)located in northcentral Oregon.It is expected that Coyote Springs 2 will commence operations in
2003.The Company's investment in Coyote Springs 2 was $109.0 million as of December 31,2002.The Company's investment in
Coyote Springs 2 was held by Avista Power as of December 31,2002 and is included in Non-utility properties and investments in the
Consolidated Balance Sheet.In January 2003,the Company's ownership interest in the plant was transferred from Avista Power to
FERC FORM NO.1 (ED.12-88)Page 123.10
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(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Avista Corp.to be operated as an asset of Avista Utilities.The Company's share of related fuel costs as well as operating and
maintenance expenses for plant in service will be included in the corresponding accounts in the Consolidated Statements of Income
and Comprehensive Income when Coyote Springs 2 commences operations.
The Company has a 15 percent ownership interest in a twin-unit coal-fired generating facility,the Colstrip Generating Project
(Colstrip)located in southeastern Montana,and provides financing for its ownership interest in the project.The Company's share of
related fuel costs as well as operating and maintenance expenses for plant in service is included in the corresponding accounts in the
Consolidated Statements of Income and Comprehensive Income.The Company's share of utility plant in service for Colstrip was
$316.0 million and accumulated depreciation was $158.6 million as of December 31,2002.
NOTE 8.PROPERTY,PLANT AND EQUIPMENT
The balances of the major classifications of property,plant and equipment are detailed in the following table as of December 31
(dollars in thousands):
2002 2001
Avista Utilities:
Electric production $740,736 $691,299
Electric transmission 295,284 288,739
Electric distribution 698,757 678,448
Construction work-in-progress (CWIP)and other 85,631 119,389
Electric total 1,820,408 1,777,875
Natural gas underground storage 18,285 18,130
Natural gas distribution 430,273 414,422
CWIP and other 44,675 46,404
Natural gas total 493,233 478,956
Common plant (including CWIP)74,751 75,912
Total Avista Utilities 2,388,392 2,332,743
Energy Trading and Marketing 142,428 128,577
Informationand Technology 15,294 16,030
Other 20,611 21,117
Total $2.566.725 $2.498,467
Equipment under capital leases at Avista Utilities totaled $0.7 million as of December 31,2002.The associated accumulated
depreciation totaled $0.1 million as of December 31,2002.Avista Utilities did not have any property,plant and equipment under
capital leases as of December 31,2001.
NOTE 9.PENSIONPLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a defined benefit pension plan covering substantially all of its regular full-time employees.Certain of the
Company's subsidiaries also participate in this plan.Individual benefits under this plan are based upon years of service and the
employee's average compensation as specified in the plan.The Company's fundingpolicy is to contribute amounts that are not less
than the minimum amounts required to be funded under the Employee Retirement Income Security Act,nor more than the maximum
amounts which are currently deductible for income tax purposes.Pension fund assets are invested primarily in marketable debt and
equity securities.As of December 31,2002,the Company's pension plan had assets with a fair value that was less than the present
value of the accumulated benefit obligation under the plan.In 2002,the Company recorded an additional minimum liability for the
unfunded accumulated benefit obligation of $33.4 million and an intangible asset of $6.4 million (representing the amount of
unrecognized prior service cost)related to the pension plan.This resulted in a charge to other comprehensive income of $17.6 million,
net of taxes of $9.4 million.The pension plan was amended effectiveJuly 1,2002 to provide a lump sum payment option for
collectivelybargained employees.
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(1)X An Original (Mo,Da,Yr)
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NOTES TO FINANCIALSTATEMENTS (Continued)
The Company also has a Supplemental Executive Retirement Plan (SERP)that provides additional pension benefits to executive
officers of the Company.The SERP is intended to providebenefits to executive officers whose benefits under the pension plan are
reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred
compensation plans.In 2002,the Company recorded an additional minimum liability for the unfunded accumulated benefit obligationof$0.7 million related to the SERP.In 2001,the Company recorded an additional minimum liability for the unfunded accumulated
benefit obligation of $1.1 million related to the SERP.This resulted in a charge to other comprehensive income of $0.5 million and
$0.7 million,net of taxes,for 2002 and 2001,respectively.
The Company provides certain health care and life insurance benefits for substantially all of its retired employees.The Company
accrues the estimated cost of postretirement benefit obligations during the years that employees provide services.The Company
elected to amortize the transition obligationof $34.5 million over a period of twenty years,beginning in 1993.
The following table sets forth the pension and postretirement plan disclosures as of December 31,2002 and 2001 and for the years
ended December 31,2002,2001 and 2000 (dollars in thousands):
Post-
Pension Benefits
retirement Benefits
2002 2001 2002
2001
Change in benefit obligation:
Benefit obligation as of beginning of year $210,510 $184,636 $36,355 $32,761
Service cost 6,734 5,716 304 460
Interest cost 15,119 14,293 2,184 2,567
Plan amendment (2,530)-(5,821)Actuarial loss (gain)22,243 18,582 (660)3,267
Benefits paid (12,229)(11,780)(3,091)(2,635)
Expenses paid (1,462)(937)(209)(65)Benefit obligation as of end of year $238.385 $210,510 $29,062 $36,355
Change in plan assets:
Fair value of plan assets as of beginning of year $153,705 $175,033 $13,969 $15,196Actualreturnonplanassets(16,677)(9,313)(1,451)(902)Employer contributions 12,000 --511
Benefits paid (11,441)(11,078)(1,008)(771)
Expenses paid (1,462)(937)(209)(65)Fair value of plan assets as of end of year $136,125 $153,705 $1I 301 $133_69
Funded status $(102,260)$(56,805)$(17,761)$(22,386)Unrecognized net actuarial loss (gain)79,812 31,144 1,425 (429)
Unrecognized prior service cost 6,366 9,726
Unrecognized net transition obligation/(asset)(2.671)(3,757)9,788 16.865Accruedbenefitcost(18,753)(19,692)(6,548)(5,950)
Additionalminimum liability (35.303)(1,139)
Accrued benefit liability $(54,056)$(20.831)$(6.548)$(5.950)
Assumptions as of December 31
Discount rate 6.75%7.25%6.75%7.25%Expected long-term return on plan assets 8.00%9.00%8.00%9.00%
Rate of compensation increase 5.00%5.00%
Medical cost trend pre-age 65 -initial 9.00%9.00%
Medical cost trend pre-age 65 -ultimate 5.00%5.00%
FERC FORM NO.1 (ED.12-88)Page 123.12
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Ultimate medical cost trend year pre-age 65 2007 2003
Medical cost trend post-age 65 -initial 10.00%12.00%
Medical cost trend post-age 65 -ultimate 6.00%6.00%
Ultimate medical cost trend year post-age 65 2007 2004
2002 2001 2000 2002 2001
2000
Componentsof net periodic benefit cost:
Service cost $6,734 $5,716 $5,372 $304 $460 $601
Interest cost 15,119 14,293 13,412 2,184 2,567 2,407
Expected return on plan assets (12,311)(15,254)(16,243)(1,064)(1,311)(1,372)
Transition (asset)/obligation recognition (1,086)(1,086)(1,086)1,256 1,534 1,534
Amortization of prior service cost 831 989 1,548
Net gain recognition 1,021 139 (858)-(52)(300)
Net periodic benefit cost $10,308 $4,797 $2,145 $2,680 $3.198 $2,870
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans.A
one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement
benefit obligation as of December 31,2002 by $2.0 million and the service and interest cost by $0.2 million.A one-percentage-point
decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as
of December 31,2002 by $1.7 million and the service and interest cost by $0.2 million.
The Company 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 401(k)plan 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 401(k)plan.Employer
matching contributions of $3.4 million,$3.5 million,$3.3 million were expensed in 2002,2001 and 2000,respectively.
NOTE 10.ACCOUNTING FOR INCOME TAXES
As of December 31,2002 and 2001,the Company had net regulatory assets of $139.1 million and $149.0 million,respectively,related
to the probable recovery of certain deferred tax liabilities from customers through future rates.
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards.The net deferred income tax
liability consisted of the following as of December 31 (dollars in thousands):
2002 2001
Deferred tax assets:
Allowance for doubtful accounts $16,343 $17,431
Reserves not currently deductible 15,750 11,071
Contributions in aid of construction 9,709 9,176
Deferred compensation 4,I 12 4,48 I
Centralia sale regulatory liability 2,954 3,415
Unfunded accumulated benefit obligation 9,736 399
Other 7,172 9,544
Total deferred tax assets 65,776 55,517
Deferred tax liabilities:
Differences between book and tax basis of utility plant 364,827 367,406
Power and natural gas deferrals 58,081 88,323
Unrealized energy commodity gains 34.231 66,401
Power exchange contract 44,533 34,444
Demand side management programs 5,064 5,679
FERC FORM NO.1 (ED.12-88)Page 123.13
Name of Respondent This Report is:Date of Report Year of Report
(1)_X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Loss on reacquired debt 8,781 4,696
Other 4,406 5,996
Total deferred tax liabilities 519,923 572,945
Net deferred tax liability $454.147 $517,428
The realization of deferred tax assets is dependent upon the ability to generate taxable income in future periods.The Company
evaluated available evidence supporting the realization of its deferred tax assets and determined it is more likely than not that deferred
tax assets will be realized.
A reconciliation of federal income taxes derived from statutory federal tax rates (35 percent in 2002,2001 and 2000)applied to pre-tax
income from continuing operations as set forth in the accompanying Consolidated Statements of Income and Comprehensive Income is
as follows for the years ended December 31 (dollars in thousands):
2002 2001 2000
Federal income taxes at statutory rates $22,506 $32,897 $62,319
Increase (decrease)in tax resulting from:
Accelerated tax depreciation 5,166 5,849 4,835
State income tax expense 2,348 (8,870)3,712
Prior year audit adjustments -(395)72
Other-net (26)4,905 6,060
Total income tax expense $29,994 $34.386 $76,998
Income Tax Expense Consisted of the Following:
Federal taxes currently provided $70,281 $(44,755)$(4,839)
Deferred federal income taxes (40,287)79.141 81..837
Total income tax expense $29.994 $34,386 $76,998
Income Tax Expense by Business Segment:
Avista Utilities $32,137 $20,177 $(1,990)
Energy Trading and Marketing 12,311 32,489 95,266
Information and Technology (7,144)(11,977)(10,138)
Other (7,310)(6,303)(6,140)
Total income tax expense $29.994 $34,386 $76,998
NOTE 11.ENERGY PURCHASECONTRACTS
The Company has contracts related to the purchase of fuel for thermal generation,natural gas and hydroelectric power.The
termination dates of the contracts range from one month to the year 2044.The Company also has various agreements for the purchase,
sale or exchange of electric energy with other utilities,cogenerators,small power producers and government agencies.Total expenses
for power purchased,natural gas purchased,fuel for generation and other fuel costs were $382.4 million,$1,054.2 million and
$1,312.7 million in 2002,2001 and 2000,respectively.The following table details future contractual commitments for power
resources (including transmission contracts)and natural gas resources (including transportation contracts)(dollars in thousands):
2003 2004 2005 2006 2007 Thereafter Total
Power resources $194,873 $118,775 $65,349 $64,580 $66,476 $506,472 $1,016,525
Natural gas resources 195,580 171,470 82,393 48,175 48,172 385.375 931,165
Total $390.453 $290,245 $147,742 $112.755 $114,648 $891.847 $1,947.690
All of the energy purchase contracts were entered into as part of Avista Utilities'obligation to serve its retail natural gas and electric
customers'energy requirements.As a result,these costs are generally recovered either through base retail rates or adjustments to retail
rates as part of the power and natural gas cost deferral and recovery mechanisms.
In addition,the Company has operational agreements,settlements and other contractual obligations with respect to its generation.
FERC FORM NO.1 (ED.12-88)Page 123.14
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
transmission and distribution facilities.The expenses associated with these agreements are reflected as operation and maintenance
expenses in the Consolidated Statements of Income and Comprehensive Income.The following table details future contractual
commitments with respect to these agreements (dollars in thousands):
2003 2004 2005 2006 2007 Thereafter Total
Contractual obligations $10,345 $12.406 $12.405 $12.406 $12.405 $185,353 $245,320
The Company has fixed contracts with certain Public Utility Districts (PUD)to purchase portions of the output of certain generating
facilities.Although the Company has no investment in the PUD generating facilities,the fixed contracts obligate the Company to pay
certain minimum amounts (based in part on the debt service requirements of the PUD)whether or not the facility is operating.The
cost of power obtained under the contracts,including payments made when a facility is not operating,is included in resource costs in
the Consolidated Statements of Income and Comprehensive Income.Expenses under these PUD contracts for 2002,2001 and 2000,
were $7.8 million,$7.4 million and $7.5 million,respectively.
Information as of December 31,2002,pertaining to these PUD contracts is summarized in the following table (dollars in thousands):
Company's Current Share of
Debt Expira-
Kilowatt Annual Service Bonds tion
Output Capability Costs (1)Costs (1)Outstanding Date
Chelan County PUD:
Rocky Reach Project 2.9%37,000 $1,842 $623 $4,053 2011
Douglas County PUD:
Wells Project 3.5 30,000 1,100 587 5,465 2018
Grant County PUD:
Priest Rapids Project 6.1 55,000 1,768 910 9,662 2040
Wanapum Project 8.2 75,000 3,096 1,754 12.153 2040
Totals 197.000 $7.806 $3,874 $31,333
(1)The annual costs will change in proportionto the percentage of output allocated to the Company in a particular year.Amounts
represent the operating costs for the year 2002.Debt service costs are included in annual costs.
The estimated aggregate amounts of required minimum payments (the Company's share of existing debt service costs)under these
PUD contracts are as follows (dollars in thousands):
2003 2004 2005 2006 2007 Thereafter Total
Minimum payments $4,277 $3,249 $3,402 $2.759 $2,887 $22,041 $38,615
In addition,the Company will be required to pay its proportionate share of the variable operating expenses of these projects.
NOTE 12.LONG-TERM DEBT
The following details the interest rate and maturity dates of Secured and Unsecured Medium-Term Notes outstanding as of December
31 (dollars in thousands):
Secured Medium-Term Notes Unsecured Medium-Term Notes
Maturity Interest Interest
Year Rate 2002 2001 Rate 2002 2001
2002 -$-$*-$-$*
2003 6.25%15,000 15,000 6.75%-9.13%56,250 190,000
2004 ---7.42%30,000 30,000
2005 6.39%-6.68%29,500 29,500 --
FERC FORM NO.1 (ED.12-88)Page 123.15
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
2006 7.89%-7.90%30,000 30,000 8.14%8,000 8,000
2007 ---5.99%-7.94%26,000 26,000
2008 6.89%-6.95%20,000 20,000 6.06%25,000 25,000
2010 6.67%-6.90%10,000 10,000 8.02%25,000 25,000
2012 7.37%7,000 7,000 8.05%12,000 12,000
2018 7.26%-7.45%27,500 27,500
2022 ---8.15%-8.23%10,000 10,000
2023 7.18%-7.54%24,500 24,500 7.99%5,000 5,000
2028 ---6.37%-6.88%35,000 45,000
Total $163,500 $163,500 $232,250 $376,000
*In 2001,the Company legally defeased $50.0 million of Medium-Term Notes scheduled to mature in 2002.
During 2002,the Company repurchased $133.8 million of Medium-Term Notes scheduled to mature in 2003,$59.8 million of
Unsecured Senior Notes scheduled to mature in 2008 and $10.0 million of Medium-Term Notes scheduled to mature in 2028.In
accordance with regulatory accounting practices,total net premiums paid to repurchase debt were $9.5 million and are being amortized
over the average remaining maturity of outstanding debt.
In addition to the required maturities documented in the table above,the Company has sinking fund requirements of $3.1 million in
2003,$3.0 million in each of 2004 and 2005,$2.7 million in 2006 and $2.4 million in 2007.Under its Mortgage and Deed of Trust,
the Company's sinking fund requirements may be met by certification of property additions at the rate of 143 percent of requirements.
All of the Company's utility plant is subject to the lien of the Mortgage and Deed of Trust securing outstanding First Mortgage Bonds.
In April 2001,the Company issued $400.0 million of 9.75 percent Senior Notes due in 2008.In December 2001,the Company issued
$150.0 million of 7.75 percent First Mortgage Bonds due in 2007.
As of December 31,2002,the Company had remaining authorization to issue up to $317.0 million of Unsecured Medium-Term Notes.
Under various financing agreements,the Company is restricted as to the amount of additional First Mortgage Bonds that it can issue.
As of December 31,2002,the Company could issue $109.4 million of additional First Mortgage Bonds under the most restrictive of
these financing agreements.
In September 1999,$83.7 million of Pollution Control Revenue Refunding Bonds (Avista CorporationColstrip Project),Series 1999A
due 2032 and Series 1999B due 2034 were issued by the City of Forsyth,Montana.The proceeds of the bonds were utilized to refund
the $66.7 million of 7.13 percent First Mortgage Bonds due 2013 and the $17.0 million of 7.40 percent First Mortgage Bonds due
2016.The Series 1999A and Series 1999B Bonds are backed by an insurance policy issued by AMBAC Assurance Corporation.In
January 2002,the interest rate on the bonds was fixed for a period of seven years at a rate of 5.00 percent for Series 1999A and 5.13
percent for Series 1999B.
Other long-term debt consisted of the following items as of December 31 (dollars in thousands):
2002 2001
Notes payable $-$688
Capital lease obligations 1,618 2,101
Subsidiary total debt 1,618 2,789
Less:current portion 651 1,827
Other long-term debt $967 $962
NOTE 13.SHORT-TERM BORROWINGS
As of December 31,2002,the Company maintained a committed line of credit with various banks in the total amount of $225.0
million that expires on May 20,2003.The Company may have up to $50.0 million in letters of credit outstanding under this
FERC FORM NO.1 (ED.12-88)Page 123.16
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
committed line of credit.As of December 31,2002 and 2001,there were $14.3 million and $13.9 million of letters of credit
outstanding,respectively.The Company pays commitment fees of up to 0.2 percent per annum on the average daily unused portion of
the credit agreement,and utilization fees of up to 0.5 percent.
The committed line of credit agreement contains customary covenants and default provisions,including covenants not to permit the
ratio of "consolidated total debt"to "consolidated total capitalization"of Avista Corp.to be greater than 65 percent at the end of any
fiscal quarter.As of December 31,2002,the Company was in compliance with this covenant with a ratio of 54.3 percent.The
committed line of credit also has a covenant requiring the ratio of "earnings before interest,taxes,depreciation and amortization"to
"interest expense"of Avista Utilities for the year ending December 31,2002 to be greater than 1.6 to 1.As of December 31,2002,the
Company was in compliance with this covenant with a ratio of 2.04 to 1.
The Company had a commercial paper program that also provided for fixed-term loans during 2000 and 2001.None of these
agreements were in place as of December 31,2002 and 2001.
Balances and interest rates of bank borrowings under these arrangements were as follows as of and for the years ended December 31
(dollars in thousands):
2002 2001 2000
Balance outstanding at end of period:
Fixed-term loans $-$-$
Commercial paper --11,160
Revolvingcredit agreement 30,000 55,000 152,000
Maximum balance outstandingduring the period:
Fixed-term loans $-$-$80,000
Commercial paper -11,160 36,900
Revolvingcredit agreement 90,000 223,000 185,000
Averagebalance outstandingduring the period:
Fixed-term loans $-$-$19,538
Commercial paper -558 16,833
Revolvingcredit agreement 47,027 108,996 84,255
Average interest rate during the period:
Fixed-term loans -%-%6.70%
Commercial paper -7.80 6.82
Revolvingcredit agreement 3.59 5.95 7.26
Averageinterest rate at end of period:
Fixed-term loans -%-%-%
Commercial paper --7.63
Revolvingcredit agreement 3.39 5.42 7.55
NOTE 14.INTEREST RATE SWAP AGREEMENTS
In order to lower interest payments during a period of declining interest rates,Avista Corp.entered into an interest rate swap
agreement effective July 17,2002 and terminating on June 1,2008.This interest rate swap agreement effectivelychanges the interest
rate on $25 million of Unsecured Senior Notes from a fixed rate of 9.75 percent to a variable rate based on LIBOR.This interest rate
swap agreement is designated as a fair value hedge,which hedges the variability of the fair value of the long-term debt attributable to
interest rate risk.This interest rate swap agreement meets the conditions of a highly effective fair value hedge in accordance with
SFAS No.133.As such,this hedge is accounted for by recording the fair value of the interest rate swap on the balance sheet as either
an asset or liability with a corresponding offset recorded to mark the Unsecured Senior Notes to fair value.The fair value of the
interest rate swap was a $1.4 million asset as of December 31,2002,which is included in other deferred charges in the Consolidated
Balance Sheet.
FERC FORM NO.1 (ED.12-88)Page 123.17
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIALSTATEMENTS (Continued)
Rathdrum Power,LLC (RP LLC),an unconsolidated entity that is 49 percent owned by Avista Power,operates a 270 MW natural
gas-fired combustion turbine plant in northern Idaho (Lancaster Project).As of December 31,2002,RP LLC had $118.7 million of
debt outstanding that is not included in the consolidated financial statements of the Company.There is no recourse to the Company
with respect to this debt.RP LLC has entered into two interest rate swap agreements,maturing in 2006,to manage the risk that
changes in interest rates may affect the amount of future interest payments.RP LLC agreed to pay fixed rates of interest with the
differential paid or received under the interest rate swap agreements recognized as an adjustment to interest expense.These interest
rate swap agreements are considered hedges against fluctuations in future cash flows associated with changes in interest rates in
accordance with SFAS No.133.The fair value of the interest rate swap agreements was determined by reference to market values
obtained from various third party sources.Avista Power's 49 percent ownership interest in RP LLC is accounted for under the equity
method of accounting.The effect on the financial statements for 2002 was a $1.3 million unrealized loss recorded as other
comprehensive loss and a corresponding decrease in non-utility property and investments in the Consolidated Balance Sheet.
NOTE 15.LEASES
The Company has multiple lease arrangements involving various assets,with minimum terms ranging from one to twenty-fiveyears
and expiration dates from 2003 to 2020.The Company's most significant leased assets include the Rathdrum CT and the corporate
office building.See Note 2 for a change in accounting with respect to the Rathdrum CT that will become effectiveJuly 1,2003.
Certain lease arrangements require the Company,upon the occurrence of specified events,to purchase the leased assets.The
Company's management believes the likelihoodof the occurrence of the specified events under which the Company could be required
to purchase the leased assets is remote.Rental expense under operating leases for the years ended December 31,2002,2001 and 2000
was $21.7 million,$19.8 million and $16.2 million,respectively.
Future minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one
year as of December 31,2002 were as follows (dollars in thousands):
Year ending December 31:2003 2004 2005 2006 2007 Thereafter Total
Minimum payments required $15,132 $13,117 $8,834 $8,163 $7.314 $65.515 $118,075
The payments under the Avista Corp.capital leases are $0.2 million in each of 2003,2004 and 2005,and $0.1 million in 2006.
NOTE 16.GUARANTEES
Avista Power,through its equity investment in RP LLC,is a 49 percent owner of the Lancaster Project,which commenced commercial
operation in September 2001.Commencing with commercial operations,all of the output from the Lancaster Project is contracted to
Avista Energy for 25 years through a Power Purchase Agreement.Avista Corp.has guaranteed the Power Purchase Agreement with
respect to the performance of Avista Energy.
NOTE 17.PREFERRED STOCK-CUMULATIVE
On September 15,2002,the Company made a mandatory redemption of 17,500 shares of preferred stock for $1.75 million.On
September 15,2003,2004,2005 and 2006,the Company must redeem 17,500 shares at $100 per share plus accumulated dividends
through a mandatory sinking fund.As such,redemption requirements are $1.75 million in each of the years 2003 through 2006.The
remaining shares must be redeemed on September 15,2007.The Company has the right to redeem an additional 17,500 shares on
each September 15 redemption date.Upon involuntaryliquidation,all preferred stock will be entitled to $100 per share plus accrued
dividends.
NOTE 18.CONVERTIBLE PREFERRED STOCK
In December 1998,as part of a dividend restructuring plan,the Company issued 1,540,460 shares of its $12.40 Convertible Preferred
Stock,Series L (Series L Preferred Stock),in exchange for 15,404,595 shares of common stock,on the basis of a one-tenth interest in
one share of preferred stock for each share of common stock.The Series L Preferred Stock had a liquidationpreference of $182.8125
per share.
FERC FORM NO.1 (ED.12-88)Page 123.18
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
During 1999,the Company repurchased the equivalent of 32,250 shares of the Series L Preferred Stock.In February 2000,the
Company exercised its option to convert all the remaining outstanding shares of Series L Preferred Stock into common stock.One
share of Series L Preferred Stock equaled 10 depositary shares,also known as RECONS (Return-Enhanced ConvertibleSecurities).
The RECONS were also converted into common stock on the same conversion date.Each of the RECONS was converted into the
following:0.7205 shares of common stock,representing the optional conversion price;plus 0.0361 shares of common stock,
representing the optional conversion premium;plus the right to receive $0.21 in cash,representing an amount equivalent to
accumulated and unpaid dividends up until,but excluding,the conversion date.Cash payments were made in lieu of fractional shares.
NOTE 19.COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES
In 1997,Avista Capital I,a business trust,issued $60.0 million of Preferred Trust Securities with an annual distribution rate of 7.875
percent.Concurrent with the issuance of the Preferred Trust Securities,Avista Capital I issued $1.9 million of Common Trust
Securities to the Company.The sole assets of Avista Capital I are the Company's 7.875 percent Junior Subordinated Deferrable
Interest Debentures,Series A,with a principal amount of $61.9 million.These debt securities may be redeemed at the Company's
option on or after January 15,2002 and mature January 15,2037.The Company has not redeemed any of these Preferred Trust
Securities as of December 31,2002.
In 1997,Avista Capital II,a business trust,issued $50.0 million of Preferred Trust Securities with a floating distribution rate of LIBOR
plus 0.875 percent,calculated and reset quarterly.The annual distribution rate paid during 2002 ranged from 2.30 percent to 2.96
percent.As of December 31,2002,the annual distribution rate was 2.30 percent.Concurrent with the issuance of the Preferred Trust
Securities,Avista Capital II issued $1.5 million of Common Trust Securities to the Company.The sole assets of Avista Capital II are
the Company's Floating Rate Junior Subordinated Deferrable Interest Debentures,Series B,with a principal amount of $51.5 million.
These debt securities may be redeemed at the Company's option on or after June 1,2007 and mature June 1,2037.In December 2000,
the Company purchased $10.0 million of these Preferred Trust Securities.
The Company has guaranteed the payment of distributions on,and redemption price and liquidation amount in respect of,the
Preferred Trust Securities to the extent that Avista Capital I and Avista Capital II have funds available for such payments from the
respective debt securities.Upon maturity or prior redemption of such debt securities,the Trust Securities will be mandatorily
redeemed.The Consolidated Statements of Capitalization reflect only $100.0 million of Preferred Trust Securities as of December 31,
2002 and 2001 as all intercompany transactions have been eliminated.
NOTE 20.FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of the Company's long-term debt (including current-portion,but excluding notes payable and other)as of December 31,
2002 and 2001 was estimated to be $1,001.2 million,or 103 percent of the carrying value,and $1,160.2 million,or 99 percent of the
carrying value,respectively.The fair value of the Company's mandatorily redeemable preferred stock as of December 31,2002 and
2001 was estimated to be $29.3 million,or 88 percent of the carrying value,and $17.5 million,or 50 percent of the carrying value,
respectively.The fair value of the Company's preferred trust securities as of December 31,2002 and 2001 was estimated to be $89.6
million,or 90 percent of the carrying value,and $84.6 million,or 85 percent of the carrying value,respectively.These estimates were
based on available market information.
NOTE 21.COMMON STOCK
In April 1990,the Company sold 1,000,000 shares of its common stock to the Trustee of the Investment and Employee Stock
Ownership Plan for Employees of the Company (Plan)for the benefit of the participants and beneficiaries of the Plan.In payment for
the shares of common stock,the Trustee issued a promissory note payable to the Company in the amount of $14.1 million.Dividends
paid on the stock held by the Trustee,plus Company contributions to the Plan,if any,are used by the Trustee to make interest and
principal payments on the promissory note.The balance of the promissory note receivable from the Trustee ($4.1 million as of
December 31,2002)is reflected as a reduction to common equity.The shares of common stock are allocated to the accounts of
participants in the Plan as the note is repaid.During 2002,the cost recorded for the Plan was $6.0 million.Interest on the note
payable to the Company,cash and stock contributions to the Plan and dividends on the shares held by the Trustee were $0.5 million,
FERC FORM NO.1 (ED.12-88)Page 123.19
Name of Respondent This Report is:Date of Report Year of Report
(1)_X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTESTO FINANCIAL STATEMENTS (Continued)
$1.6 million and $0.1 million,respectively during 2002.
In May 1999,the Company's Board of Directors authorized the Company to repurchase in the open market or through privately
negotiated transactions up to an aggregate of 10 percent of its common stock and common stock equivalents over the next two years.
The repurchased shares return to the status of authorized but unissued shares.During 1999 and 2000,the Company repurchased
approximately 4.8 million common shares and 322,500 shares of Return-Enhanced Convertible Securities (equivalent to 32,250 shares
of Convertible Preferred Stock,Series L).The combined repurchases of these two securities represented 9 percent of outstanding
common stock and common stock equivalents.No common shares were repurchased during 2001 and 2002.
In November 1999,the Company adopted a shareholder rights plan pursuant to which holders of common stock outstanding on
February 15,1999,or issued thereafter,were granted one preferred share purchase right (Right)on each outstanding share of common
stock.Each Right,initially evidenced by and traded with the shares of common stock,entitles the registered holder to purchase one
one-hundredth of a share of preferred stock of the Company,without par value,at a purchase price of $70,subject to certain
adjustments,regulatory approval and other specified conditions.The Rights will be exercisable only if a person or group acquires 10
percent or more of the outstanding shares of common stock or commences a tender or exchange offer,the consummation of which
would result in the beneficial ownership by a person or group of 10 percent or more of the outstanding shares of common stock.Upon
any such acquisition,each Right will entitle its holder to purchase,at the purchase price,that number of shares of common stock or
preferred stock of the Company (or,in the case of a merger of the Company into another person or group,common stock of the
acquiring person or group)that has a market value at that time equal to twice the purchase price.In no event will the Rights be
exercisable by a person that has acquired 10 percent or more of the Company's common stock.The Rights may be redeemed,at a
redemption price of $0.01 per Right,by the Board of Directors of the Company at any time until any person or group has acquired 10
percent or more of the common stock.The Rights expire on March 31,2009.This plan replaced a similar shareholder rights plan that
expired in February 2000.
The Company has a Dividend Reinvestment and Stock Purchase Plan under which the Company's shareholders may automatically
reinvest their dividends and make optional cash payments for the purchase of the Company's common stock at current market value.
In March 2000,the Company began issuing shares of its common stock to the Employee Investment Plan rather than having the Plan
purchase shares of common stock on the open market.In the fourth quarter of 2000,the Company also began issuing new shares of
common stock for the Dividend Reinvestment and Stock Purchase Plan.During 2002,2001 and 2000,a total of 408,799,332,861 and
125,636 shares of common stock were issued,respectively,to these plans.
NOTE 22.EARNINGS PER COMMON SHARE
In February 2000,all outstanding shares of Series L Preferred Stock were converted into 11,410,047 shares of common stock.The
weighted-average number of shares of common stock outstanding during 2000 related to the converted shares was 9,975,997.The
cost of converting the Series L Preferred Stock into common stock totaled $21.3 million during the first quarter of 2000,with $18.1
million representing the optional conversion premium and $3.2 million attributable to the regular dividendon the preferred stock.
The following table presents the computation of basic and diluted earnings per common share for the years ended December 31 (in
thousands,except per share amounts):
2002 2001 2000
Numerator:
Income from continuing operations $34,310 $59,605 $101,055
Income (loss)from discontinued operations 1,145 (47.449)(9,376)
Net income before cumulative effect
of accounting change 35,455 12,156 91,679
Cumulative effect of accounting change (4,148)
Net mcome 31,307 12,156 91,679
Deduct:Preferred stock dividend requirements 2,402 2,432 23,735
Income available for common stock $28,905 $9,724 $67,944
FERC FORM NO.1 (ED.12-88)Page 123.20
Name of Respondent This Report is:Date of Report Year of Report
(1)_X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Denominator:
Weighted-average number of common shares
outstanding-basic 47,823 47,417 45,690
Effect of dilutive securities:
Restricted stock 2 5 101
Stock options 49 13 312
Weighted-average number of common shares
outstanding-diluted 47,874 47.435 46.103
2002 2001 2000
Earnings per common share,basic:
Earnings per common share from continuing operations $0.67 $1.21 $1.69
Earnings (loss)per common share
from discontinued operations 0.0_2 (1.00)(0.20)
Earnings per common share before cumulative effect
of accounting change 0.69 0.21 1.49
Loss per common share from cumulative effect
of accounting change (0.09)--
Total earnings per common share,basic $0.60 $0.21 $1.49
Earnings per common share,diluted:
Earnings per common share from continuing operations $0.67 $1.20 $1.67
Earnings (loss)per common share
from discontinued operations _0_.02 (1.00)(0.20)
Earnings per common share before cumulative effect
of accounting change 0.69 0.20 1.47
Loss per common share from cumulative effect
of accounting change (0.09)_
-__-
Total earnings per common share,diluted $0.60 $0.20 $1.47
NOTE 23.STOCK COMPENSATION PLANS
Avista Corg
In 1998,the Company adopted and shareholders approved an incentive compensation plan,the Long-Term Incentive Plan (1998
Plan).Under the 1998 Plan,certain key employees,directors and officers of the Company and its subsidiaries may be granted stock
options,stock appreciation rights,stock awards (including restricted stock)and other stock-based awards and dividend equivalent
rights.The Company has available a maximum of 2.5 million shares of its common stock for grant under the 1998 Plan.The shares
issued under the 1998 Plan are purchased by the trustee on the open market.Beginning in 2000,non-employee directors began
receiving options under this plan.
In 2000,the Company adopted a Non-Officer Employee Long-Term Incentive Plan (2000 Plan),which was not required to be
approved by shareholders.The provisions of the 2000 Plan are essentially the same as those under the 1998 Plan,except for the
exclusion of directors and executive officers of the Company.The Company has available a maximum of 2.5 million shares of its
common stock for grant under the 2000 Plan.
The Company accounts for stock based compensation using APB No.25,"Accounting for Stock Issued to Employees,"which requires
the recognition of compensation expense on the excess,if any,of the market price of the stock at the date of grant over the exercise
price of the option.As the exercise price for options granted under the 1998 Plan and the 2000 Plan was equal to the market price at
the date of grant,there was no compensation expense recorded by the Company.SFAS No.123,"Accounting for Stock-Based
FERC FORM NO.1 (ED.12-88)Page 123.21
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)A Resubmission 04/30/2003 Dec 31,2002
NOTESTO FINANCIAL STATEMENTS (Continued)
Compensation,"requires the disclosure of pro forma net income and earnings per common share had the Company adopted the fair
value method of accounting for stock options.Under this statement,the fair value of stock-based awards is calculated with option
pricing models.These models require the use of subjective assumptions,including stock price volatility,dividend yield,risk-free
interest rate and expected time to exercise.The fair value of options is estimated on the date of grant using the Black-Scholesoption-pricingmodel.
As of December 31,2002,there were 2.3 million shares available for future stock grants under the 1998 Plan and the 2000 Plan.
The following summarizes stock options activity under the 1998 Plan and the 2000 Plan for the years ended December 31:
2002 2001 2000
Number of shares under stock options:
Options outstanding at beginning of year 2,440,475 1,843,900 1,360,325
Options granted 569,800 781,900 623,200
Options exercised -(2,750)(44,975)
Options canceled (325,925)(182.575)(94,650)
Options outstanding at end of year 2,684,350 2,440,475 1,843,900
Options exercisable at end of year 1,192,775 883,075 581.025
Weighted average exercise price:
Options granted $10.51 $12.43 $23.03
Options exercised -$17.96 $18.53
Options canceled $19.88 $19.22 $18.15
Options outstanding at end of year $15.69 $17.49 $19.81
Options exercisable at end of year $18.28 $19.28 $18.72
Weighted average fair value of options granted during the year $3.43 $5.54 $12.02
Principal assumptions used in applying the Black-Scholes model:
Risk-free interest rate 3.25%-4.96%4.05%-5.13%5.87%-6.87%
Expected life,in years 7 7 7
Expected volatility 47.13%60.80%58.47%
Expected dividend yield 4.61%3.93%2.34%
Informationwith respect to options outstanding and options exercisable as of December 31,2002 was as follows:
Options Outstanding Options Exercisable
Weighted Weighted Weighted
Average Average Average
Range of Number Exercise Remaining Number Exercise
Exercise Prices of Shares Price Life (in years)of Shares Price
$10.17-$11.68 542,800 $10.25 9.8 -$-
$11.69-$14.61 694,600 11.80 8.9 173,650 11.80
$14.62-$17.53 587,600 17.16 6.7 405,275 17.26
$17.54-$20.45 329,875 18.75 5.5 316,775 18.70
$20.46-$23.37 494,275 22.56 7.5 267,475 22.58
$26.29-$29.22 35,200 27.19 5.5 29.600 26.95Total2,684,350 $15.69 7.9 1,192,775 $18.28
FERC FORM NO.1 (ED.12-88)Page 123.22
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
Non-Employee Director Stock Plan
In 1996,the Company adopted and shareholders approved the Non-Employee Director Stock Plan (1996 Director Plan).Under the
1996 Director Plan,directors who are not employees of the Company receive two-thirds of their annual retainer in Avista Corp.
common stock.The Company acquires the common stock in the open market.The Company has available a maximum of 150,000
shares of its common stock under the 1996 Director Plan and there were 85,937 shares available for future compensation to
non-employee directors as of December 31,2002.
NOTE 24.COMMITMENTS AND CONTINGENCIES
The Company believes,based on the informationpresently known,that the ultimate liability for the matters discussed in this note,
individually or in the aggregate,taking into account established accruals for estimated liabilities,will not be material to the
consolidated financial condition of the Company,but could be material to results of operations or cash flows for a particular quarter or
annual period.No assurance can be given,however,as to the ultimate outcome with respect to any particular issue.
Federal Energy Regulatory Commission Inquiry
In February 2002,the FERC issued an order commencing a fact-findinginvestigation of potential manipulation of electric and natural
gas prices in the Californiaenergy markets by multiple companies.On May 8,2002,the FERC requested data and information with
respect to certain trading strategies that companies may have engaged in.Specifically,the requests inquired as to whether or not the
Company engaged in certain trading strategies that were the same or similar to those used by Enron Corporation (Enron)and its
affiliates.These requests were made to all sellers of wholesale electricity and/or ancillary services in the Western Interconnection
during 2000 and 2001,including Avista Corp.and Avista Energy.On May 22,2002,Avista Corp.and Avista Energy filed their
responses to this request indicating that they had engaged in sound business practices in accordance with established market rules,and
that no information was evident from business records or employee interviews that would indicate that Avista Corp.or Avista Energy,
or its employees,were knowinglyengaged in these trading strategies,or any variant of the strategies.
On June 4,2002,the FERC issued an additional order to Avista Corp.and three other companies requiring these companies to show
cause within ten days as to why their authority to charge market-based rates should not be revoked.In this order,the FERC alleged
that Avista Corp.failed to respond fully and accurately to the data request made on May 8,2002.On June 14,2002,Avista Corp.
providedadditional information in response to the June 4,2002 FERC order to establish that its initial response was appropriate and
adequate.
On August 13,2002,the FERC issued an order to initiate an investigation into possible misconduct by Avista Corp.and Avista Energy
and two affiliates of Enron:Enron Power Marketing,Inc.(EPMI)and Portland General Electric Corporation(PGE).The purpose of
the investigation was to determine whether Avista Corp.and Avista Energy engaged in or facilitated certain Enron trading strategies,
whether Avista Corp.'s or Avista Energy's role in transactions with EPMI and PGE resulted in the circumvention of a code of conduct
governingtransactions with affiliates,and the imposition of any appropriate remedies such as refunds and revocation of market-based
rates.The investigation also explored whether the companies providedall relevant information in response to the May 8,2002 data
request.
In December 2002,the FERC staff,Avista Corp.and Avista Energy filed a joint motion announcing that the parties have reached an
agreement in principle.In the joint motion,the FERC Trial Staff states that its investigation found no evidence that:(1)any executives
or employees of Avista Utilities or Avista Energy knowingly engaged in or facilitated any improper trading strategy;(2)Avista
Utilities or Avista Energy engaged in any efforts to manipulate the western energy markets during 2000 and 2001;(3)Avista Utilities
or Avista Energy withheld relevant informationfrom the Commission's inquiry into the western energy markets for 2000 and 2001.
In December 2002,the FERC's administrative law judge approved the joint motion,suspending the procedural schedule in the FERC
investigation regarding Avista Corp.and Avista Energy.In January 2003,the FERC staff,Avista Corp.and Avista Energy filed a
completed agreement in resolution of the proceeding with the administrative law judge.The parties requested that the administrative
law judge certify the agreement and forwardit to the FERC for acceptance following a 30-day comment period.
FERC FORM NO.1 (ED.12-88)Page 123.23
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
On February 19,2003 the City of Tacoma (Tacoma)and CaliforniaParties (the Office of the Attorney General,the CPUC,and the
California Electricity Oversight Board,filing jointly)filed comments in opposition to the agreement in resolution between the FERC
staff,Avista Corp.and Avista Energy.PGE filed comments supporting the agreement in resolution,but took exception to how certain
transactions were reported.On March 3,2003,Avista Corp.and Avista Energy filedjoint reply comments in response to the concerns
raised by Tacoma,the CaliforniaParties,and PGE.The FERC Trial Staff filed separate reply comments supporting the agreement in
resolution and responding to Tacoma,the CaliforniaParties and PGE.The reply comments of Avista Corp.,Avista Energy and the
FERC Staffalso reiterated the request that the administrative law judge certify the agreement in resolution and forward it to the FERC
for approval.
U.S.Commodity Futures Trading Commission (CFTC)Subpoena
Beginning on June 17,2002,the CFTC has issued several subpoenas directing Avista Corp.to produce certain materials,make
employees available for questions and to respond to certain interrogatories.This relates to electricity and natural gas trades by Avista
Corp.and any of its subsidiaries (includingAvista Energy),involving "round trip trades,""wash trades,"or "sell/buyback trades"and
price reporting.The CFTC subpoena applies to both Avista Corp.and Avista Energy.The Company is cooperating with the CFTC
and is providingthe information requested by the CFTC.
Class Action Securities Litigation
On September 27,2002,Ronald R.Wambolt filed a class action lawsuit in the United States District Court for the Eastern District of
Washington against Avista Corp.,Thomas M.Matthews,the former Chairman of the Board,President and ChiefExecutive Officerof
the Company,Gary G.Ely,the current Chairman of the Board,President and Chief Executive Officer of the Company,and Jon E.
Eliassen,the former Senior Vice President and Chief Financial Officer of the Company.On October 9,2002,Gail West filed a similar
class action lawsuit in the same court against the same parties.On November 7,2002,Michael Atlas filed a similar class action
lawsuit in the same court against the same parties.On November 21,2002,Peter Arnone filed a similar class action lawsuit in the
same court against the same parties.In their complaints,the plaintiffs assert violations of the federal securities laws in connection with
alleged misstatements and omissions of material fact pursuant to Sections 10(b)and 20(a)of the Securities Exchange Act of 1934.In
particular,the plaintiffs allege that the Company failed to disclose certain business practices that Avista Corp.was allegedly engaging
in with EPMI and PGE.For furtherinformationsee "Federal Energy Regulatory Commission Inquiry"above.The plaintiffs assert
that such alleged misstatements and omissions have occurred in the Company's filings with the Securities and Exchange Commission
and other information made publicly available by the Company,including press releases.The class action lawsuits assert claims on
behalf of all persons who purchased,converted,exchanged or otherwise acquired the Company's common stock during the period
between November 23,1999 and August 13,2002.On February 3,2003,the court issued an order consolidating the complaints under
the name "In re Avista Corp.Securities Litigation,"and on February 7,2003 appointed the lead plaintiff and co-lead counsel.The
Company intends to file a motion to dismiss these consolidated complaints and vigorously defend against these lawsuits.
California Energy Markets
In April 2002,several subsidiaries of Reliant Energy,Inc.(Reliant)and Duke Energy Corporation (Duke)filed cross-complaints
against Avista Energy and numerous other participants in the Californiaenergy markets.The cross-complaints are for indemnification
for any liability which may arise from original complaints filed against Reliant and Duke with respect to charges of unlawful and unfair
business practices in the California energy markets under California law.Avista Energy has filed motions to dismiss the
cross-complaints.In the meantime,the U.S.District Court has remanded the case to CaliforniaState Court,which remand is itself the
subject of an appeal to the United States Court of Appeals for the Ninth Circuit.
In March 2002,the Attorney General of the State of California (California AG)filed a complaint with the FERC against certain
specific companies (not including Avista Corp.or its subsidiaries)and "all other public utility sellers"in California.The complaint
alleges that sellers with market-based rates have violated their tariffs by not filing with the FERC transaction-specific information
about all of their sales and purchases at market-based rates.As a result,all past sales should be subject to refund if found to be above
just and reasonable levels.In May 2002,the FERC issued an order denying the claim to issue refunds.In July 2002,the California
AG requested a rehearing on the FERC order,which request was denied in September 2002.The California AG filed a Petition for
Review of the FERC's decision with the United States Court of Appeals for the Ninth Circuit.
FERC FORM NO.1 (ED.12-88)Page 123.24
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
In April 2002,the CaliforniaAG providednotice of intent to file a complaint against Avista Energy in the California State Court on
behalf of the State of California.As of the filing date of this report,the California AG has not filed the threatened complaint against
Avista Energy.Complaints have been filed against approximately a dozen other companies,many of which have filed motions to
dismiss based upon federal preemption and primary jurisdictionarguments.The threatened complaint alleges that Avista Energy failed
to file rates and changes to rates charged for each sale of wholesale electricity in Californiamarkets with the FERC as required by
Federal Power Act regulations and FERC orders.The threatened complaint asserts that each violation of law,regulation and order is
an unlawful and unfair business practice under the California Business and Professions Code,subject to a penalty of $2,500 per
violation.The threatened complaint further alleges that certain rates charged for wholesale electricity sold in California exceeded a
just and reasonable rate.As such,the threatened complaint alleges that these rates violate the Federal Power Act and are also a
violation under the California Business and Professions Code,subject to penalty.A significant portion of the transactions involved in
this threatened complaint are also the subject of FERC proceedings to examine potential refunds and in most cases are transactions for
which Avista Energy is still owed payment.
WashingtonConsumerClass Action Lawsuit
On December 23,2002,Nick A.Symonds filed a class action lawsuit in the United States District Court for the Western District of
Washington against numerous purchasers and sellers of wholesale electricity and natural gas in the western United States,including
Avista Utilities.The class action lawsuit asserts claims on behalf of all persons and businesses residing in Washington who were
purchasers of electric and/or natural gas energy from any period beginning in January 2000 to the present.The complaint alleges that
due to the deregulation of the California energy market,the defendants were able to unlawfully manipulate the wholesale energy
market resulting in supply shortages and high energy prices across the western United States,including Washington.The complaint
further alleges that high energy prices have resulted in profits for the defendants at the expense of rate-paying consumers in
Washington.The complaint seeks treble damages,attorney fees and costs,and an order that defendants immediately remedy the
alleged unlawful practices relating to the purchase and sale of wholesale energy that affects rate-paying consumers in Washington.The
complaint further seeks an order enjoining the defendants from continuing any alleged unlawfulpractices relating to the purchase and
sale of wholesale energy that affects rate-paying consumers in Washington.The Company intends to file a motion to dismiss this
complaint and vigorously defend against this lawsuit.
Enron Corporation
On December 2,2001,Enron and certain of its affiliates filed for protection under chapter 11 of the United States Bankruptcy Code.
Both Avista Corp.and Avista Energy had done considerable business and had short-term and long-term contracts with Enron affiliates.
The bankruptcy filing constituted an event of default under contracts between Avista Corp.and Avista Energy,respectively,and
certain Enron affiliates,namely,EPMI,Enron North America Company (ENA)and Enron Canada Corp.(ECC),that are guaranteed by
Enron.As a result,Avista Corp.and Avista Energy terminated all of these contracts and suspended trading activities with all Enron
affiliates,including the final position that was terminated and a settlement agreement reached between Avista Corp.and EPMI in
October 2002.
As of December 31,2002,Avista Energy had net accounts receivable of $13.9 million from EPMI and ENA.Avista Corp.'s and
Avista Energy's contracts with each Enron affiliate provide that,upon termination,the net settlement of accounts receivable and
accounts payable with such entity will be netted against the net mark-to-market value of the terminated forwardcontracts with such
entity.It is estimated that for Avista Energy,netting the mark-to-market liability against the defaulted net accounts receivable will
result in no significant loss due to non-collection from the Enron affiliates.The Company further estimates that the net mark-to-market
liability to Enron affiliates with respect to the terminated forward contracts not yet settled (AvistaEnergy with EPMI and ENA)taken
together,exceeds total net accounts receivable from these entities by less than $15 million.
In October 2002,Avista Corp.settled its remaining contract with EPMI with the approval of the U.S.Bankruptcy Court.In addition,
Avista Corp.reached settlement agreements on all terminated positions with ECC and ENA.Avista Energy reached a settlement
agreement on its terminated ECC positions.In each instance,the settlement agreements reached satisfy all of the Avista entity's
obligations and exposure to such Enron entity.Confidentialityprovisions contained in the settlement agreements protect disclosure of
the specific details of each settlement.None of the settlements individually,nor all of the settlements collectively,have had or are
FERC FORM NO.1 (ED.12-88)Page 123.25
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
expected to have a material adverse impact on Avista Corp.'s or Avista Energy's financial condition,results of operations or cash
flows.All additional claims by the Enron entities for amounts that Avista Energy might owe with respect to the terminated forward
contracts would be subject to any defenses and counterclaims which Avista Energy may have.Any residual obligation by Avista
Energy for termination payments is not expected to have a material impact on the Company's financial condition,results of operations
or cash flows.The Company continues to negotiate the settlement of other contracts with Enron affiliates.
The estimates of the mark-to-market values of terminated forward contracts are based on available broker quotes for the respective
periods,and on assumptions as to future market prices and other information.While Avista Energy believes these assumptions are
reasonable,they are subject to change and ultimately could be challenged by the Enron entities or their bankruptcy trustees,except as
to those terminated forward contracts that have been fully settled by agreements among the parties as described above.The
mark-to-market value of terminated contracts has not been firmly established and could result in undercollection that is not expected to
be material to the financial condition,results of operations or cash flows of Avista Energy.
National Energy Production Corporation (NEPCO),a wholly owned subsidiary of Enron,was the contractor responsible for the
engineering,procurement and construction of Coyote Springs 2.Avista Corp.owns 50 percent of Coyote Springs 2.NEPCO was not
included in the initial bankruptcy filings made by Enron and its affiliates in December 2001.NEPCO subsequently filed for bankruptcy
on May 20,2002.However,Enron guaranteed NEPCO's obligations,and the bankruptcy filing by Enron was an event of default
under the Coyote Springs 2 construction contract.As a result of this default and other defaults under the contract,NEPCO was
removed as contractor for the project on April 15,2002.
Avista Corp.is party to a power exchange arrangement which expires in 2016.Under this power exchange arrangement,EPMI
purchases capacity from Avista Corp.and sells capacity to Spokane Energy LLC (Spokane Energy),a subsidiary of Avista Corp.,
formed in 1998 solely for the purpose of facilitating a long-term capacity contract between PGE and Avista Corp.The 1998
transaction resulted in the Company receiving $143.4 million in cash proceeds that was originally recorded as deferred revenue.
Spokane Energy sells the related capacity to PGE.Subsequently,PGE became a subsidiary of Enron that has not been included in the
bankruptcy filing to date.EPMI assisted in setting up the transaction structure and acts as an intermediary to abide by certain
regulatory restrictions that currently prevent Spokane Energy and Avista Corp.from dealing directly with each other.The transaction
is structured such that Spokane Energy bears full recourse risk for a loan (balance of $125.8 million as of December 31,2002)that
matures in January 2015 with no recourse to Avista Corp.related to the loan.EPMI is obligated to pay approximately $150,000 per
month to Avista Corp.for its capacity purchase.EPMI defaulted on two payments to Avista Corp.prior to filing for bankruptcy.
Such payments were accounted for and included in the settlement agreement reached between Avista Corp.and EPMI in October
2002.
Montana Hydroelectric Security Act Initiative
In the November 5,2002 General Election,Montana voters rejected an initiative that would have created a public agency to study
whether it would benefit the people of Montana to have the state own and operate certain hydroelectric generating facilities located
within the state.The initiative would have authorized the new public agency to acquire,through a negotiated purchase or an
acquisition at fair market value through a condemnation proceeding,any or all hydroelectric facilities larger than 5 MW within the
state.The Company's largest generation plant,the Noxon Rapids Hydroelectric Generating Station (Noxon Rapids)(527 MW),is
located in Montana on the Clark Fork River.
Hamilton Street BridgeSite
A portion of the Hamilton Street Bridge Site in Spokane,Washington (including a former coal gasification plant site that operated for
approximately 60 years until 1948)was acquired by the Company through a merger in 1958.The Company no longer owns the
property.Initial core samples taken from the site indicated environmental contamination at the site.On January 15,1999,the
Company received notice from the State of Washington's Department of Ecology (DOE)that it had been designated as a potentially
liable party (PLP)with respect to any hazardous substances located on this site,stemming from the Company's past ownership of the
former gas plant site.In its notice,the DOE stated that it intended to complete an on-going remedial investigation of this site,
complete a feasibility study to determine the most effectivemeans of halting or controllingfuture releases of substances from the site,
FERC FORM NO.1 (ED.12-88)Page 123.26
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(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
and to implement appropriate remedial measures.The Company responded to the DOE acknowledging its listing as a PLP,but
requested that additional parties also be listed as PLPs.In the spring of 1999,the DOE named two other parties as additional PLPs.
An Agreed Order was signed by the DOE,the Company and another PLP,Burlington Northern &Santa Fe Railway Co.(BNSF)on
March 13,2000 that providedfor the completion of a remedial investigation and a feasibility study.The work to be performed under
the Agreed Order includes three major technical parts:completion of the remedial investigation;performance of a focused feasibility
study;and implementation of an interim groundwater monitoring plan.During the second quarter of 2000,the Company received
comments from the DOE on its initial remedial investigation,then submitted another draft of the remedial investigation,which was
accepted as final by the DOE.After responding to comments from the DOE,the feasibility study was accepted by the DOE during the
fourthquarter of 2000.After receiving input from the Company and the other PLPs,the final Cleanup Action Plan (CAP)was issued
by the DOE on August 10,2001.On September 10,2001,the DOE issued an initial draft Consent Decree for the PLPs to review.
During the first quarter of 2002,the Company and BNSF signed a cost sharing agreement.On September 11,2002,the Company,
BNSF and the DOE finalized the Consent Decree to implement the CAP.The third PLP has indicated it will not sign the Consent
Decree.It is currently estimated that the Company's share of the costs will be less than $1.0 million.The Engineering and Design
Report for the CAP was submitted to the DOE in January 2003.If approved by the DOE,it is anticipated that the CAP will be
implemented in mid-2003.Negotiations are continuing with the third PLP with respect to the logistics of the CAP.
Lake Coeur d'Alene
In July 1998,the United States District Court for the District of Idaho issued its finding that the Coeur d'AleneTribe of Idaho owns
portions of the bed and banks of Lake Coeur d'Alene and the St.Joe River lying within the current boundaries of the Coeur d'Alene
Reservation.This action was brought by the United States on behalf of the Tribe against the State of Idaho.While the Company is not
a party to this action,the Company is continuing to evaluate the potential impact of this decision on the operation of its hydroelectric
facilities on the Spokane River,downstream of Lake Coeur d'Alene.The United States District Court decision was affirmed by the
United States Court of Appeals for the Ninth Circuit.The United States Supreme Court affirmedthis decision in June 2001.This will
result in the Company being liable to the Coeur d'Alene Tribe of Idaho for payments for use of reservation lands under Section 10(e)
of the Federal Power Act.
Spokane River Relicensing
The Company operates six hydroelectric plants on the Spokane River,and five of these (Long Lake,Nine Mile,Upper Falls,Monroe
Street and Post Falls)are under one FERC license and referred to herein as the Spokane River Project.The sixth,Little Falls,is
operated under separate Congressional authority and is not licensed by the FERC.The license for the Spokane River Project expires
in August 2007;the Company filed a Notice of Intent to Relicense on July 29,2002.The formal consultation process involving
planning and information gathering with stakeholder groups is underway.The Company's goal is to develop with the stakeholders a
comprehensive and cost-effective settlement agreement to be filed as part of the Company's license application to the FERC in July
2005.
Clark Fork Settlement Agreement
The issue of high levels of dissolved gas which exceed Idaho and federal water quality standards downstream of the Cabinet Gorge
Hydroelectric Generating Project (Cabinet Gorge)during spill periods continues to be studied,as agreed to in the Clark Fork
Settlement Agreement and incorporated into the renewed FERC license.To date,intensive biological studies in the lower Clark Fork
River and Lake Pend Oreille have documented minimal biological effects of high dissolved gas levels on free ranging fish.Under the
terms of the Clark Fork Settlement Agreement,the Company developed an abatement and mitigation strategy during 2002 with the
other signatories to the agreement.In December 2002,the Company submitted its plan for review and approval by the other
signatories as well as the FERC.The structural alternative proposed in the plan provides for the modification of the two existing
diversion tunnels built when Cabinet Gorge was originally constructed.The costs of modifications to the first tunnel are currently
estimated to be $37 million (including AFUDC and inflation)and would be incurred between 2004 and 2009.The second tunnel
would be modified only after evaluation of the performance of the first tunnel and such modifications would commence no later than
10 years following the completion of the first tunnel.It is currently estimated that the costs to modify the second tunnel would be $23
million (including AFUDC and inflation).As part of the plan,the Company will also provide$0.5 million annually commencing as
FERC FORM NO.1 (ED.12-88)Page 123.27
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(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
early as 2004,as mitigation for aquatic resources that might be adversely affected by high dissolved gas levels.Mitigation funds will
continue until the modification of the second tunnel commences or if the second tunnel is not modified to an agreed upon point in time
commensurate with the biological effects of high dissolved gas levels.The Company will seek regulatory recovery of the costs for the
modification of Cabinet Gorge and the mitigation payments.
The operating license for the Clark Fork Projects describes the approach to restore bull trout populations in the project areas.Using
the concept of adaptive management,the Company is evaluating the feasibility of fish passage and,depending upon the results of these
experimental studies,determining the applications of funds toward continuing fish passage efforts or other population enhancement
measures.
Other Contingencies
In the normal course of business,the Company has various other legal claims and contingent matters outstanding.The Company
believes that any ultimate liability arising from these actions will not have a material adverse impact on the Company's financial
condition,results of operations or cash flows.
The Company routinely assesses,based on in-depth studies,expert analyses and legal reviews,its contingencies,obligations and
commitments for remediation of contaminated sites,including assessments of ranges and probabilities of recoveries from other
responsible parties who have and have not agreed to a settlement and recoveries from insurance carriers.The Company's policy is to
immediately accrue and charge to current expense identified exposures related to environmental remediation sites based on estimates
of investigation,cleanup and monitoring costs to be incurred.
The Company has potential liabilities under the Federal Endangered Species Act (ESA)for species of fish that have either already
been added to the endangered species list,been listed as "threatened"or been petitioned for listing.Thus far,measures adopted and
implemented have had minimal impact on the Company.
Under the federal licenses for its hydroelectric projects,the Company is obligated to protect its property rights,including water rights.
The State of Montana is examining the status of all water right claims within state boundaries,which could potentially adversely affect
the energy production of the Company's Cabinet Gorge and Noxon Rapids hydroelectric facilities.The Company is participating in
this extended process,which is unlikely to be concluded in the foreseeable future.
The Company must be in compliance with requirements under the Clean Air Act Amendments (CAAA)at the Colstrip thermal
generating plant,in which the Company maintains an ownership interest.The anticipated share of costs at Colstrip is not expected to
have a major economic impact on the Company.
As of December 31,2002,the Company's collective bargaining agreement with the International Brotherhood of Electrical Workers
represented approximately 48 percent of all Avista Utilities employees.The current agreement with the local union representing the
majority of the bargaining unit employees expires on March 25,2005.A local agreement in the South Lake Tahoe area,which
represents 5 employees,also expires on March 25,2005.Three other labor agreements in Oregon,which cover approximately 55
employees,expire on March 31,2003.Negotiations are currently ongoing with respect to the agreements that expire on March 31,
2003.
NOTE 25.DISPOSITION OF POWER PLANT
In May 2000,the owners of Centralia sold the plant to TransAlta.Avista Utilities recorded an after-tax gain totaling $37.2 million
from the sale of its 17.5 percent ownership interest in the plant.Of the total after-tax gain,$9.0 million was recorded in the
Consolidated Statements of Income and Comprehensive Income for the year ended December 31,2000 and $28.2 million was deferred
and returned to Avista Utilities'customers through rates over established periods of time.Washington customers received $20.7
million of the after-tax gain through pre-tax credits to their electric bills over the two-month period of December 2000 and January
2001.Idaho customers are receiving the remaining $7.5 million of the after-tax gain,which is a rate reduction of 1.8 percent,over an
eight-year period.
FERC FORM NO.1 (ED.12-88)Page 123.28
Name of Respondent This Report is:Date of Report Year of Report
(1)_X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTE 26.SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
The Company's energy operations are significantly affected by weather conditions.Consequently,there can be large variances in
revenues,expenses and net income between quarters based on seasonal factors such as temperatures and streamflow conditions.A
summary of quarterly operations (in thousands,except per share amounts)for 2002 and 2001 follows:
Three Months Ended
March June September December
31 30 30 31
2002
Operating revenues $306,979 $218,362 $189,830 $265,275
Operating expenses 260,471 180,627 169,453 225,208
Income from operations 46,508 37,735 20,377 40,067
Income (loss)from continuing operations 15,520 9,331 (1,082)10,541
Income (loss)from discontinued operations (272)1,014 (533)936
Net income before cumulative effect
of accounting change 15,248 10,345 (1,615)11,477
Cumulative effect of accounting change (4,148)
Net income (loss)11,100 10,345 (1,615)11,477
Income (loss)available for common stock $10,492 $9,737 $(2,223)$10,899
Outstanding common stock:
Weighted average 47,671 47,774 47,866 47,978
End of period 47,737 47,830 47,930 48,044
Earnings (loss)per share,basic and diluted:
Earnings (loss)per share from continuing operations $0.32 $0.18 $(0.04)$0.21
Earnings (loss)per share from discontinued operations (0.01)0.02 (0.01)().02
Earnings (loss per share before cumulative effect
of accounting change 0.31 0.20 (0.05)0.23
Cumulative effect of accounting change (0.09)_
--
Total earnings (loss)per share,basic $0.22 $0.20 $(0.05)$0.23
Dividends paid per common share $0.12 $0.12 $0.12 $0.12
Tradingprice range per common share:
High $16.47 $16.60 $13.89 $12.10
Low $13.00 $11.00 $10.16 $8.75
2001
Operating revenues $473,855 $371,135 $232,113 $318,210
Operating expenses 408,408 314,585 198,494 304,534
Income from operations 65,447 56,550 33,619 13,676
Income (loss)from continuing operations 32,121 25,980 6,111 (4,607)
Loss from discontinued operations (2,718)(3,255)(38,421)(3,055)
Net income (loss)29,403 22,725 (32,310)(7,662)
Income (loss)available for common stock $28,795 $22,117 $(32,918)$(8,270)
Outstanding common stock:
Weighted average 47,237 47,372 47,486 47,569
End of period 47,266 47,465 47,537 47,633
Earnings (loss)per share,basic and diluted:
Earnings (loss)per share from continuing operations $0.67 $0.54 $0.12 $(0.11)
Loss per share from discontinued operations (0.06)(0.07)(0.81)(0.06)
Total earnings (loss)per share,basic $0.61 $0.47 $(0.69)$(0.17)
FERC FORM NO.1 (ED.12-88)Page 123.29
Name of Respondent This Report is:Date of Report Year of Report
(1)_X An Original (Mo,Da,Yr)
Avista Corp.(2)A Resubmission 04/30/2003 Dec 31,2002
NOTESTO FINANCIAL STATEMENTS (Continued)
Dividendspaid per common share $0.12 $0.12 $0.12 $0.12
Tradingprice range per common share:
High $20.63 $23.97 $19.98 $14.60Low$15.60 $16.27 $13.40 $10.60
FERC FORM NO.1 (ED.12-88)Page 123.30
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME,COMPREHENSIVE INCOME,Ah D HEDGING ACTIVITIES
1.Report in columns (b)(c)and (e)the amounts of accumulated other comprehensive income items,on a net-of-tax basis,where appropriate.
2.Report in columns (f)and (g)the amounts of other categories of other cash flow hedges.
3.For each category of hedges that have been accounted for as "fair value hedges",report the accounts affected and the related amounts in a footnote
.Item Unrealized Gains and Minimum Pension Foreign Currency OtherLine
No Losses on Available-Liability adjustment Hedges Adjustments
for-Sale Securities (net amount)
(a)(b)(c)(d)(e)
1 Balance of Account 219 at Beginning of
Preceeding Year
2 Preceding yr.Reclassification from Account
219 Net Income
3 Preceding Year Changes in Fair Value
4 Total (lines 2 and 3)
5 Balance of Account 219 at End of
Preceding Yr/Beginning of Current Yr
6 Current Year Reclassification From Account
219 to Net income
7 Current Year Changes in Fair Value (18,809,177)
8 Total (lines 6 and 7)(18,809,177)
9 Balance of Account 219 at End of Current
Year (18,809,177)
FERC FORM NO.1 (NEW 06-02)Page 122a
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME,COMPREHENSIVE INCOME,AND HEDGING ACTIVITIES
Other Cash Flow Other Cash Flow Totals for each Net Income (Carried TotalLineHedgesHedgescategoryofitemsForwardfromComprehensiveNo[Specify][Specify]recorded in Page 117,Line 72)Income
Account 219
(f)(g)(h)(i)(j)
1
2
4 12,155,766 12,155,766
5
6
7 (18,809,177)
8 (18,809,177)31,306,753 12,497,576
9 (18,809,177)
FERC FORM NO.1 (NEW 06-02)Page 122b
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
SUMMAHY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION.AMORTIZATION AND DEPLETlON
Line Classification Total Electric
No (a)(b)(c)
1 Utility Plant
2 In Service $ËÛÙ
3 Plant in Service (Classified)2,343,518,533 1,805,835,336
4 Property Under Capital Leases 712,325
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unciassified
8 Total (3 thru 7)2,344,230,858 1,805,835,336
9 Leased to Others
10 Held for Future Use
11 Construction Work in Progress 17,581,119 14,572,908
12 Acquisition Adjustments 26,580,073
13 Total Utility Plant (8 thru 12)2,388,392,050 1,820,408,244
14 Accum Prov for Depr,Amort,&Depl 824,688,269 607,504,878
15 Net Utility Plant (13 less 14)1,563,703,781 1,212,903,366
16 Detail of Accum Prov for Depr,Amort &Dep!
17 In Service:
18 Depreciation 772,278,930 603,295,686
19 Amort &Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utility Plant 5,732,382 4,209,192
22 Total in Service (18 thru 21)778,011,312 607,504,878
23 Leased to Others
24 Depreciation 31,676,743
25 Amortization and Depletion
26 Total Leased to Others (24 &25)31,676,743
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 &29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj 15,000,214
33 Total Accum Prov (equals 14)(22,26,30,31,32)824,688,269 607,504,878
FERC FORM NO.1 (ED.12-89)Page 200
Name of Respondent This Report is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION.AMORTIZATIONAND DEPLETION
Gas Other (Specify)Other (Specify)Other (Specify)Common Line
(d)(e)(f)(g)(h)No.
464,916,437 72,766,760 3
712,325 4
5
6
7
464,916,437 73,479,085 8
9
10
2,240,889 767,322 11
26,580,073 12
493,737,399 74,246,407 13
185,506,648 31,676,743 14
308,230,751 42,569,664 15
16
17
168,983,244 18
19
20
1,523,190 21
170,506,434 22
23
31,676,743 24
25
31.676,743 26
27
28
29
30
31
15,000,214 32
185,506,648 31,676.743 33
FERC FORM NO.1 (ED.12-89)Page 201
Name of Respondent This Re ort Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
1.Report below the costs incurred for nuclear fuel materials in process of fabrication,on hand,in reactor,and in cooling;owned by the
respondent.
2.If the nuclear fuel stock is obtained under leasing arrangements,attach a statement showing the amount of nuclear fuel leased,the
quantity used and quantity on hand,and the costs incurred under such leasing arrangements.
Line Description of item Balance Changes during Year
No.Beginning of Year Additions(a)(b)(c)
1 Nuclear Fuel in process of Refinement,Conv,Enrichment &Fab (120.1)
2 Fabrication
3 Nuclear Materials
4 Allowance for Funds Used during Construction
5 (Other Overhead Construction Costs,provide details in footnote)
6 SUBTOTAL (Total 2 thru 5)
7 Nuclear Fuel Materials and Assemblies
8 In Stock (120.2)
9 In Reactor (120.3)
10 SUBTOTAL (Total 8 &9)
11 Spent Nuclear Fuel (120.4)
12 Nuclear Fuel Under Capital Leases (120.6)
13 (Less)Accum Prov for Amortization of Nuclear Fuel Assem (120.5)
14 TOTAL Nuclear Fuel Stock (Total 6,10,11,12,less 13)
15 Estimated net Salvage Value of Nuclear Materials in line 9
16 Estimated net Salvage Value of Nuclear Materials in line 11
17 Est Net Salvage Value of Nuclear Materials in Chemical Processing
18 Nuclear Materials held for Sale (157)
19 Uranium
20 Plutonium
21 Other (provide details in footnote):
22 TOTAL Nuclear Materials held for Sale (Total 19,20,and 21)
FERC FORM NO.1 (ED.12-89)Page 202
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)g An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
NUCLEAF FUELMATERIALS(Account 120.1 through 120.6 and 157)
Changes during Year Balance LineAmoationÓtherReductionsExplaininafootnote)End Year No.
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21..-----................-----,22
FERC FORM NO.1 (ED.12-89)Page 203
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106)
1.Report below the original cost of electric plant in service according to the prescribed accounts.
2.In addition to Account 101,Electric Plant in Service (Classified),this page and the next include Account 102,Electric Plant Purchased or Sold;
Account 103,Experimental Electric Plant Unciassified;and Account 106,Completed Construction Not Classified-Electric.
3.Include in column (c)or (d),as appropriate,corrections of additions and retirements for the current or preceding year.
4.Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
5.Classify Account 106 according to prescribed accounts,on an estimated basis if necessary,and include the entries in column (c).Also to be included
in column (c)are entries for reversals of tentative distributions of prior year reported in column (b).Likewise,if the respondent has a significant amount
of plant retirements which have not been classified to primary accounts at the end of the year,include in column (d)a tentative distribution of such
retirements,on an estimated basis,with appropriate contra entry to the account for accumulated depreciation provision.Include also in column (d)
reversals of tentative distributions of prior year of unclassified retirements.Show in a footnote the account distributions of these tentative classifications
in columns (c)and (d),including the reversals of the prior years tentative account distributions of these amounts.Careful observance of the above
Line i Account Balance Additions
No Beginning of Year
(a)(b)(c)
1 1.INTANGIBLE PLANT -,o
2 (301)Organization 14,698
3 (302)Franchises and Consents 15,084,274
4 (303)Miscellaneous Intangible Plant 9,199,347 1,955,108
5 TOTAL Intangible Plant (Enter Total of lines 2,3,and 4)24,298,319 1,955,108
6 2.PRODUCTION PLANT
7 A.Steam Production Plant
8 (310)Land and Land Rights 2,248,799
9 (311)Structures and Improvements 123,257,425 290,696
10 (312)Boiler Plant Equipment 155,591,240 1,223,415
11 (313)Engines and Engine-DrivenGenerators
12 (314)Turbogenerator Units 44,429,261 250,974
13 (315)Accessory Electric Equipment 23,766,083
14 (316)Misc.Power Plant Equipment 14,975,947 65,794
15 TOTAL Steam Production Plant (Enter Total of lines 8 thru 14)364,268,755 1,830,879
16 B.Nuclear Production Plant
17 (320)Land and Land Rights
18 (321)Structures and Improvements
19 (322)Reactor Plant Equipment
20 (323)Turbogenerator Units
21 (324)Accessory Electric Equipment
22 (325)Misc.Power Plant Equipment
23 TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 22)
24 C.Hydraulic Production Plant
25 (330)Land and Land Rights 51,573,713 1,120,195
26 (331)Structures and Improvements 35,886,550 393,282
27 (332)Reservoirs,Dams,and Waterways 96,919,024 273,369
28 (333)Water Wheels,Turbines,and Generators 96,480,772 125,720
29 (334)Accessory Electric Equipment 24,146,429 1,531,510
30 (335)Misc.Power PLant Equipment 6,083,575 27,248
31 (336)Roads,Railroads,and Bridges 1,991,392 84
32 TOTAL Hydraulic Production Plant (Enter Total of lines 25 thru 31)313,081,455 3,471,408
33 D.Other Production Plant
34 (340)Land and Land Rights 617,158 145,076
35 (341)Structures and Improvements 257,333 703,576
36 (342)Fuel Holders,Products,and Accessories 1,242,556 207,716
37 (343)Prime Movers 6,879,665 15,704,721
38 (344)Generators 4,141,677 28,716,972
39 (345)Accessory Electric Equipment 569,447 221,282
FERC FORM NO.1 (ED.12-95)Page 204
Name of Respondent This Report Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp(2)A Resubmission 04/30/2003 '
ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106)(Continued)
instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent's plant actually in service at end of
year.
6.Show in column (f)reclassifications or transfers within utility plant accounts.Include also in column (f)the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102,include in column (e)the amounts with respect to accumulated
provision for depreciation,acquisition adjustments,etc.,and show in column (f)only the offset to the debits or credits distributed in column (f)to primary
account classifications.
7.For Account 399,state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showingsubaccountclassificationofsuchplantconformingtotherequirementofthesepages.
8.For each amount comprising the reported balance and changes in Account 102,state the property purchased or sold,name of vendor or purchase,
and date of transaction.If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts,give also date
of such filing.
Retirements Adjustments Transfers Balanceat Line
(d)(e)(f)End Year No.
14,698 2
15,084,274 3
14,352 11,140,103 4
14,352 26,239,075 5
2,248,799 8
123,548,121 9
109,349 156,705,306 10
11
44,680,235 12
23,766,083 13
4,506 15,037,235 14
113,855 365,985,779 15
17
18
19
20
21
22
23
52,693,908 25
5,774 36,274,058 26
12,540 97,179,853 27
1,181,150 95,425,342 28
54,392 25,623,547 29
6,110,823 30
1,991,476 31
1,253,856 315,299,007 32
33
762,234 34
960,909 35
1,450,272 36
200,000 22,384,386 37
32,858,649 38
790,729 39
FERC FORM NO.1 (ED.12-95)Page 205
Name of Respondent This Report Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp.(2)A Resubmission 04/30/2003
ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106)(Continued)
Line Account Balance Additions
No i Beginning of Year
(a)(b)(c)
40 (346)Misc.Power Plant Equipment 241,255 2,503
41 TOTAL Other Prod.Plant (Enter Total of lines 34 thru 40)13,949,091 45,701,846
42 TOTAL Prod.Plant (Enter Total of lines 15,23,32,and 41)691,299,301 51,004,133
43 3.TRANSMISSION PLANT jg"Ti Ä
44 (350)Land and Land Rights 12,109,788 8,411
45 (352)Structures and Improvements 8,690,269 270,957
46 (353)Station Equipment 110,564,405 3,533,161
47 (354)Towers and Fixtures 17,052,676 10,578
48 (355)Poles and Fixtures 73,328,377 1,979,953
49 (356)Overhead Conductors and Devices 63,292,726 1,292,959
50 (357)Underground Conduit 561,148
51 (358)Underground Conductors and Devices 1,317,533
52 (359)Roads and Trails 1,821,968 3,941
53 TOTAL Transmission Plant (Enter Total of lines 44 thru 52)288,738,890 7,099,960
54 4.DISTRIBUTION PLANT
55 (360)Land and Land Rights 3,987,252 155,920
56 (361)Structures and Improvements 9,524,158 534,923
57 (362)Station Equipment 66,097,774 1,617,963
58 (363)Storage Battery Equipment
59 (364)Poles,Towers,and Fixtures 144,745,600 4,475,229
60 (365)Overhead Conductors and Devices 99,094,169 2,666,437
61 (366)Underground Conduit 44,254,548 2,210,830
62 (367)Underground Conductors and Devices 75,279,195 2,543,070
63 (368)Line Transformers 115,322,611 2,764,742
64 (369)Services 78,467,200 3,779,179
65 (370)Meters 23,366,596 683,328
66 (371)Installations on Customer Premises
67 (372)Leased Property on Customer Premises
68 (373)Street Lighting and Signal Systems 18,308,562 1,312,058
69 TOTAL Distribution Plant (Enter Total of lines 55 thru 68)678,447,665 22,743,679
70 5.GENERAL PLANT g:g
71 (389)Land and Land Rights 124,681
72 (390)Structures and Improvements 1,657,727
73 (391)Office Furniture and Equipment 15,383 85,122
74 (392)Transportation Equipment 7,845,061 -48,197
75 (393)Stores Equipment 99,196
76 (394)Tools,Shop and Garage Equipment 2,678,384 14,947
77 (395)Laboratory Equipment 2,853,796
78 (396)Power Operated Equipment 17,545,158 227,604
79 (397)Communication Equipment 16,940,904 457,857
80 (398)Miscellaneous Equipment 1,739
81 SUBTOTAL (Enter Total of lines 71 thru 80)49,762,029 737,333
82 (399)Other Tangible Property
83 TOTAL General Plant (Enter Total of lines 81 and 82)49,762,029 737,333
84 TOTAL (Accounts 101 and 106)1,732,546,204 83,540,213
85 (102)Electric Plant Purchased (See Instr.8)
86 (Less)(102)Electric Plant Sold (See Instr.8)
87 (103)Experimental Plant Unciassified
88 TOTAL Electric Plant in Service (Enter Total of lines 84 thru 87)1,732,546,204 83,540,213
FERC FORM NO.1 (ED.12-95)Page 206
Name of Respondent This Report is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
ELECTRIC PLANT IN SERVICf (Account 101,102,103 and 106)(Continued)
Retirements Adjustments Transfers Balance at LineEndofYearNo(d)(e)(f)(g)
243,758 40
200,000 59,450,937 41
1,567,711 740,735,723 42
43
12,118,199 44
19,272 8,941,954 45
337,391 -1,733 113,758,442 46
17,063,254 47
85,477 75,222,853 48
110,997 64,474,688 49
561,148 50
1,317,533 51
1,825,909 52
553,137 -1,733 295,283,980 53
54
4,143,172 55
19,845 10,039,236 56
840,405 -53,974 66,821,358 57
58
96,676 149,124,153 59
125,367 101,635,239 60
43,311 46,422,067 61
330,507 77,491,758 62
533,011 65,113 117,619,455 63
63,820 82,182,559 64
318,412 23,731,512 65
66
67
73,730 19,546,890 68
2,445,084 11,139 698,757,399 69
70
124,681 71
27,309 1,630,418 72
100,505 73
689,608 7,107,256 74
99,196 75
34,290 2,659,041 76
9,296 2,844,500 77
1,237,850 16,534,912 78
26,297 17,372,464 79
1,739 80
2,024,650 48,474,712 81
82
2,024,650 48,474,712 83
6,604,934 9,406 1,809,490,889 84
85
86
87
6,604,934 9,406 1,809,490,889 88
FERC FORM NO.1 (ED.12-95)Page 207
Name of Respondent This Report is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
CONSTRUCTION WORK IN PROGRESS --ELECTRIC (Account 107)
1.Report below descriptions and balances at end of year of projects in process of construction (107)
2.Show items relating to "research,development,and demonstration"projects last,under a caption Research,Development,and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3.Minor projects (5%of the Balance End of the Year for Account 107 or $100,000,whichever is less)may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
1 STATE OF WASHINGTON
2 Post Street 115 Substation 126,318
3 Beacon-Rathdrum 230KV Line 216,295
4 Mead 115 Substation 869,299
5 Beacon Storage Yard-Build Containment Area 292,703
6 East Colfax MOAS A-147 197,542
7 Hydro Relicensing Costs-Spokane River Project 1,484,218
8 Highway 20E Re-route 139,514
9 Upper Falls Control Work 258,464
10 Minor Projects (27)Under $100,000 699,338
11
12 STATE OF IDAHO
13 Adelphia Make Ready Moscow 101,046
14 Oden 115 Sub-Split FDR &Scada FDR 127,954
15 Cabinet Gorge Special Projects 282,377
16 Cabinet Gorge Unit #2 Turbine 1,346,555
17 Tenth &Stewart 176,515
18 Beacon-Rathdrum 282,068
19 Cabinet Gorge Unit #4 Turbine 127,399
20 Pinecreek Rebuild 3,500,790
21 Clark Fork Settlement Agreement 952,521
22 Minor Projects (27)Under $100,000 985,189
23
24 STATE OF OREGON
25 Forestry Service Requirements 42,300
26 Coyote Springs Il
27
28 STATE OF MONTANA
29 Noxon Rapids Capital Projects Upgrades 412,298
30 Clark Fork Settlement Agreement 1,096,266
31 Minor Projects (1)Under $100,000 8,444
32
33 COMMON-WA &ID
34 AVA/BPA Fiber Project 671,581
35 Construction Engineering &Supervision 95,690
36 Minor Projects (2)Under $100,000 80,224
37
38
39
40
41
42
43 TOTAL 14,572,908
FERC FORM NO.1 (ED.12-87)Page 216
Name of Respondent This Report is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
.Explain in a footnote any important adjustments during year.
2.Explain in a footnote any difference between the amount for book cost of plant retired,Line 11,column (c),and that reported for
electric plant in service,pages 204-207,column 9d),excluding retirements of non-depreciable property.
3.The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service.If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications,make preliminary closing entries to tentatively functionalize the book
cost of the plant retired.In addition,include all costs included in retirement work in progress at year end in the appropriate functional
:lassifications.
4.Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Section A.Balances and (:hanges During Year
une item I otal Electnc Plant in Electnc Plant Held Electnc P nt(c+d+e)Service for Future Use Leased to t ersNo(a)(b)(c)(d)(e)
1 Balance Beginning of Year 566,628,662 566,628,662
|
2 Depreciation Provisions for Year,Charged to
3 (403)Depreciation Expense 42,327,187 42 327,187
4 (413)Exp.of Elec.Pit.Leas.to Others
5 Transportation Expenses-Clearing 810,219 810,219
6 Other Clearing Accounts
7 Other Accounts (Specify,details in footnote):
8
9 TOTAL Deprec.Prov for Year (Enter Total of 43,137,406 43,137,406
lines 3 thru 8)
10 Net Charges for Plant Retired:qu,ewas e
11 Book Cost of Plant Retired 6,590,584 6,590,584
12 Cost of Removal 1,029,699 1,029,699
13 Salvage (Credit)1,149,901 1,149,901
14 TOTAL Net Chrgs.for Plant Ret.(Enter Total 6,470,382 6,470,382
of lines 11 thru 13)
15 Other Debit or Cr.Items (Describe,details in
footnote):
16
17 Balance End of Year (Enter Totals of lines 1,603,295,686 603,295,686
9,14,15,and 16)
Section E .Balances at End of Yet r According to Functional Classification
18 Steam Production 188,943,461 188,943,461
19 Nuclear Production
20 Hydraulic Production-Conventional 60,150,874 60,150,874
21 Hydraulic Production-Pumped Storage
22 Other Production 11,251,128 11,251,128
23 Transmission 108,433,569 108,433,569
24 Distribution 207,482,732 207,482,732
|
25 General 27,033,922 27,033,922
26 TOTAL (Enter Total of lines 18 thru 25)603,295,686 603,295,686
I
FERC FORM NO.1 (ED.12-88)Page 219
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original (Mo,Da,Yr)Avista Corp (2)A Resubmission 04/30/2003 Dec.31,2002
INVESTM ENTS IN SUBSIDIARY COMPANIES (Account 123.1)
1.Report below investments in Accounts 123.1,investments in Subsidiary Companies.
2.Provide a subheading for each company and List there under the information called for below.Sub -TOTAL by company and give a TOTAL in
columns (e),(f),(g)and (h)
(a)Investment in Securities -List and describe each security owned.For bonds give also principal amount,date of issue,maturity and interest rate.
(b)Investment Advances -Report separately the amounts of loans or investment advances which are subject to repayment,but which are not subject to
current settlement.With respect to each advance show whether the advance is a note or open account.List each note giving date of issuance,maturity
date,and specifying whether note is a renewal.
3.Report separately the equity in undistributed subsidiary earnings since acquisition.The TOTAL in column (e)should equal the amount entered for
Account 418.1.
Line Description of Investment Date Acquired Date Of Amount of Investment at
No (a)(b)Mat4rity Begin g of Year
1
2 Avista Capital -Common Stock 1997 184,251,609
3 Avista Capital -Equity in Earnings 166,494,974
4 Dividends from Subsidiary (Avista Capital)
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42 Total Cost of Account 123.1 $0 TOTAL 350,746,583
FERC FORM NO.1 (ED.12-89)Page 224
Name of Respondent This Report Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)Avista Corp (2)A Resubmission 04/30/2003 Dec.31,2002
INVESTMENT3 IN SUBSIDIARYCOMPANIES (Account 123.1)(Continued)
4.For any securities,notes,or accounts that were pledged designate such securities,notes,or accounts in a footnote,and state the name of pledgee
and purpose of the pledge.
5.If Commission approval was required for any advance made or security acquired,designate such fact in a footnote and give name of Commission,
date of authorization,and case or docket number.
6.Report column (f)interest and dividend revenues form investments,including such revenues form securities disposed of during the year.
7.In column (h)report for each investment disposed of during the year,the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost)and the selling price thereof,not including interest adjustment includible
in column (f).
8.Report on Line 42,column (a)the TOTAL cost of Account 123.1
Equity in Šubsidiary Revenues for Year Amount of Investment at Óain or Loss from Investment LineEarnins4ofYearEndYearDispsedofNo.
1
184,251,609 2
-4,212,474 162,282,500 3
-89,796,369 -89,796,369 4
5
6
7
8
9
10
11
12
13
14
15
16
17
|
18
I I
I
19
.20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
-4,212,474 -89,796,369 256,737,740 42
FERC FORM NO.1 (ED.12-89)Page 225
Name of Respondent This Report Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)Avista Corp (2)A Resubmission 04/30/2003 Dec.31,2002
MATERIALS AND SUPPLIES
1.For Account 154,report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a)
estimates of amounts by function are acceptable.In column (d),designate the department or departments which use the class of material.
2.Give an explanation of important inventory adjustments during the year (in a footnote)showing general classes of material and supplies and the
various accounts (operating expenses,clearing accounts,plant,etc.)affected debited or credited.Show separately debit or credits to stores expense
clearing,if applicable.
Line Account Balance Balance Department or
No.Beginning of Year End of Year Departmentswhich
Use Material(a)(b)(c)(d)
1 Fuel Stock (Account 151)3,395,773 3,261,065
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to -Construction (Estimated)5,151,843 4,502,503
6 Assigned to -Operations and Maintenance
7 Production Plant (Estimated)2,409,198 2,460,890
8 Transmission Plant (Estimated)5,989 14,011
9 Distribution Plant (Estimated)136,892 167,171
10 Assigned to -Other (provide details in footnote)1,311,352 1,304,937
11 TOTAL Account 154 (Enter Total of lines 5 thru 10)9,015,274 8,449,512
12 Merchandise (Account 155)
13 Other Materials and Supplies (Account 156)
14 Nuclear Materials Held for Sale (Account 157)(Not
applic to Gas Util)
15 Stores Expense Undistributed (Account 163)578,289 494,542
16
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)12,989,336 12,205,119
FERC FORM NO.1 (ED.12-96)Page 227
Name of Respondent This Re ort Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)2002AvistaCorpDec.31,(2)A Resubmission 04/30/2003
O 'HER REGULATORYASSETS (Account 182.3)
1.Report below the particulars (details)called for concerning other regulatory assets which are created through the rate making actions
of regulatory agencies (and not includable in other accounts)
2.For regulatory assets being amortized,show period of amortization in column (a)
3.Minor items (5%of the Balance at End of Year for Account 182.3 or amounts less than $50,000,whichever is less)may be grouped
by classes.
Line 'Description and Purpose of Debits OREDITS Balance at
No.Other Regulatory Assets Account Amount End of YearCharged
(a)'(b)(c)(d)(e)
1 FAS 106 -Accounting for Post Retirement 926.65 472,752 4,727,520
2 Benefits,other than Pensions (182.30)
3
4 FAS 109 -Acctng for Income Taxes Util Prop 283.17,18 9,898,399 139,499,024
5 (182.31 &182.32)
6 More Options Power Supply (MOPS)-WA (182.34 )407.44 190,944 190,944
7 More Options Power Supply (MOPS)-ID (182.34)407.44 59,184 29,592
8 WA ERM Deferral Balance (182.35)186.28,38 27,839,715 104,166,540
9 Hamilton Street Bridge --WA (182.39 028)407.39 111,480 389,388
10 Hamilton Street Bridge --ID (182.39 038)407.39 34,368 212,352
11 FAS 133 Reg Asset (182.74)
12 Oregon DSM Long-Term Regulatory Asset various 153,006 -468,429
13 (182.80)
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
|37
38
39
40
41
42
43
44 TOTAL 38,759,848 248,746,931
FERC FORM NO.1 (ED.12-94)Page 232
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
M SCELLANEOUS DEFFERED DEBITS (Account 186)
1.Report below the particulars (details)called for concerning miscellaneous deferred debits.
2.For any deferred debit being amortized,show period of amortization in column (a)
3.Minor item (1%of the Balance at End of Year for Account 186 or amounts less than $50,000,whichever is less)may be grouped by
classes.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year chcouend Amount End of Year
(a)(b)(c)(d (e)(f)
1 Regulatory Deferrals -WA
2 Colstrip Common Fac.634,800 406 31,740 603,060
3 WA Accrued Power Def 1,164,331 1,164,331
4 WA Deferred Power Costs 8,231,970 10,186,578 18,418,548
5 WA ERM YTD Company Band 4,500,000 4,500,000
6 WA ERM YTD Contra Account 4,500,000 -4,500,000
7
8 Regulatory Deferrals -ID
9 ID Deferred New Generation 921,184 921,184
10 Colstrip Common Fac.1,346,160 406 67,308 1,278,852
11 Idaho Accrued PCA Def 592,090 592,090
12 ID Deferred Power 75,046,296 var 17,086,246 57,960,050
13 ID Accumulated Surcharge Am -2,901,409 557 24,132,930 -27,034,339
14
15 Payroll Accrual 2,443,520 var 846,095 1,597,425
16
17 PPP Surcharge 32,468 332,458 364,926
18
19 Misc Error Suspense -254,559 var 1,951,765 -2,206,324
20
21 Joint Projects
22 Centralia Operating Payments 525,000 525,000
23
24 WPI-lD Terminated Elec Pur.1,175,981 555 391,992 783,989
25
26 Unamortized A/R Sale 269,502 87,921 357,423
27
28 intangible Pension Asset 6,365,810 6,365,810
29
30 Bank Recon Suspense -262,967 262,775 -192
31 Mark to Market Deferred Debit 1,889,288 254 1,889,288
32 Interest Rate Swap 1,368,874 1,368,874
33
34 Nez Perce Settlement 780,360 557 567,491 212,869
I35
36 Centralia Mine Env Balance 567,509 567,509
37
38 DES Contract Amortization 314,350 556 227,112 87,238
39
40 Metro-Sunset 115KV TE 11,966 56,685 68,651
41
42 UPRR Permit Conv 171,191 12,860 184,051
43
44 CPRR Permit Conv 28,077 44,294 72,371
45
46 Ortho Business Activity 38,900 46,127 85,027
47 Misc.Work in Progress
Deferred Regulatory Óomm.48 Expenses (See pages 350 -351)
49 TOTAL 109,424,216 81,406,921
FERC FORM NO.1 (ED.12-94)Page 233
Name of Respondent This Report Is;Date of Report Year of Report
(1)An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp.(2)A Resubmission 04/30/2003
L M SCELLANEOUS DEFFERED DEBITS (Account 186)
1.Report below the particulars (details)called for concerning miscellaneous deferred debits.
2.For any deferred debit being amortized,show period of amortization in column (a)
3.Minor item (1%of the Balance at End of Year for Account 186 or amounts less than $50,000,whichever is less)may be grouped by
classes.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
I No.Deferred Debits Beginning of Year chcouend Amount End of Year
(a)(b)(c)(d (e)(f)
1 Canadian GST Tax 148,151 var 52,747 95,404
2
3 Nez Perce Forest 53,430 38,446 91,876
4
5 Electric Network 77,595 77,595
6
7 Misc Work Orders <$50,000 194,770 131,816 326,586
8 Subsidiary Billings 2,930,118 var 707,381 2,222,737
9
10 Conservation
11 Enhanced Low Income Wzn 62,505 62,505
12 Oregon Gas Comm Consvt 103,835 47,032 150,867
13 Oregon Shower Head 184,135 908 36,409 147,726
14 Oregon Common Gas Eff 88,162 30,519 118,681
15 WPNG HEWtr Htrs-Oregon 248,874 19,863 268,737
16 WPNG HE Furnaces 1,467,548 259,194 1,726,742
17 WPNG CA RES L/l-P -169,899 var 190,837 -360,736
18 WPNG OR Res Low 1 196,739 908 11,549 185,190
19 Regulatory-Sched 67 263,484 908 33,067 230,417
20 Reg-Water Heat Conv 1,338,003 908 152,358 1,185,645
21 Reg-Space/Water Con 5,470,734 908 704,560 4,766,174
22 Reg-Elec Comm/Ind 896,167 908 116,375 779,792
23 Reg-Gas Wzn Res 1,339,014 908 153,145 1,185,869
24 Reg-L/I Elec/Gas 447,947 908 49,738 398,209
25 Reg-ElecManuf Home 382,763 908 48,985 333,778
26 Reg-Comm/Ind Gas 155,419 908 19,599 135,820
27 Reg-Gas Res Appl Ef 1,818,793 908 208,179 1,610,614
28 Reg-Gas Res Showerhead 192,658 908 55,047 137,611
29 Reg Elect Res Wzn 67,521 908 8,644 58,877
30 Reg L/1 Elec Wzn 110,039 908 14,099 95,940
31 Reg Elec Res Shwr 96,675 908 37,936 58,739
32 Reg C/I Elec Fuel 263,656 908 34,221 229,435
33 Reg Gas A.E.Wtr 259,414 908 74,130 185,284
34 Reg Low income Gas Wzn 450,835 908 56,634 394,201
35
36 Sandpoint DSR -PPL 967,127 908 113,387 853,740
37
38 Gas Plant
I 39 Hamilton Street Bridge Site 108,137 var 260,657 -152,520
40
41 Electric Plant
42 Post Falls No Channel Study 49,984 1,007 50,991
43
44 Easy Pay Billing CS -531,496 228,071 -303,425
45
46 Lake CDA Issues 232,990 89,002 321,992
47 Misc.Work in Progress
Deferred Regulatory Öomm.48 Expenses (See pages 350 -351)
49 TOTAL 109,424,216 81,406,921
FERC FORM NO.1 (ED.12-94)Page 233.1
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
ACCUMULATED DEFERRED INCOMETAXES (Account 190)
1.Report the information called for below concerning the respondent's accounting for deferred income taxes.
2.At Other (Specify),include deferrals relating to other income and deductions.
Line bescription and Location Balance of Begining Balance at End
No of Year of Year
(a)(b)(c)
1 Electnc
2 9,583,164 11,862,009
3
4
5
6
7 Other
8 TOTAL Electric (Enter Total of lines 2 thru 7)9,583,164 11,862,009
9 Gas
10 -960,359 1,907,787
11
12
13
14
15 Other
16 TOTAL Gas (Enter Total of lines 10 thru 15 -960,359 1,907,787
17 Other 18,422,137 23,825,508
18 TOTAL (Acct 190)(Total of lines 8,16 and 17)27,044,942 37,595,304
Notes
OCI Adjustment for 2002 related to SERP and Pension plans was booked on the General Ledger 2/28/2003.The 10k
reflects the journal entry so various accounts,including the 190,have been adjusted to reflect this entry.
The total amount booked to the 190.10 is a debit in the amount of $9,729,514.Of this amount,$9,478,869 is
related to Pension and $250,645 is related to SERP.
FERC FORM NO.1 (ED.12-88)Page 234
This Page Intentionally Left Blank
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original (Mo,Da,Yr)Dec.31,2002AvistaCorp(2)A Resubmission 04/30/2003
CAPITAL STOCKS (Account 201 and 204)
1.Report below the particulars (details)called for concerning common and preferred stock at end of year,distinguishing separate
series of any general class.Show separate totals for common and preferred stock.If information to meet the stock exchange reporting
requirement outlined in column (a)is available from the SEC 10-K Report Form filing,a specific reference to report form (i.e.,year and
company title)may be reported in column (a)provided the fiscal years for both the 10-K report and this report are compatible.
2.Entries in column (b)should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line Class and Series of Stock and Number of shares Par or Stated Call Price at
No.|Name of Stock Series Authorized by Charter Value per share End of Year
(a)(b)(c)(d)
1 Account 201 -Common Stock issued
2 No Par Value 200,000,000
3
4 TOTAL_COM 200,000,000
5
6
7 Account 204 -Preferred Stock issued 10,000,000
8
9 $6.95 Series K Mandatorily Redeemable 100.00
10 Cumulative
11
12
13 TOTAL PRE 10,000,000
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED.12-91)Page 250
Name of Respondent This Report Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp.(2)A Resubmission 04/30/2003 '
CAPITAL STOCKS (Account 201 and 204)(Continued)
3.Give particulars (details)concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4.The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5.State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details)in column (a)of any nominally issued capital stock,reacquired stock,or stock in sinking and other funds which
is pledged,stating name of pledgee and purposes of pledge.
OUTSTANDING PERBALANCE SHEET HELD BY REEPONDENT Line(Total amount outstanding without reduction
for amounts held by respondent)AS REACQUIREDSTOCK (Account 217)IN SINKING AND OTHER FUNDS No.
$hares Amount Šhares 'Óost $hares Amount(e)(f)(g)(h)(i)(j)
1
48,044,208 623,092,000 2
3
48,044,208 623,092,000 4
5
6
7
8
332,500 33,250,000 9
10
11
12
332,500 33,250,000 13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED.12-88)Page 251
Name of Respoient This Re ort Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
CAPITAL STOCK EXPENSE (Account 214)
1.Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2.If any change occurred during the year in the balance in respect to any class or series of stock,attach a statement giving particulars
(details)of the change.State the reason for any charge-off of capital stock expense and specify the account charged.
Line 'Class and Series of Štock Balance at End of Year
No.(a)(b)
1 Common Stock -Public Issue 8,318,679
2 Shares issued under provisions of Respondant's Dividend Reinvestment and Stock Purchase Plan 442,144
3 Shares issued under provisions of Respondant's Employee Stock Purchase Plan 74,839
4 Common Stock -401k 215,137
5 Common Stock -Periodic Offering Program (POP)599,768
6 $6.95 Preferred Stock,Series K 2,089,391
7 Common Stock Split 187,872
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22 TOTAL 11,927,830
FERC FORM NO.1 (ED.12-87)Page 254b
This Page Intentionally Left Blank
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp(2)A Resubmission 04/30/2003
LONG-TERM DEBT (Account 221,222,223 and 224)
1.Report by balance sheet account the particulars (details)concerning long-term debt included in Accounts 221,Bonds,222,
Reacquired Bonds,223,Advances from Associated Companies,and 224,Other long-Term Debt.
2.In column (a),for new issues,give Commission authorization numbers and dates.
3.For bonds assumed by the respondent,include in column (a)the name of the issuing company as well as a description of the bonds.
4.For advances from Associated Companies,report separately advances on notes and advances on open accounts.Designate
demand notes as such.Include in column (a)names of associated companies from which advances were received.
5.For receivers,certificates,show in column (a)the name of the court -and date of court order under which such certificates were
issued.
6.In column (b)show the principal amount of bonds or other long-term debt originally issued.
7.In column (c)show the expense,premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8.For column (c)the total expenses should be listed first for each issuance,then the amount of premium (in parentheses)or discount.
Indicate the premium or discount with a notation,such as (P)or (D).The expenses,premium or discount should not be netted.
9.Furnish in a footnote particulars (details)regarding the treatment of unamortized debt expense,premium or discount associated with
issues redeemed during the year.Also,give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Series of Obligation,Coupon Rate Principal Amount Total expense,
No.(For new issue,give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 Acct.221 -Bonds:
2 Secured Medium Term Notes $650,000,000 4,130,555
3 (Premium)50,220
4
5 Pollution Control Revenue Bonds:
6 6%Series due 2023 4,100,000 345,385
7 Colstrip 1999A due 2032 66,700,000 2,182,462
8 (Premium)1,334,000
9 Colstrip 1999B due 2034 17,000,000 565,288
10 (Premium)340,000
11
12 SUBTOTAL 87,800,000 8,947,910
13
14 Acct.222 -Reacquired Bonds
15
16 Acct.223 -Advances from Associated Companies
17
18 Acct.224 -Other Long-term Debt
19
20 Notes Payable -Banks (local)$225,000,000 2,844,500
21
22 Commercial Paper
23
24 Unsecured Senior Notes 400,000,000 9,128,000
25 (Discount)2,716,000
26
27 Medium Term Notes $1,000,000,000 6,197,873
28 (Premium)70,000
29 Long Term Curent
30 Notes Payable to Various Parties
31 Preferred Trust Securities 60,000,000 5,960,160
32 50,000,000 3,633,783
33 TOTAL 597,800,000 39,498,226
FERC FORM NO.1 (ED.12-96)Page 256
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
LON 3-TERM DEBT (Account 221,222,223 and 224)(Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11.Explain any debits and credits other than debited to Account 428,Amortization and Expense,or credited to Account 429,Premium
on Debt -Credit.
12.In a footnote,give explanatory (details)for Accounts 223 and 224 of net changes during the year.With respect to long-term
advances,show for each company:(a)principal advanced during year,(b)interest added to principal amount,and (c)principle repaid
during year.Give Commission authorization numbers and dates.
13.If the respondent has pledged any of its long-term debt securities give particulars (details)in a footnote including name of pledgee
and purpose of the pledge.
14.If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year,describe such securities in a footnote.
15.If interest expense was incurred during the year on any obligations retired or reacquired before end of year,include such interest
expense in column (i).Explain in a footnote any difference between the total of column (i)and the total of Account 427,interest on
Long-Term Debt and Account 430,Interest on Debt to Associated Companies.
16.Give particulars (details)concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD Uutstanding--LineNominalDateMDatun
Date From Date To
roeda rnon d nh bhyout IntereAsor Year No.
1
313,500,000 22,235,332 2
3
4
5
12/18/1984 12/01/2014 12/18/1984 12/01/2014 4,100,000 246,000 6
9/01/1999 10/01/2032 9/01/1999 10/01/2032 66,700,000 3,335,000 7
8
9/01/1999 3/01/2034 9/01/1999 3/01/2034 17,000,000 872,161 9
10
i 11
401,300,000 26,688,493 12
13
14
15
16
17
18
19
30,000,000 2,967,548 20
21
22
23
341,528,874 35,337,708 24
25
26
232,250,000 22,478,645 27
28
29
30
01/23/1997 01/15/2037 01/31/1997 12/31/2036 60,000,000 4,725,000 31
06/03/1997 06/01/2037 06/30/1997 05/31/2037 40,000,000 986,363 32
1,105,078,874 93,183,757 33
FERC FORM NO.1 (ED.12-96)Page 257
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
1.Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals.Include in the reconciliation,as far as practicable,the same detail as furnished on Schedule M-1 of the tax return for
the year.Submit a reconciliation even though there is no taxable income for the year.Indicate clearly the nature of each reconciling amount.
2.If the utility is a member of a group which files a consolidated Federal tax return,reconcile reported net income with taxable net income as if a
separate return were to be field,indicating,however,intercompany amounts to be eliminated in such a consolidated return.State names of group
member,tax assigned to each group member,and basis of allocation,assignment,or sharing of the consolidated tax among the group members.
3.A substitute page,designed to meet a particular need of a company,may be used as Long as the data is consistent and meets the requirements of
the above instructions.For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line Particulars (Details)Amount
No.(a)(b)
1 Net income for the Year (Page 117)31,306,753
2
3
4 Taxable Income Not Reported on Books
5 6 782 579
6
7
8
9 Deductions Recorded on Books Not Deducted for Return
10 66,339,514
11 Federal IncomeTax 37,736,923
12 Deferred income Tax -7,898,717
13 Investment Tax Credit -49,308
14 Income Recorded on Books Not Included in Return
15 47,025,686
16 Equity in Sub Earnings (Income)/Loss 4,212,474
17
18
19 Deductions on Return Not Charged Against Book Income
20 -77,636,119
21
22
23
24
25
26
27 Federal Tax Net Income 107,819,785
28 Show Computation of Tax:37,736,923
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (ED.12-96)Page 261
This Page Intentionally Left Blank
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp.(2)A Resubmission 04/30/2003 '
TAXES ACCRUED,PREPAID AND CHAHGED DURING YEAR
1.Give particulars (details)of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year.Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged.If the
actual,or estimated amounts of such taxes are know,show the amounts in a footnote and designate whether estimated or actual amounts.
2.Include on this page,taxes paid during the year and charged direct to final accounts,(not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d)and (e).The balancing of this page is not affected by the inclusion of these taxes.
3.Include in column (d)taxes charged during the year,taxes charged to operations and other accounts through (a)accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year,and (c)taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
!4.List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
I
Line Kind of Tax BALANCE AT BEGINNING OF YEAR C aaresed aieds Adjust-
No.(See instruction 5)Taxes Accrued 'Prepaid1axes During During ments(Account 236)(Include in Account 165)Year Year
(a)(b)(c)(d)(e)(f)
1 FEDERAL:
2 Income Tax (989-1996)-587,439
3 Income Tax (1997)2,043,665 -2,043,665
4 Income Tax (1998)-905,998 868,086
5 Income Tax (1999)-2,233,598 -78,533 1,216,192
6 Income Tax (2000)-370,301 2,898,190 10,366,392
7 Income Tax (2001)-30,392,782 12,456,564 -10,366,338
8 Income Tax (2002)37,736,923 -17,206,503
9 Unemployment Ins 2001 8,377 -8,377
10 FICA (2001)-23,857 23,857
11 FICA (2002)7,791,912 7,789,319
12 Retained Earnings-ESOP -408,268 408,268
13 Retained Earnings-ESOP -329,623 329,623
14 Retained Earnings-ESOP -147,175 -737,891
15 Retained Earnings-ESOP -419,065
16 Retained Earnings-ESOP -141,026
17 Retained -139,205
18 Total Federal -33,907,090 45,405,110 5,859,037 40,667
19
20 STATE OF WASHINGTON:
21 Property Tax (2000)485,660
22 Property Tax (2001)8,954,826 -537,213 8,475,227 6
23 Property Tax (2002)9,966,072 1,442
24 Excise Tax (2001)2,132,526 1,803,110
25 Excise Tax (2002)20,169,667 18,523,789
26 Gas Surcharge -8,734 23,047 14,314
27 Unemployment Ins.(2001)2,426 -2,426
28 Unemployment Ins.(2002)766,052 766,052
29 Motor Vehicle (2002)27,818 27,818
30 Total Washington 11,566,704 30,413,017 29,611,752 6
31
32 STATE OF IDAHO:
33 Income Tax (1997-2000)855,431
34 Income Tax (2001)-3,085,967
35 Income Tax (2002)1,343,462 593,961
36 Property Tax (2000)-383
37 Property Tax (2001)2,287,690 2,287,643
38 Property Tax (2002)5,149,005 2,583,035
39 Excise Tax (2000)-8,056
40 Excise Tax (2001)-54,473
41 TOTAL -20,229,945 114,399,073 71,687,563 40,613
FERC FORM NO.1 (ED.12-96)Page 262
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
TAXES ACCEUED,PREPAID AND CHARGED DUHING YEAR (Continued)
5.If any tax (exclude Federal and State incometaxes)-covers more then one year,show the required information separately for each tax year,
identifying the year in column (a).
6.Enter all adjustments of the accrued and prepaid tax accounts in column (f)and explain each adjustment in a foot-note.Designate debit adjustments
by parentheses.
7.Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pendingtransmittalofsuchtaxestothetaxingauthority.
8.Report in columns (i)through (I)how the taxes were distributed.Report in column (l)only the amounts charged to Accounts 408.1 and 409.1pertainingtoelectricoperations.Report in column (1)the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments andamountschargedtoAccounts408.2 and 409.2.Also shown in column (I)the taxes charged to utility plant or other balance sheet accounts.
9.For any tax apportioned to more than one utility department or account,state in a footnote the basis (necessity)of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items Adjustments to Ret.Other No.Account 236)(Incl.in Account 165)(Account 408.1,409.1)(Account 409.3)Earnings (Account 439)
(g)(h)(i)(j)(k)(I)
1
-587,439 2
3
-37,912 4
-938,867 5
7,097,901 6
-53,215,684 7
54,943,426 8
25,158,719 12,578,204 9
-8,377 10
2,594 23,857 11
7,703,905 12
13
-885,066 14
-419,065 15
-141,026 16
-139,205 -139,205 17
5,679,657 25,158,719 20,158,384 18
19
20
485,660 21
-57,614 -274,217 -262,996 22
9,964,632 7,978,208 1,984,994 23
329,416 24
1,645,877 11,595,728 8,573,939 25
23,047 26
-2,426 27
766,052 28
27,818 29
12,367,971 19,299,719 11,110,428 30
31
855,431
-3,085,967 34
749,501 1,343,462 35
-383 36
47 37
2,565,970 4,316,245 832,760 38
-8,056 39
-54,473 40
22,522,183 58,458,643 56,079,796 41
FERC FORM NO.1 (ED.12-96)Page 263
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TAXES ACCRUED,PREPAIDAND CHAHGED DURING YEAR
1.Give particulars (details)of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year.Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged.If the
actual,or estimated amounts of such taxes are know,show the amounts in a footnote and designate whether estimated or actual amounts.
2.Include on this page,taxes paid during the year and charged direct to final accounts,(not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d)and (e).The balancing of this page is not affected by the inclusion of these taxes.
3.Include in column (d)taxes charged during the year,taxes charged to operations and other accounts through (a)accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year,and (c)taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4.List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Line Kind of Tax BALANCE AT BE 31NNING OF YEAR C aaresed aied Adjust-
No.(See instruction 5)Ìaxes Accrued Prepaid Ìaxes Dunng During ments(Account 236)(Include in Account 165)Year Year
(a)(b)(c)(d)(e)(f)
1 Excise Tax (2002)1,869 9,004
2 Unemployment Ins (2001)29,268 -29,268
3 Unemployment Ins.(2002)12,651 12,651
4 Motor Vehicle Ins.(2002)32,849 32,849
5 Irrigation Credits (2002)-3,616 3,747 132
6 KWH Tax (2001)46,662 -29,766 16,896
7 KWH Tax (2002)402,361 360,859
8 Franchise Tax (2002)681,486 2,998,074 3,046,678
9 Total Idaho 748,042 9,884,984 8,943,708
10
11 STATE OF MONTANA:
12 Income Tax (1996-2000)369,410 -246,347
13 Income Tax (2001)-1,186,912
14 Income Tax (2002)595,199 525,211
15 Property Tax (1999)-93,657
16 Property Tax (2000)-46,114
17 Property Tax (2001)2,781,455 2,780,001
18 Property Tax (2002)5,973,731 2,989,231
19 Unemployment Ins (2001)5,473 -5,473
20 Unemployment Ins (2002)4,573 4,573
21 KWH Tax (2001)275,333 -61,419 213,915
22 KWH Tax (2002)1,100,654 896,080
23 Motor Vehicle (2002)8,393 8,393
24 Consumer Council Tax -87,266 87,690 423
25 Public Commission Tax -18 .732 714
26 Total Montana 2,017,704 7,704,080 7,172,194
27
28 STATE OF OREGON:
29 IncomeTax (1995)-24,207
30 Income Tax (1999)214,635
31 Income Tax (2000)-158,916
32 Income Tax (2001)-854,575 -90
33 Income Tax (2002)347,806 131,690
34 Property Tax (1999-2000)55,143
35 Property Tax (2001)-580,573 651,504 50,432
36 Proprty Tax (2002)562,157 1,033,598
37 Unemployment Ins (2001)8,108 -8,108
38 Unemployment Ins.(2002)22,643 22,643
39 Motor Vehicle (2002)2,343 2,343
40 Busn Energy Tax Credit -414,235
41 TOTAL -20,229,945 114,399,073 71,687,563 40,613
FERC FORM NO.1 (ED.12-96)Page 262.1
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TAXES ACCEUED,PREPAID AND CHARGED DUHING YEAR (Continued)
5.If any tax (exclude Federal and State income taxes)-covers more then one year,show the required information separately for each tax year,
identifying the year in column (a).
6.Enter all adjustments of the accrued and prepaid tax accounts in column (f)and explain each adjustment in a foot-note.Designate debit adjustments
I by parentheses.
7.Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8.Report in columns (i)through (I)how the taxes were distributed.Report in column (1)only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations.Report in column (I)the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2.Also shown in column (I)the taxes charged to utility plant or other balance sheet accounts.
9.For any tax apportioned to more than one utility department or account,state in a footnote the basis (necessity)of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary items Adjustments to Ret.Other No.Account 236)(Incl.in Account 165)(Account 408.1,409.1)(Account 409.3)Earnings (Account 439)
(g)(h)(i)(j)(k)(I)
-7,135 1,236 633 1
-29,268 2
12,651 3
32,849 4
3,747 5
-29,766 6
41,502 402,361 7
632,882 1,660,406 1,337,668 8
1,689,319 6,350,482 3,534,502 9
10
11
615,757 12
-1,186,912 13
69,988 595,199 14
-93,657 15
-46,114 16
1,454 5,973,731 17
2,984,500 18
-5,473 19
4,573 20
-61,419 21
204,574 1,100,654 22
8,393 23
87,690 24
731 25
2,549,590 5,973,731 1,730,348 26
27
28
-24,207 29
214,635 30
-158,916 31
-854,485 32
216,117 347,807 33
55,143 34
20,499 651,504 35
-471,442 15,586 546,570 36
-8,108 37
22,643 38
2,343 39
-414,235 40
22,522,183 58,458,643 56,079,796 41
FERC FORM NO.1 (ED.12-96)Page 263.1
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TAXES ACCRUED,PREPAIDAND CHAHGED DURING YEAR
1.Give particulars (details)of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year.Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged.If the
actual,or estimated amounts of such taxes are know,show the amounts in a footnote and designate whether estimated or actual amounts.
2.Include on this page,taxes paid during the year and charged direct to final accounts,(not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d)and (e).The balancing of this page is not affected by the inclusion of these taxes.
3.Include in column (d)taxes charged during the year,taxes charged to operations and other accounts through (a)accruals credited to taxes accrued,
(b)amounts creditéd to proportions of prepaid taxes chargeable to current year,and (c)taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4.List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Line Kind of Tax BALANCE AT BEGINNING OF YEAR C ar ed aieds Adjust-
No.(See instruction 5)Taxes Accrued Prepaid Taxes During During ments(Account 236)(Include in Account 165)Year Year(a)(b)(c)(d)(e)(1)
1 Busn Energy Tax Credit -34,244
2 Busn Energy Tax Credit -55,790
3 Franchise Tax (2002)195,353 2,663,664 2,637,589
4 Total Oregon -1,593,511 4,186,219 3,878,205
5
6 STATE OF CALIFORNIA:
7 income Tax (1996-2000)146,857 -11,566
8 Income Tax (2001)-142,429
9 Income Tax 2002 61,665 34,802
10 Property Tax (1999)128,479
11 Property Tax (2000-2001)-59,094 63,000
12 Property Tax (2002)53,934 107,920
13 Excise Tax (1999-2000)-2,163
14 Excise Tax (2001)100 134
15 Unemployment ins (2001)61,000 -61,000
16 Motor Vehicle (2002)5,175;5,175
17'Franchise Tax (2002)293,925 577,706 313,884
18 California PUC Tax -194 554 360
19'Califomia Gas Surcharge -187,659 -187,659
20 Total California 238,822 701,034 263,050
21
22 STATE OF ARIZONA:
23 Income Tax (2001)-1,656 2,510 -60
24 Total Arizona -1,656 2,510 -60
25
26 STATE OF TEXAS
27 Unemploymnt Ins
28 Unemployment Ins (2001)1,208 -1,208
29 Total Texas 1,208 -1,208
30
31 STATE OF KENTUCKY
32 Unemploymnt Ins
33 Unemployment Ins (2001)-725 725
34 Total Kentucky -725 725
35
36 STATE OF VIRGINIA
37 Unemploymnt ins
38 Unemployment Ins (2001)200 -200
39 Total Virginia 200 -200
40
41 TOTAL -20,229,945 114,399,073 71,687,563 40,613
FERC FORM NO.1 (ED.12-96)Page 262.2
Name of Respondent This Re ort Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TAXES ACCE UED,PREPAIDAND CHARGED DUHING YEAR (Continued)
5.If any tax (exclude Federal and State income taxes)-covers more then one year,show the required information separately for each tax year,
identifying the year in column (a).
6.Enter all adjustments of the accrued and prepaid tax accounts in column (f)and explain each adjustment in a foot-note.Designate debit adjustments
I by parentheses.
7.Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8.Report in columns (i)through (I)how the taxes were distributed.Report in column (l)only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations.Report in column (1)the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2.Also shown in column (l)the taxes charged to utility plant or other balance sheet accounts.
9.For any tax apportioned to more than one utility department or account,state in a footnote the basis (necessity)of apportioning such tax.
BALANCE AT ND OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items Adjustments to Het Other No.Account 236)(Incl.in Account 165)(Account 408.1,409.1)(Account 409.3)Earnings (Account 439)
(g)(h)(i)(j)(k)(l)
-34,243 -55,790 1
-55,790 2,663,664 2
221,428 3
-1,285,496 15,586 4,170,633 4
5
6
158,423 7
-142,429 8
26,863 61,665 9
128,479 10
3,906 63,000 11
-53,986 53,934 12
-2,163 13
-34 14
-61,000 15
5,175 16
557,747 577,706 17
468 18
240,562 19
676,806 941,510 20
21
22
-4,226 23
-4,226 24
25
26
27
-1,208 28
-1,208 29
30
31
725 3
725 34
35
36
37
-200 38
-200 39
40
22,522,183 58,458,643 56,079,796 41
FERC FORM NO.1 (ED.12-96)Page 263.2
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)§AnOriginal (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TAXES ACCRUED,PREPAID AND CHAHGED DURING YEAR
1.Give particulars (details)of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year.Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged.If the
actual,or estimated amounts of such taxes are know,show the amounts in a footnote and designate whether estimated or actual amounts.
2.Include on this page,taxes paid during the year and charged direct to final accounts,(not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d)and (e).The balancing of this page is not affected by the inclusion of these taxes.
3.Include in column (d)taxes charged during the year,taxes charged to operations and other accounts through (a)accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year,and (c)taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4.List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Line i Kind of Tax |BALANCE AT BEGINNING OF YEAR C arŸed 'ÉÎaieds Adjust-
No.(See instruction 5)iaxes Accrued Þrepaid Taxes Dunng During ments(Account 236)(Include in Account 165)Year Year
(a)(b)(c)(d)(e)(f)
1 STATE OF WYOMING
2 Unemployment Ins
3 Unemployment Ins (2001)582 -582
4 Total Wyoming 582 -582
5
6 STATE OF FLORIDA
I
7 Unemployment Ins (2000)
8 Unemployment ins (2001)-370 370
9 Total Florida -370 370
10 STATE OF NEW YORK
11 Unemployment Ins (2000)
12 Unemployment Ins (2001)300 -300
13 Total New York 300 -300
14
15 COUNTY &MUNICIPAL
16 Occupation 719,110 16,067,719 15,938,257
17 Forrest Fire Protection -294 294
18 Greenacres Irrigation
19 City of Spokane PBIA 18,530 18,530
20 WA Dept of Natural -18,930 19,250 320
21 Spokane Utility Tax
22 Misc.1,347 -1,357
23 Total County 701,233 16,104,436 15,957,107
24
25 STATE OF ILLINOIS
26 Unemploymnt Ins.1999-2000
27 Unemployment Ins.2001 270 -270
28 Total Illinois 270 -270
29
30 STATE OF UTAH
31 Unemployment Ins.2001 -1,658 1,658
32 Total Utah -1,658 1,658
33
34
35
36
37
38
39
40
41 TOTAL -20,229,945 114,399,073 71,687,563 40,613
FERC FORM NO.1 (ED.12-96)Page 262.3
Name of Respondent This Re ort Is:Date of Report Year of Report
Avista Cor (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TAXES ACCEUED,PREPAIDAND CHARGED DUHING YEAR (Continued)
5.If any tax (exclude Federal and State income taxes)-covers more then one year,show the required information separately for each ta× year,
dentifying the year in column (a).
6.Enter all adjustments of the accrued and prepaid tax accounts in column (f)and explain each adjustment in a foot-note.Designate debit adjustments
by parentheses.
7.Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8.Report in columns (i)through (I)how the taxes were distributed.Report in column (l)only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations.Report in column (1)the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2.Also shown in column (I)the taxes charged to utility plant or other balance sheet accounts.
9.For any tax apportioned to more than one utility department or account,state in a footnote the basis (necessity)of apportioning such tax.
BALANCE AT IND OF YEAR DISTRIBUTIONOF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items Adjustments to Ret.Other No.
Account 236)(Incl.in Account 165)(Account 408.1,409.1)(Account 409.3)Earnings (Account 439)
(g)(h)(i)(j)(k)(I)
1
2
-582 3
-582 4
5
6
370 7
8
370 9
10
I -300 11
12
-300 13
|
14
15
848,569 1,660,406 14,395,724 16
294 17
18
18,530 19
19,250 20
21
848,5 1,660,406 14,433,798
24
25
-270 26
27
-270 28
29
30
1,658 31
1,658 32
33
34
35
36
37
38
39
40
22,522,183 58,458,643 56,079,796 41
FERC FORM NO.1 (ED.12-96)Page 263.3
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)g An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
ACCUMULA ED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Report below information applicable to Account 255.Where appropriate,segregate the balances and transactions by utility and
nonutility operations.Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i)
1
veercoverw
2 3%
3 4%
4 7%
5 10%
6
7
8 TOTAL
9 Other (List separately
and show 3%,4%,7%,äffÈ k
10%and TOTAL)
10 Gas Propertry (10%)718,884 1411.40 49,30E I
11
12 TOTAL PROPERTY 718,884 49,30E
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO.1 (ED.12-89)Page 266
Name of Respondent This Re ort is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
ACCUMULATED DEFERRED INVESTMENT TAX CRED TS (Account 255)(continued)
BalarceeaarEnd ASÑoeœÞ riod ADJUSTMENT EXPLANATION Line
to Income(h)(i)
2
3
4
5
6
7
669,576 10
11
669,576 12
13
14
15
16
17
18
19
20
21
22
I 23
24
25
26
27
28
29
30
31
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO.1 (ED.12-89)Page 267
Name of Respondent This Re ort Is:Date of Report Year of Report
Avista Cor .
(1)An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
O HER DEFFERED CREDITS (Account 253)
1.Report below the particulars (details)called for concerning other deferred credits.
2.For any deferred credit being amortized,show the period of amortization.
3.Minor items (5%of the Balance End of Year for Account 253 or amounts less than $10,000,whichever is greater)may be grouped by classes.
Line Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
Account
(a)(b)(c)(d)(e)(f)
1 Unearned interest -Customer
2 wiring &conversions 253.00 18 419 3,059 11,100 8,059
3
4 Deferred revenue prepayment -
5 Pacific Walla Walla/Enterprise
6 Amort =19 yrs 253.08 70,290 456 9,372 60,918
7
8 BPA C&RD Receipts 253.10 65,700 394,200 394,200 65,700
9
10 Trust Fund -Centralia 253.11 852,529 128 11,608 49,497 890,418
12 Rathdrum Refund 253.12 611,621 550 33,823 577,798
13 Amort =25 years
14
15 Supplemental Executive 10,362,946 426 822,973 3,001,426 12,541,399
16 Retirement Plan 253.29
17
18 Deferred PGE Contract 253.70 30,597,960 30,597,960
19
20 Mark to Market 253.74 159,418,185 557 1,157,747,883 998,329,698
21
22 Gain on Sale and leaseback 2,614,560 931 261,456 2,353,104
23 of Building (Amortization period
24 is 25 years)253.85 &253.86
25
26 WA Clark Fork Relicensing 253.88 114,550 171 5,414,550 5,300,000
27 ID Clark Fork Relicensing 253.89 -605,387 171 569,152 783,190 -391,349
28
29 Deferred Compensation 90,91,92 12,746,394 131 2,182,300 1,083,686 11,647,780
30
31 Long Term Incentive Plan 253.93 57,103 920/417 94,606 37,503
32
33 FAS5 Mark to Market 253.95 13,653,729 120,921,889 109,219,739 1,951,579
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL 230,560,198 1,319,064,831 1,118,210,039 29,705,406
FERC FORM NO.1 (ED.12-94)Page 269
This Page Intentionally Left Blank
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
ACCUMULATE3 DEFFERED INCOMETAXES -OTE ER PROPERTY (Account 282)
1.Report the information called for below concerning the respondent's accounting for deferred income taxes rating to property not
subject to accelerated amortization
2.For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line Account Balance at
No.Beginningof Year Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
(a)(b)(c)(d)
1 Account 282
2 Electric 161,842,987 5,043,434
3 Gas 33,103,340 3,894,155
4 General Common 12,990,001 -1,276,087
5 TOTAL (Enter Total of lines 2 thru 4)207,936,328 7,661,502
6 Non-operating 2,293,161 98,714
7
8
9 TOTAL Account 282 (Enter Total of lines 5 thru 210,229,489 7,760,216
10 Classification of TOTAL
11 Federal Income Tax 204,565,233 8,642,206
12 State income Ta× 5,664,256 881,990
13 Local Income Tax
NOTES
FERC FORM NO.1 (ED.12-96)Page 274
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
ACCUMULATED DEFERRED INCOlvE TAXES -OTHER PROPERTY (Account 282)(Continued)
3.Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Amounts Debited Amounts Credited Debits Credits Balance at Line
I to Account 410.2 to Account 411.2 Account Amount Account Amount End of Year No.
Credited Debited(e)(f)(g)(h)(¡)(k)
166,886,421 2
36,997,49E 3
11,713,914 4
215,597,83C 5
2,391,875 6
7
8
217,989,70E 9
10
213,207,43E 11
6,546,24E 12
13
NOTES (Continued)
ERC FORM NO.1 (ED.12-96)Page 275
Name of Respondent This Report is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
ACCUMULATED DEFFERED INCOME TAXES -OTHER (Account 283)
1.Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts
recorded in Account 283.
2.For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line Account Balance at Amounts Debited Amounts Óredited
No.(a)
Beginning of Year to Accou t 410.1 to Acco t 411.1
2 Electric
3 Electric 130,520,472 -9,734,409 440,304
4
5
6
7
8
9 TOTAL Electric (Total of lines 3 thru 8)130,520,472 -9,734,409 440,304
10 Gas nam mmmew .mm.m.mm .mmromanemummmw-ww-netw «-r ---mm
11 Gas 17,276,605 -11,919,054
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)17,276,605 -11,919,054
18 Other 139,550,762 3,706,754
19 TOTAL (Acct 283)(Enter Total of lines 9,17 and 18)287,347,839 -17,946,709 440,304
20 Classification of TOTAL
21 Federal Income Tax 287,347,839
22 State Income Tax
23 Local Income Tax
NOTES
FERC FORM NO.1 (ED.12-96)Page 276
Name of Respondent This Re ort Is:Date of Report Year of Report
Avista Cor (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
ACCUMULATED DEFERRED INCOMETAXES -OTHEH (Account 283)(Continuec)
3.Provide in the space below explanations for Page 276 and 277.Include amounts relating to insignificant items listed under Other.
4.Use footnotes as required.
CHANGES DURINGYEAR ADJUSTMENTS
Amounts Debited Amounts Credited Debits Credits Balance at Line
to Account 410.2 to Account 411.2 Account Amount Account Amount End of Year No.Credited Debited(e)(f)(g)(h)(i)(j)(k)
3,005,188 123,350,947 3
4
5
6
7
8
3,005,188 123,350,947 9
323,412 190.10 161,852 5,519,111 11
190.88 11,933 -11,933 12
13
14
15
16
323,412 173,785 5,507,178 17
182.31 &9,898,399 133,359,117 18
3,328,600 10,072,184 262,217,242 19
20
21
22
23
NOTES (Continued)
FERC FORM NO.1 (ED.12-96)Page 277
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
Ol HER REGULATORY LIABILITIES (Account 254)
1.Reporting below the particulars (Details)called for concerning other regulatory liabilities which are created through the rate-making
actions of regulatory agencies (and not includable in other amounts)
2.For regulatory Liabilities being amortized show period of amortization in column (a).
3.Minor items (5%of the Balance at End of Year for Account 254 or amounts less than $50,000,whichever is Less)may be grouped
by classes.
Line Description and Purpose of DEBITS Balance at
No Other Regulatory Liabilities Account Amount Credits End of Year
Credited
(a)(b)(c)(d)(e)
1 Centralia Sale 254.11,028 &038 407.41 1,494,265 176,335 8,438,779
2
3 FAS 109 -Accounting for Income Taxes 254.18 190.18 53,100 48,709 360,576
4
5 Nez Perce -Regulatory Liability 254.22 186.80/557.2 16,506 918,950 902,444
6
7 Rate Base Credit -WA 254.43 253.70 2,915,400
8
9 BPA Residential Exchange 254.45,028 &038 407.45 11,156,707 12,470,816 208,098
10
11 Mark to Market FAS133 -Reg Liab 254.74 176.74/245.7 3,604,007 13,868,612 10,264,605
12
13
14
15
16
17
18
19
20
21 i
22
23 '
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 19,239,985 27,483,422 20,174,502
FERC FORM NO.1 (ED.12-94)Page 278
This Page Intentionally Left Blank
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
E.ECTRIC OPERATING REVENUES (Account 400)
1.Report below operating revenues for each prescribed account,and manufactured gas revenues in total.
2.Report number of customers,columns (f)and (g),on the basis of meters,in addition to the number of flat rate accounts;except that
where separate meter readings are added for billing purposes,one customer should be counted for each group of meters added.The
-average number of customers means the average of twelve figures at the close of each month.
3.If increases or decreases from previous year (columns (c),(e),and (g)),are not derived from previously reported figures,explain any
inconsistencies in a footnote.
Line Title of Account OPERATING REVENUES
No.Amount for Year Amount for Previous Year
(a)(b)(c)
1 Sales of Electricity
2 (440)Residential Sales 196,156,154 158,846,735
3 (442)Commercial and Industrial Sales
4 Small (or Comm.)(See Instr.4)194,732,477 155,371,070
5 Large (or Ind.)(See Instr.4)68,096,108 80,433,325
6 (444)Public Street and Highway Lighting 4,682,491 3,789,565
7 (445)Other Sales to PublicAuthorities
8 (446)Sales to Railroads and Railways
9 (448)Interdepartmental Sales 900,386 630,925
10 TOTAL Sales to Ultimate Consumers 464,567,616 399,071.620
11 (447)Sales for Resale 64,082,272 480,902,532
12 TOTAL Sales of Electricity 528,649,888 879,974.152
13 (Less)(449.1)Provision for Rate Refunds
14 TOTAL Revenues Net of Prov.for Refunds 528,649,888 879,974,152
15 Other Operating Revenues
16 (450)Forfeited Discounts
17 (451)Miscellaneous Service Revenues 532,286 469,676
18 (453)Sales of Water and Water Power 58,862 415,973
19 (454)Rent from Electric Property 1,992,663 2,190,57Ô
20 (455)Interdepartmental Rents
21 (456)Other Electric Revenues 52,907,304 39,154,123
22
23
24
25
26 TOTAL Other Operating Revenues 55,491,115 42,230,348
27 TOTAL Electric Operating Revenues 584,141,003 922,204,500
FERC FORM NO.1 (ED.12-96)Page 300
Name of Respondent This Re ort is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
E _ECTRICOPERATING REVENUES(Account 400)
4.Commercial and industrial Sales,Account 442,may be classified according to the basis of classification (Small or Commercial,and
Large or Industrial)regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand.
(See Account 442 of the Uniform System of Accounts.Explain basis of classification in a footnote.)
5.See pages 108-109,Important Changes During Year,for important new territory added and important rate increase or decreases.
6.For Lines 2,4,5,and 6,see Page 304 for amounts relating to unbilled revenue by accounts.
7.Include unmetered sales.Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD AVG.NO.CUSTOMERS PER MONTH Line
Amount for Year Amount for Previous Year Number for Year Number for Previous Year No.
3,202,948 3,219,407 279,735 2 846 2
2,836,717 2,881,998 35,910 35,454 4
1,519,104 1,891,267 1,420 1,433 5
25,163 24,979 413 402 6
7
8
14,097 13,386 70 62 9
27,,5958,04259 68,Œ31,037 317,5448 314,1 10
9,813,574 14,292,341 317,594 314,241 12
13
9,813,574 14,292,341 317,594 314,241 14
Line 12,column (b)includes $2,082,153 of unbilled revenues.
Line 12,column (d)includes -13,810 MWH relating to unbilled revenues
FERC FORM NO.1 (ED.12-96)Page 301
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
SALES OF ELECTRICITY BY RATE SGHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold,revenue,average number of customer,average Kwh per
customer,and average revenue per Kwh,excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues,"Page
300-301.If the sales under any rate schedule are classified in more than one revenue account,List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule),the entries in column (d)for the special schedule should denote the duplication in number of reported
customers.
.4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
lif all billings are made monthly).
,5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line Number and I Itle of Hate schedule MWh Sold Hevenue Average Number KWh of Sales HÑÑhn e er
No-(a)(b)(c)of Cus omers Per stomer
1 RESIDENTIAL SALES (440)
2 1 Residential Service 3,131,538 182,937,565 269,161 11,634 0.0584
3 2 Residential Service
4 3 Residential Service
5 12 Res.&Farm Gen.Service 48,288 4,408,853 9,232 5,231 0.0913
6 15 MOPS II Residential
7 22 Res.&Farm Lg.Gen.Service 26,156 1,566,900 64 408,688 0.0599
8 30 Pumping-Special 110 5,488 1 110,000 0.0499
9 32 Res.&Farm Pumping Service 10,601 683,216 1,277 8,301 0.0644
10 48 Res.&Farm Area Lighting 5,438 905,276 0.1665
11 49 Area Lighting-High-Press.256 55,468 0.2167
12 56 Centralia Refund 149
13 95 Wind Power 50,382
14 72 Residential Service
15 73 Residential Service
16 74 Residential Service
17 76 Residential Service
18 77 Residential Service
19 58A Tax Adjustment -13,875
20 58 Tax Adjustment 4,991,768
21 SubTotal 3,222,387 195,591,190 279,735 11,519 0.0607
22 Residential-Unbilled -19,439 564,964 -0.0291
23 Total Residential Sales 3,202,948 196,156,154 279,735 11,450 0.0612
24
25 COMMERCIAL SALES (442)
26 2 General Service 1 65 0.0650
27 3 General Service
28 11 General Service 548,291 47,201,042 30,447 18,008 0.0861
29 13 MOPS 11 Commercial
30 16 MOPS 11 Commercial
31 19 Contract-General Service
32 21 Large General Service 1,891,198 121,386,785 4,669 405,054 0.0642
33 25 Extra Lg.Gen.Service 330,494 13,950,389 12 27,541,167 0.0422
34 28 Contract-Extra Large Serv 1,353 54,379 1 1,353,000 0.0402
35 31 Pumping Service 53,960 3,161,118 781 69,091 0.0586
36 47 Area Lighting-Sod.Vap 7,578 1,110,833 0.1466
37 49 Area Lighting-High-Press.2,114 345,119 0.1633
38 56 Centralia Refune 1,264
39 95 Wind Power 3,981
40 74 Large General Service
41 TOTAL Billed 9,827,38A 526,567,735 317,594 30,942 0.0536
42 Total Unbilled Rev.(See Instr.6)-13,81C 2,082,153 C C -0.1508
43 TOTAL 9,813,574 528,649,888 317,594 30,90C 0.0539
FERt:FORM NO.1 (ED.12-95)Page 304
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold,revenue,average number of customer,average Kwh per
customer,and average revenue per Kwh,excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues,"Page
300-301.If the sales under any rate schedule are classified in more than one revenue account,List the rate schedule and sales data under eachapplicablerevenueaccountsubheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule),the entries in column (d)for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line 'Number and i It of Hate schedule MWh ¡Old Hevenue Av rcage Nu er KP
r s
rneer Ke e Pder
1 75 Large General Service
2 76 Large General Service
3 77 General Service
4 58A Tax Adjustment -12,103
5 58 Tax Adjustment 6,415,853
6 SubTotal 2,834,989 193,618,725 35,910 78,947 0.0683
7 Commercial-Unbilled 1,728 1,113,752 0.6445
8 Total Commercial 2,836,717 194,732,477 35,910 78,995 0.0686
9
10 INDUSTRIAL SALES (442)
11 2 General Service
12 3 General Service
13 8 Lg Gen Time of Use
14 11 General Service 5,344 484,370 248 21,548 0.0906
15 16 MOPS Il Industrial
16 21 Large General Service 213,402 13,382,256 228 935,974 0.0627
17 25 Extra Lg.Gen.Service 1,201,892 48,566,177 23 52,256,174 0.0404
18 28 Contract -Extra Large Service -27,464 161,289 -0.0059
19 29 Contract Lg.Gen.Service 40,425 1 40,425,000
20 30 Pumping Service -Special 24,003 1,197,238 45 533,400 0.0499
21 31 Pumping Service 52,481 3,147,499 709 74,021 0.0600
22 32 Pumping Svc Res &Firm 4,795 279,539 166 28,886 0.0583
23 47 Area Lighting-Sod.Vap.278 35,300 0.1270
24 49 Area Lighting -High-Press 47 7,065 0.1503
25 56 Centralia Refund.
26-72 General Service
27 73 General Service '
28 74 Large General Service
29 75 Large General Service
30 76 Pumping Service
31 77 General Service
32 58A Tax Adjustment -816
33 58 Tax Adjustment 432,754
34 SubTotal 1,515,203 67,692,671 1,420 1,067,044 0.0447
35 Industrial-Unbilled 3,901 403,437 0.1034
36 Total industrial 1,519,104 68,096,108 1,420 1,069,792 0.0448
37
38 STREET AND HWY LIGHTING (444)
39 6 Mercury Vapor St.Ltg.
40 7 HP Sodium Vap.St.Ltg
41 TOTAL Billed 9,827,384 526,567,735 317,594 30,942 0.0536
42 Total Unbilled Rev.(See Instr.6)-13,81C 2,082,153 C C -0.1508
43 TOTAL 9,813,57A 528,649,888 317,594 30,90C 0.0539
FERC FORM NO.1 (ED.12-95)Page 304.1
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold,revenue,average number of customer,average Kwh per
customer,and average revenue per Kwh,excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues,"Page
300-301.If the sales under any rate schedule are classified in more than one revenue account,List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule),the entries in column (d)for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line 'Number and l itie of Rate schedule MWh Sold Revenue Average Number KWh of Sales He ne Per
No-(a)(b)I (c)of Cusd)omers Per stomer K old
1 11 General Service 176 15,930 25 7,040 0.0905
2 41 Co-Owned St.Lt.Service 337 49,693 19 17,737 0.1475
3 42 Co-Owned St.Lt.Service 17,870 4,021,898 279 64,050 0.2251
4 High-Press.Sod.Vap.
5 43 Cust-Owned St.Lt.Energy 139 12,958 3 46,333 0.0932
6 and Maint.Service
7 44 Cust-Owned St.Lt.Energy 727 78,060 29 25,069 0.1074
8 and Maint.Svce -High-Pres
9 Sodium Vapor
10 45 Cust.Owned St.Lt.Energy Svc 2,887 132,010 21 137,476 0.0457
11 46 Cust.Owned St.Lt.Energy Svc 3,027 208,966 37 81,811 0.0690
12 56 Centralia Refund
13 58 Tax Adjustment 162,976
14 SubTotal 25,163 4,682,491 413 60,927 0.1861
15 Street &Hwy Lighting-Unbilled
16 Total Street &Hwy Lighting 25,163 4,682,491 413 60,927 0.1861
17
18 OTHER SALES TO PUBLIC
19 (445)
20 None
21
22 INTERDEPARTMENTAL SALES 14,097 900,386 70 201,386 0.0639
23 58 Tax Adjustment
24 Total Interdepartmental 14,097 900,386 70 201,386 0.0639
25
26 SALES FOR RESALE (447)
27 61 Sales to Other Utilities (WA)2,051,527 61,303,397 39 52,603,256 0.0299
28 61 Sales to Other Utilities (ID)99,265 1,475,050 3 33,088,333 0.0149
29 61 Sales to Other Utilities (MT)64,753 1,303,825 4 16,188,250 0.0201
30 Total Sales for Resale 2,215,545 64,082,272 46 48,164,022 0.0289
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed 9,827,384 526,567,735 317,594 30,942 0.0536
42 Total Unbilled Rev.(See Instr.6)-13,81C 2,082,153 C C -0.1508
43 TOTAL 9,813,574 528,649,888 317,594 30,90C 0.0539
FERC FORM NO.1 (ED.12-95)Page 304.2
This Page Intentionally Left Blank
Name of Respondent This Report Is:Date of Report Year of Report
Avista Co (1)X An Original (Mo,Da,Yr)Dec.31,2002rp.(2)A Resubmission 04/30/2003
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e.,sales to purchasers other than ultimate consumers)transacted on a settlement basis other than
power exchanges during the year.Do not report exchanges of electricity (i.e.,transactions involving a balancing of debits and credits
for energy,capacity,etc.)and any settlements for imbalanced exchanges on this schedule.Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a).Do note abbreviate or truncate the name or use acronyms.Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b),enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (i.e.,the
supplier includes projected load for this service in its system resource planning).In addition,the reliability of requirements service must
be the same as,or second only to,the supplier's service to its own ultimate consumers.
LF -for tong-term service."Long-term"means five years or Longer and "firm"means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g.,the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service).This category should not be used for Long-term firm service which meets the
definition of RQ service.For all transactions identified as LF,provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF -for intermediate-term firm service.The same as LF service except that "intermediate-term"means longer than one year but Less
than five years.
SF -for short-term firm service.Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU -for Long-term service from a designated generating unit."Long-term"means five years or Longer.The availability and reliability of
service,aside from transmission constraints,must match the availability and reliability of designated unit.
IU -for intermediate-term service from a designated generating unit.The same as LU service except that "intermediate-term"means
Longer than one year but Less than five years.
Line Name of Company or PublicAuthority Statistical FERC Rate Average Actual De nand (MW)
No (Footnote Affiliations)Classifi-Schedule or Monthly Billing Avera e Avera e
cation Tariff Number Demand (MW)Monthly NC Demand Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 American Electric Power SF WSPP "C"
2 Amoco Energy Trading,Inc SF WSPP "C"
3 Aquila Canada SF EA -101-A
4 Aquila Merchant Services,Inc.SF WSPP "C"
5 Aquila Networks (W Kootenay)SF WSPP "C"
6 Benton County Public Utility District SF WSPP "C"Tariff 9
7 Bonneville Power Administration SF WSPP "C"
8 Calpine Corporation SF WSPP "C"
9 Cargill Power Markets,LLC SF WSPP "C"
10 Chelan County Public Utility Dist.No 1 SF WSPP "C"Tariff 9
11 Clatskanie Peoples PUD SF WSPP "C"
12 Cogentrix Energy Power Marketing,Inc.IF Tariff 10 VAR 0 0
13 Constellation Power Sources,Inc SF WSPP "C"
14 Conoco,Incorporated SF WSPP "C"
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0:
FERC FORM NO.1 (ED.12-90)Page 310
Name of Respondent This Re ort Is:Date of Report Year of Report
Avista Co (1)X An Original (Mo,Da,Yr)Dec.31 2002rp.(2)A Resubmission 04/30/2003 '
SALES FOR RESALE (Account 447)(Continued)
OS -for other service.use this category only for those services which cannot be placed in the above-defined categories,such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year.Describe the nature
of the service in a footnote.
AD -for Out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one.After listing all RQ sales,enter "Subtotal -RQ"
in column (a).The remaining sales may then be listed in any order.Enter "Subtotal-Non-RQ"in column (a)after this Listing.Enter
"Total"in column (a)as the Last Line of the schedule.Report subtotals and total for columns (9)through (k)
5.In Column (c),identify the FERC Rate Schedule or Tariff Number.On separate Lines,List all FERC rate schedules or tariffs under
which service,as identified in column (b),is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer)basis,enter the
average monthly billing demand in column (d),the average monthly non-coincident peak (NCP)demand in column (e),and the average
monthly coincident peak (CP)
demand in column (f).For all other types of service,enter NA in columns (d),(e)and (f).Monthly NCP demand is the maximum
metered hourly (60-minute integration)demand in a month.Monthly CP demand is the metered demand during the hour (60-minute
integration)in which the supplier's system reaches its monthly peak.Demand reported in columns (e)and (f)must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g)the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h),energy charges in column (i),and the total of any other types of charges,including
out-of-period adjustments,in column (j).Explain in a footnote all components of the amount shown in column (j).Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g)through (k)must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4),and then totaled on
the Last -line of the schedule.The "Subtotal -RQ"amount in column (g)must be reported as Requirements Sales For Resale on Page
401,line 23.The "Subtotal -Non-RQ"amount in column (g)must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours 'REVENUE Total ($)Line
Sold Demand Charges Energy harges Other harges (h+i+j)No.
(g)(h)(i)(j)(k)
104,249 2,259,361 2,259,361 1
15,444 362,116 362,116 2
21,721 556,739 556,739 3
112,822 2,604,538 2,604,538 4
857 16,268 16,268 5
510 12,320 12,320 6
40,324 950,418 950,418 7
400 10,900 10,900 8
2,000 33,200 33,200 9
295 7,225 7,225 10
320 7,520 7,520 11
7,284 63,771 212,981 276,752 12
87,926 7,983,142 7,983,142 13
16,592 284,342 284,342 14
0 0 0 0 0
2,215,545 4,671,215 55,262,915 4,148,142 64,082,272
2,215,545 4,671,215 55,262,915 4,148,142 64,082,272
FERC FORM NO.1 (ED.12-90)Page 311
Name of Respondent This Report Is:Date of Report Year of Report
Avista Cor (1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
SALES FOR RESALE (Account 4/7)
1.Report all sales for resale (i.e.,sales to purchasers other than ultimate consumers)transacted on a settlement basis other than
power exchanges during the year.Do not report exchanges of electricity (i.e.,transactions involving a balancing of debits and credits
for energy,capacity,etc.)and any settlements for imbalanced exchanges on this schedule.Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a).Do note abbreviate or truncate the name or use acronyms.Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b),enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (i.e.,the
supplier includes projected load for this service in its system resource planning).In addition,the reliability of requirements service must
be the same as,or second only to,the supplier's service to its own ultimate consumers.
LF -for tong-term service."Long-term"means five years or Longer and "firm"means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g.,the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service).This category should not be used for Long-term firm service which meets the
definition of RQ service.For all transactions identified as LF,provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF -for intermediate-term firm service.The same as LF service except that "intermediate-term"means longer than one year but Less
than five years.
SF -for short-term firm service.Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU -for Long-term service from a designated generating unit."Long-term"means five years or Longer.The availability and reliability of
service,aside from transmission constraints,must match the availability and reliability of designated unit.
IU -for intermediate-term service from a designated generating unit.The same as LU service except that "intermediate-term"means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera e Actual Demand (MW)
No.(Footnote Affiliations)C i-ySa ih ulrenb
r
DMerahr
d (MonthyN Deman Month y
CmP ernand
(a)(b)(c)(d)(e)(f)
1 Coral Power,LLC SF WSPP "C"
2 Douglas County PUD SF WSPP "C"
3 Duke Energy Trading &Marketing LLC SF WSPP "C"
4 Dynegy Power Marketing Inc.SF WSPP "C"
5 El Paso Merchant Energy LP SF WSPP "C"
6 Enmax Energy Marketing,Inc.SF WSPP "C"
7 Enron Power Marketing LF Tariff 9
8 Entergy-Koch Trading LP SF WSPP "C"
9 EPCOR Merchant &Capital US SF WSPP "C"
10 EugeneWater &Electric Board SF WSPP "C"
11 Franklin County Public Utility District SF WSPP "C"Tariff 9
12 Grant County Public Utility District SF WSPP "C"Tariff 9
13 Grays Harbor PUD SF WSPP "C"
14 IdaCorp Energy LP SF WSPP "C"Tariff 9
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED.12-90)Page 310.1
Name of Respondent This Re ort Is:Date of Report Year of RepoÑ
Avista Co (1)X An Original (Mo,Da,Yr)Dec.31 2002rp.(2)A Resubmission 04/30/2003 '
SALES FOR RESALE (Account 447)(Continued)
OS -for other service.use this category only for those services which cannot be placed in the above-defined categories,such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year.Describe the nature
of the service in a footnote.
AD -for Out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one.After listing all RQ sales,enter "Subtotal -RO"
in column (a).The remaining sales may then be listed in any order.Enter "Subtotal-Non-RQ"in column (a)after this Listing.Enter
"Total"in column (a)as the Last Line of the schedule.Report subtotals and total for columns (9)through (k)
5.In Column (c),identify the FERC Rate Schedule or Tariff Number.On separate Lines,List all FERC rate schedules or tariffs under
which service,as identified in column (b),is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer)basis,enter the
average monthly billing demand in column (d),the average monthly non-coincident peak (NCP)demand in column (e),and the average
monthly coincident peak (CP)
demand in column (f).For all other types of service,enter NA in columns (d),(e)and (f).Monthly NCP demand is the maximum
metered hourly (60-minute integration)demand in a month.Monthly CP demand is the metered demand during the hour (60-minute
integration)in which the supplier's system reaches its monthly peak.Demand reported in columns (e)and (f)must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g)the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h),energy charges in column (i),and the total of any other types of charges,including
out-of-period adjustments,in column (j).Explain in a footnote all components of the amount shown in column (j).Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g)through (k)must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4),and then totaled on
the Last -line of the schedule.The "Subtotal -RQ"amount in column (g)must be reported as Requirements Sales For Resale on Page
401,line 23.The "Subtotal -Non-RQ"amount in column (g)must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE
Sold Demand Charges Energy Charges Other Charges Total ($)Line
($)($)($)(h+i+;)0.
(9)(h)(i)(j)(k)
107,250 2,553,724 2,553,724 1
1,200 1,200 2
2,452 75,838 75,838 3
69,800 1,664,200 1,664,200 4
57,475 1,566,735 1,566,735 5
5,527 152,470 152,470 6
1,733,536 1,733,536 7
1,800 9,900 9,900 8
195 5,870 5,870 9
4,077 18,925 52,007 70,932 10
155 4,790 4,790 11
25,851 623,112 623,112 12
495 14,960 14,960 13
70,813 3,535 844,231 847,766 14
0 0 0 0 0
2,215,545 4,671,215 55,262,915 4,148,142 64,082,272
2,215,545 4,671,215 55,262,915 4,148,142 64,082,272
FERC FORM NO.1 (ED.12-90)Page 311.1
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)OX An Original (Mo,Da,Yr)Dec.31 2002
(2)A Resubrnission 04/30/2003 '
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e.,sales to purchasers other than ultimate consumers)transacted on a settlement basis other than
power exchanges during the year.Do not report exchanges of electricity (i.e.,transactions involving a balancing of debits and credits
for energy,capacity,etc.)and any settlements for imbalanced exchanges on this schedule.Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a).Do note abbreviate or truncate the name or use acronyms.Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b),enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (i.e.,the
supplier includes projected load for this service in its system resource planning).In addition,the reliability of requirements service must
be the same as,or second only to,the supplier's service to its own ultimate consumers.
LF -for tong-term service."Long-term"means five years or Longer and "firm"means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g.,the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service).This category should not be used for Long-term firm service which meets the
definition of RQ service.For all transactions identified as LF,provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF -for intermediate-term firm service.The same as LF service except that "intermediate-term"means longer than one year but Less
than five years.
SF -for short-term firm service.Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU -for Long-term sentice from a designated generating unit."Long-term"means five years or Longer.The availability and reliability of
service,aside from transmission constraints,must match the availability and reliability of designated unit.
IU -for intermediate-term service from a designated generating unit.The same as LU service except that "intermediate-term"means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Avera e |Avera
cation Tariff Number Demand (MW)Monthly NCÑ Deman<l Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Idaho Power Company SF WSPP "C"Tariff 9
2 Klamath Falls,City of SF WSPP "C"
3 Los Angeles Department of Water &Power SF WSPP "C"
4 MIECO SF WSPP "C"
5 Mirant Americas Energy Marketing LP SF WSPP "C"
6 Modesto Irrigation District SF WSPP "C"
7 Morgan Stanley SF WSPP "C"
8 Northern California Power Agency SF WSPP "C"
9 Northpoint Energy Solutions SF WSPP "C"
10 NorthWestern Energy LLC SF WSPP "C"
11 NorthWestern Energy LLC LF Tariff 9
12 Okanagan County PUD SF WSPP "C"
13 Pacific Northwest Generating Coop SF WSPP "C"
14 Pacific Power Marketing SF WSPP "C"
Subtotal RQ 0 0 0
Subtotal non-RQ O 0
Total 0 0 0
FERC FORM NO.1 (ED.12-90)Page 310.2
Name of Respondent This Re ort Is:Date of Report Year of Report
Avista Corp (1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
SALES FOR RESALE (Account 447)(Continued)
OS -for other service.use this category only for those services which cannot be placed in the above-defined categories,such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year.Describe the nature
of the service in a footnote.
AD -for Out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one.After listing all RQ sales,enter "Subtotal -RQ"
in column (a).The remaining sales may then be listed in any order.Enter "Subtotal-Non-RQ"in column (a)after this Listing.Enter
"Total"in column (a)as the Last Line of the schedule.Report subtotals and total for columns (9)through (k)
5.In Column (c),identify the FERC Rate Schedule or Tariff Number.On separate Lines,List all FERC rate schedules or tariffs under
which service,as identified in column (b),is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer)basis,enter the
average monthly billing demand in column (d),the average monthly non-coincident peak (NCP)demand in column (e),and the average
monthly coincident peak (CP)
demand in column (f).For all other types of service,enter NA in columns (d),(e)and (f).Monthly NCP demand is the maximum
metered hourly (60-minute integration)demand in a month.Monthly CP demand is the metered demand during the hour (60-minute
integration)in which the supplier's system reaches its monthly peak.Demand reported in columns (e)and (f)must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g)the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h),energy charges in column (i),and the total of any other types of charges,including
out-of-period adjustments,in column (j).Explain in a footnote all components of the amount shown in column (j).Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g)through (k)must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4),and then totaled on
the Last -line of the schedule.The "Subtotal -RQ"amount in column (g)must be reported as Requirements Sales For Resale on Page
401,line 23.The "Subtotal -Non-RQ"amount in column (g)must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE
Sold Demand Charges Energy Charges Other Charges Total ($)ne
($)($)($)(h+i+;)-
(g)(h)(i)(j)(k)
17,346 375 326,758 327,133 1
961 24,502 24,502 2
1,200 9,500 9,500 3
24,955 696,290 696,290 4
448 5,878 5,878 5
34,868 910,176 910,176 6
101,982 1,749,589 1,749,589 7
4,427 88,070 88,070 8
535 10,035 10,035 9
6,380 157,880 113,384 271,264 10
7,489 166,132 166,132 11
170 1,385 1,385 12
3,297 60,287 60,287 13
20,096 447,548 447,548 14
0 0 0 0 0
2,215,545 4,671,215 55,262,915 4,148,142 64,082,272
2,215,545 4,671,215 55,262,915 4,148,142 64,082,272
FERC FORM NO.1 (ED.12-90)Page 311.2
Name of Respondent This Report is:Date of Report Year of Report
Avista Corp (1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
SALES FOR RESALE (Account 4<7)
1.Report all sales for resale (i.e.,sales to purchasers other than ultimate consumers)transacted on a settlement basis other than
power exchanges during the year.Do not report exchanges of electricity (i.e.,transactions involving a balancing of debits and credits
for energy,capacity,etc.)and any settlements for imbalanced exchanges on this schedule.Power exchanges must be reported on the
2.Enter the name of the purchaser in column (a).Do note abbreviate or truncate the name or use acronyms.Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b),enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (i.e.,the
supplier includes projected load for this service in its system resource planning).In addition,the reliability of requirements service must
be the same as,or second only to,the supplier's service to its own ultimate consumers.
LF -for tong-term service."Long-term"means five years or Longer and "firm"means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g.,the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service).This category should not be used for Long-term firm service which meets the
definition of RQ service.For all transactions identified as LF,provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF -for intermediate-term firm service.The same as LF service except that "intermediate-term"means longer than one year but Less
than five years.
SF -for sholt-term firm service.Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU -for Long-term service from a designated generating unit."Long-term"means five years or Longer.The availability and reliability of
service,aside from transmission constraints,must match the availability and reliability of designated unit.
IU -for intermediate-term service from a designated generating unit.The same as LU service except that "intermediate-term"means
Longer than one year but Less than five years.
Line Name of Company or PublicAuthority Statistical FERC Rate Average Actual De nand (MW)
No (Footnote Affiliations)Classifi-Schedule or Monthly Billing Avera e Averaae
cation Tariff Number Demand (MW)Monthly NC Demarf Monthly CPT)emand
(a)(b)(c)(d)(e)(f)
1 PacifiCorp LF 194 150 150 84
2 PacifiCorp SF WSPP "C"
3 PacifiCorp LF Tariff 9
4 Pend Oreille Co Public Utility District IF Tariff 10 VAR 0 0
5 Pend Oreille Co Public Utility District SF WSPP "C"Tariff 9
6 Pacific Gas &Electric Trading SF WSPP "C"
7 Pinnacle West SF WSPP "C"
8 Portland General Electric Company SF WSPP "C"Tariff 9
9 Powerex SF WSPP "C"
10 PP &L Montana SF WSPP "C"
11 PP &L Montana LF Tariff 9
12 Public Service of Colorado SF WSPP "C"
13 Puget Sound Energy SF WSPP "C"Tariff 9
14 Puget Sound Energy LF 154
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED.12-90)Page 310.3
Name of Respondent This Report Is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp(2)A Resubmission 04/30/2003 '
SALES FOR RESALE(Account 447)(Continued)
OS -for other service.use this category only for those services which cannot be placed in the above-defined categories,such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year.Describe the nature
of the service in a footnote.
AD -for Out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one.After listing all RQ sales,enter "Subtotal -RQ"
in column (a).The remaining sales may then be listed in any order.Enter "Subtotal-Non-RQ"in column (a)after this Listing.Enter
"Total"in column (a)as the Last Line of the schedule.Report subtotals and total for columns (9)through (k)
5.In Column (c),identify the FERC Rate Schedule or Tariff Number.On separate Lines,List all FERC rate schedules or tariffs under
which service,as identified in column (b),is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer)basis,enter the
average monthly billing demand in column (d),the average monthly non-coincident peak (NCP)demand in column (e),and the average
,monthly coincident peak (CP)
demand in column (f).For all other types of service,enter NA in columns (d),(e)and (f).Monthly NCP demand is the maximum
metered hourly (60-minute integration)demand in a month.Monthly CP demand is the metered demand during the hour (60-minute
integration)in which the supplier's system reaches its monthly peak.Demand reported in columns (e)and (f)must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g)the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h),energy charges in column (i),and the total of any other types of charges,including
out-of-period adjustments,in column (j).Explain in a footnote all components of the amount shown in column (j).Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g)through (k)must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4),and then totaled on
the Last -line of the schedule.The "Subtotal -RQ"amount in column (g)must be reported as Requirements Sales For Resale on Page
401,line 23.The "Subtotal -Non-RQ"amount in column (g)must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE
Sold Demand Charges Energy Charges Other Charges Total ($)Line
($)($)($)(h+i+j)No.
(g)(h)(i)(k)
82,800 2,043,000 3,335,184 5,378,184 1
45,966 98,520 749,507 848,027 2
4,765 105,721 105,721 3
307,958 307,958 4
320 178,607 2,880 181,487 5
600 7,500 7,500 6
23,080 349,792 349,792 7
75,026 5,850 1,454,227 1,460,077 8
141,244 1,587,754 1,587,754 9
33,869 41,600 446,305 487,905 10
17,015 377,573 377,573 11
91,101 2,054,417 2,054,417 12
51,474 12,100 946,740 958,840 13
216,810 10,279,150 10,279,150 14
0 0 0 0 0
2,215,545 4,671,215 55,262,915 4,148,142 64,082,272
2,215,545 4,671,215 55,262,915 4,148,142 64,082,272
I
FERC FORM NO.1 (ED.12-90)Page 311.3
Name of Respondent This Report ls:Date of Report Year of Report
Avista Corp.(1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
SALES FOR RESALE (Account 4/7)
1.Report all sales for resale (i.e.,sales to purchasers other than ultimate consumers)transacted on a settlement basis other than
power exchanges during the year.Do not report exchanges of electricity (i.e.,transactions involving a balancing of debits and credits
for energy,capacity,etc.)and any settlements for imbalanced exchanges on this schedule.Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a).Do note abbreviate or truncate the name or use acronyms.Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b),enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (i.e.,the
supplier includes projected load for this service in its system resource planning).In addition,the reliability of requirements service must
be the same as,or second only to,the supplier's service to its own ultimate consumers.
LF -for tong-term service."Long-term"means five years or Longer and "firm"means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g.,the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service).This category should not be used for Long-term firm service which meets the
definition of RQ service.For all transactions identified as LF,provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF -for intermediate-term firm service.The same as LF service except that "intermediate-term"means longer than one year but Less
than five years.
SF -for short-term firm service.Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU -for Long-term service from a designated generating unit."Long-term"means five years or Longer.The availability and reliability of
service,aside from transmission constraints,must match the availability and reliability of designated unit.
lU -for intermediate-term service from a designated generating unit.The same as LU service except that "intermediate-term"means
Longer than one year but Less than five years.
Line Name of Companyor Public Authority Statistical FERC Rate Avera e Actual Demand (MW)
No.(Footnote Affiliations)C sh he
u br DMeahr
d (MonthI N Deman Month yC emand
(a)(b)(c)(d)(e)(f)
1 Puget Sound Energy LF Tariff 9
2 Redding,City of SF WSPP "C"
3 Sacramento Municipal Utility District SF WSPP "C"
4 Santa Clara,City of SF WSPP "C"
5 Seattle,City of SF WSPP "C"Tariff 9
6 Sempra SF WSPP "C"
7 Sierra Pacific Power Company SF WSPP "C"
8 Sovereign Power LF Tariff 10 VAR 0 0
9 Tacoma,City of SF WSPP "C"
10 TransAlta Energy Marketing SF WSPP "C"Tariff 9
11 Turlock Irrigation District SF WSPP "C"
12 TXU Energy Trading Company SF WSPP "C"
13 Williams Energy Services Company SF WSPP "C"
14 IntraCompany Wheeling OS
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total O 0 0
FERC FORM NO.1 (ED.12-90)Page 310.4
Name of Respondent This Report Is:Date of Report Year of Report
Avista Co (1)DX An Original (Mo,Da,Yr)Dec.31 2002rp.(2)A Resubmission 04/30/2003 '
SALES FOR RESALE (Account 447)(Continued)
OS -for other service.use this category only for those services which cannot be placed in the above-defined categories,such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year.Describe the nature
of the service in a footnote.
AD -for Out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reponing
years.Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one.After listing all RQ sales,enter "Subtotal -RO"
in column (a).The remaining sales may then be listed in any order.Enter "Subtotal-Non-RQ"in column (a)after this Listing.Enter
"Total"in column (a)as the Last Line of the schedule.Report subtotals and total for columns (9)through (k)
5.In Column (c),identify the FERC Rate Schedule or Tariff Number.On separate Lines,List all FERC rate schedules or tariffs under
which service,as identified in column (b),is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer)basis,enter the
average monthly billing demand in column (d),the average monthly non-coincident peak (NCP)demand in column (e),and the average
monthly coincident peak (CP)
demand in column (f).For all other types of service,enter NA in columns (d),(e)and (f).Monthly NCP demand is the maximum
metered hourly (60-minute integration)demand in a month.Monthly CP demand is the metered demand during the hour (60-minute
integration)in which the supplier's system reaches its monthly peak.Demand reported in columns (e)and (f)must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g)the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h),energy charges in column (i),and the total of any other types of charges,including
out-of-period adjustments,in column (j).Explain in a footnote all components of the amount shown in column (j).Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g)through (k)must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4),and then totaled on
the Last -line of the schedule.The "Subtotal -RQ"amount in column (g)must be reported as Requirements Sales For Resale on Page
401,line 23.The "Subtotal -Non-RQ"amount in column (g)must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges i Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(j)(k)
21,783 483,294 483,294 1
48,962 1,183,922 1,183,922 2
110,305 2,538,449 2,538,449 3
7,371 136,841 136,841 4
7,796 350 148,274 148,624 5
1,695 27,865 27,865 6
11,106 274,517 274,517 7
2,308 2,308 8
440 1,700 7,815 9,515 9
147,410 3,373,630 3,373,630 10
18,592 441,531 441,531 11
800 19,200 19,200 12
74,275 1,539,206 1,539,206 13
-4,148,142 4,148,142 14
0 0 0 0 0
2,215,545 4,671,215 55,262,915 4,148,142 64,082,272
2,215,545 4,671,215 55,262,915 4,148,142 64,082,272
FERC FORM NO.1 (ED.12-90)Page 311.4
Name of Respondent This Report is:Date of Report Year of Report
Avista Corp (1)OX An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e.,sales to purchasers other than ultimate consumers)transacted on a settlement basis other than
power exchanges during the year.Do not report exchanges of electricity (i.e.,transactions involving a balancing of debits and credits
for energy,capacity,etc.)and any settlements for imbalanced exchanges on this schedule.Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a).Do note abbreviate or truncate the name or use acronyms.Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b),enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (i.e.,the
supplier includes projected load for this service in its system resource planning).In addition,the reliability of requirements service must
be the same as,or second only to,the supplier's service to its own ultimate consumers.
LF -for tong-term service."Long-term"means five years or Longer and "firm"means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g.,the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service).This category should not be used for Long-term firm service which meets the
definition of RQ service.For all transactions identified as LF,provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF -for intermediate-term firm service.The same as LF service except that "intermediate-term"means longer than one year but Less
than five years.
SF -for short-term firm service.Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU -for Long-term service from a designated generating unit."Long-term"means five years or Longer.The availability and reliability of
service,aside from transmission constraints,must match the availability and reliability of designated unit.
IU -for intermediate-term service from a designated generating unit.The same as LU service except that "intermediate-term"means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera e Actual De nand (MW)
No.(Footnote Affiliations)SaÎihe
u br DMerMahr
d (Month N I Demand Month y CP emand
(a)(b)(c)(d)(e)(f)
1 IntraCompany Generation OS
2 Revenue Adjustment OS
3
4
5
6
7
8
9
10
11
12
13
14
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED.12-90)Page 310.5
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)OX An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
SALES FOR RESALE (Account 447)(Continued)
OS -for other service.use this category only for those services which cannot be placed in the above-defined categories,such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year.Describe the nature
of the service in a footnote.
AD -for Out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one.After listing all RQ sales,enter "Subtotal -RO"
in column (a).The remaining sales may then be listed in any order.Enter "Subtotal-Non-RQ"in column (a)after this Listing.Enter
"Total"in column (a)as the Last Line of the schedule.Report subtotals and total for columns (9)through (k)
5.In Column (c),identify the FERC Rate Schedule or Tariff Number.On separate Lines,List all FERC rate schedules or tariffs under
which service,as identified in column (b),is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer)basis,enter the
average monthly billing demand in column (d),the average monthly non-coincident peak (NCP)demand in column (e),and the average
monthly coincident peak (CP)
demand in column (f).For all other types of service,enter NA in columns (d),(e)and (f).Monthly NCP demand is the maximum
metered hourly (60-minute integration)demand in a month.Monthly CP demand is the metered demand during the hour (60-minute
integration)in which the supplier's system reaches its monthly peak.Demand reported in columns (e)and (f)must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g)the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h),energy charges in column (i),and the total of any other types of charges,including
out-of-period adjustments,in column (j).Explain in a footnote all components of the amount shown in column (j).Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g)through (k)must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4),and then totaled on
the Last -line of the schedule.The "Subtotal -RQ"amount in column (g)must be reported as Requirements Sales For Resale on Page
401,line 23.The "Subtotal -Non-RQ"amount in column (g)must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges |Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(j)(k)
63,057 63,057 1
152 -1,735 -1,735 2
3
4
5
6
7
8
9
10
11
12
13
14
0 0 0 0 0
2,215,545 4,671,215 55,262,915 4,148,142 64,082,272
2,215,545 4,671,215 55,262,915 4,148,142 64,082,272
FERC FORM NO.1 (ED.12-90)Page 311.5
Name of Respondent This Report Is:Date of Report Year of Report
Avista Cor (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If thE amount for previous year is not derived from previously reported figures,explain in footnote.
Line Account Amount for Amount forCurrentYearPrevousYearNo(a)(b)(c)
1 1.POWER PRODUCTION EXPENSES
2 A.Steam Power Generation
3 Operation
4 (500)Operation Supervision and Engineering 214,537 326,224
5 (501)Fuel 15,531,714 18,309,601
6 (502)Steam Expenses 815,779 609,026
7 (503)Steam from Other Sources 2,878 -6,446
8 (Less)(504)Steam Transferred-Cr.
9 (505)Electric Expenses 590,407 452,837
10 (506)Miscellaneous Steam Power Expenses 2,984,404 2,052,292
11 (507)Rents 62,042 115,166
12 (509)Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12)20,201,761 21,858,70C
14 Maintenance
15 (510)Maintenance Supervision and Engineering 215,172 409,004
16 (511)Maintenance of Structures 328,872 288,690
17 (512)Maintenance of Boiler Plant 3,155,081 3,854,534
18 (513)Maintenance of Electric Plant 1,039,473 634,803
19 (514)Maintenance of Miscellaneous Steam Plant 419,137 467,805
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)5,157,735 5,654,836
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 &20)25,359,496 27,513,536
22 B.Nuclear Power Generation
23 Operation
24 (517)Operation Supervision and Engineering
25 (518)Fuel
26 (519)Coolants and Water
27 (520)Steam Expenses
28 (521)Steam from Other Sources
29 (Less)(522)Steam Transferred-Cr.
30 (523)Electric Expenses
31 (524)Miscellaneous Nuclear Power Expenses
32 (525)Rents
33 TOTAL Operation (Enter Total of lines 24 thru 32)
34 Maintenance
35 (528)Maintenance Supervision and Engineering
36 (529)Maintenance of Structures
37 (530)Maintenance of Reactor Plant Equipment
38 (531)Maintenance of Electric Plant
39 (532)Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Production Expenses-Nuc.Power (Entr tot lines 33 &40)
42 C.Hydraulic Power Generation %C2
44 (535)Operation Supervision and Engineering 1,232,213 1,152,467
45 (536)Water for Power 703,155 736,431
46 (537)Hydraulic Expenses 1,349,496 1,813,892
47 (538)Electric Expenses 3,090,333 2,924,770
48 (539)Miscellaneous Hydraulic Power Generation Expenses 472,905 623,751
49 (540)Rents 555,722 579,331
50 TOTAL Operation (Enter Total of Lines 44 thru 49)7,403,824 7,830,642
FERC FORM NO.1 (ED.12-93)Page 320
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
ELECTRIC OPERATIONAND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures,explain in footnote.
Line Account Amount for Amount forCurrentYearPreviousYearNo.(a)(b)(c)
51 C.Hydraulic Power Generation (Continued)t.¾94
52 Maintenance š¾À
53 (541)Mainentance Supervision and Engineering 228,252 173,058
54 (542)Maintenance of Structures 169,868 157,883
55 (543)Maintenance of Reservoirs,Dams,and Waterways 735,000 340,136
56 (544)Maintenance of Electric Plant 1,829,645 1,425,606
57 (545)Maintenanceof Miscellaneous Hydraulic Plant 23,460 223,172
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)2,986,225 2,319,855
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 &58)10,390,049 10,150 497
60 D.Other Power Generation
62 (546)Operation Supervision and Engineering 22,354 6,662
63 (547)Fuel 3,967,063 64,632,815
64 (548)Generation Expenses 28,531 331,244
65 (549)Miscellaneous Other Power Generation Expenses 276,750 1,487,674
66 (550)Rents 9,399,833 13,948,886
67 TOTAL Operation (Enter Total of lines 62 thru 66)13,694,531 80,407,281
68 Maintenance
69 (551)Maintenance Supervision and Engineering 173,413 86,136
70 (552)Maintenance of Structures 40,742 91,490
71 (553)Maintenance of Generating and Electric Plant 569,648 1,230,897
72 (554)Maintenance of Miscellaneous Other Power Generation Plant 93,323 89,122
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)877,126 1,497,645
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 &73)14,571,657 81,904,926
75 E.Other Power Supply Expenses S-'W
76 (555)Purchased Power 115,282,088 708,320,720
77 (556)System Control and Load Dispatching 1,004,616 899,145
78 (557)Other Expenses 109,507,405 -152,001,217
79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)225,794,109 557,218,648
80 TOTAL Power Production Expenses (Total of lines 21,41,59,74 &79)276,115,311 676,787,607
81 2.TRANSMISSION EXPENSES emmwa
82 Operation
83 (560)Operation Supervision and Engineering 2,054,685 2,099,226
84 (561)Load Dispatching 966,064 959,898
85 (562)Station Expenses 130,269 165,854
86 (563)Overhead Lines Expenses 112,411 122,599
87 (564)Underground Lines Expenses
88 (565)Transmission of Electricity by Others 8,441,228 9,888,820
89 (566)Miscellaneous Transrnission Expenses 301,663 526,551
90 (567)Rents 115,440 128,500
91 TOTAL Operation (Enter Total of lines 83 thru 90)12,121,760 13,891,448
92 Maintenance Mi fä¾i?O
93 (568)Maintenance Supervision and Engineering 138,292 138,343
94 (569)Maintenance of Structures 18,435 35,475
95 (570)Maintenance of Station Equipment 1,187,787 1,069,865
96 (571)Maintenance of Overhead Lines 114,217 970,101
97 (572)Maintenance of Underground Lines 8,929 23,482
98 (573)Maintenance of Miscellaneous Transmission Plant 2,882 500
99 TOTAL Maintenance (Enter Total of lines 93 thru 98)1,470,542 2,237,766
100 TOTAL Transmission Expenses (Enter Total of lines 91 and 99)13 592 302 16 129 2'4
101 3.DISTRIBUTION EXPENSES
102 Operation .TE
103 (580)Operation Supervision and Engineering 675,982 815,163
FERC FORM NO.1 (ED.12-93)Page 321
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures,explain in footnote.
Line |Account Amount for Ampunt for
I Current Year Previous YearNo(a)(b)(c)
104 3.DISTRIBUTION Expenses (Continued)
105 (581)Load Dispatching 1,460 62,588
106 (582)Station Expenses 239,401 253,321
107 (583)Overhead Line Expenses 1,231,203 1,439,451
108 (584)Underground Line Expenses 1,312,694 1,243,110
109 (585)Street Lighting and Signal System Expenses 167,527 142,837
110 (586)Meter Expenses 1,135,102 993,685
111 (587)Customer Installations Expenses 274,263 283,948
112 (588)Miscellaneous Expenses 2,433,201 1,781,252
113 (589)Rents 363,061 398,286
114 TOTAL Operation (Enter Total of lines 103 thru 113)7,833,894 7,413,641
115 Maintenance
116 (590)Maintenance Supervision and Engineering 443,722 608,887
117 (591)Maintenance of Structures 28,958 1,424
118 (592)Maintenance of Station Equipment 937,398 655,166
119 (593)Maintenance of Overhead Lines 3,338,769 5,565,053
120 (594)Maintenance of Underground Lines 733,271 610,954
121 (595)Maintenance of Line Transformers 552,653 604,400
122 (596)Maintenance of Street Lighting and Signal Systems 278,844 346,530
123 (597)Maintenance of Meters 25,643 41,701
124 (598)Maintenance of Miscellaneous Distribution Plant 147,033 1,763
125 TOTAL Maintenance (Enter Total of lines 116 thru 124)6,486,291 8,435,878
126 TOTAL Distribution Exp (Enter Total of lines 114 and 125)14,320,185 15,849,519
127 4.CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901)Supervision 113,629 77,851
130 (902)Meter Reading Expenses 2,320,981 2,080,803
131 (903)Customer Records and Collection Expenses 7,186,516 8,016,957
132 (904)Uncollectible Accounts 1,644,870 1,115,713
133 (905)Miscellaneous Customer Accounts Expenses 832,003 894,870
134 TOTAL Customer Accounts Expenses (Total of lines 129 thru 133)12,097,999 12,186,194
135 5.CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation an --a-...n-
137 (907)Supervision 28
138 (908)Customer Assistance Expenses 9,985,270 8,329,213
139 (909)Informational and Instructional Expenses 108,098 138,134
140 (910)Miscellaneous Customer Service and Informational Expenses 181,542 111,802
141 TOTAL Cust.Service and Information.Exp.(Total lines 137 thru 140)10,274,910 8,579,177
142 6.SALES EXPENSES
143 Operation
144 (911)Supervision 19,824 46,481
145 (912)Demonstrating and Selling Expenses 710,061 790,644
146 (913)Advertising Expenses 183,047 155,722
147 (916)Miscellaneous Sales Expenses 89,905 143,656
148 TOTAL Sales Expenses (Enter Total of lines 144 thru 147)1,002,837 1,136,503
149 7.ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920)Administrative and General Salaries 13,607,995 10,705,006
152 (921)Office Supplies and Expenses 5,494,412 4,204,321
153 (Less)(922)Administrative Expenses Transferred-Credit 27,200 59,674
FERC FORM NO.1 (ED.12-93)Page 322
l Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures,exolain in footnote.
Line Account Amount for Amount forCurrentYearPreviousYearNo(a)(b)(c)
154 7.ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
155 (923)Outside Services Employed 8,529,025 6,476,250
156 (924)Property Insurance 846,203 481,800
157 (925)Injuries and Damages 1,624,746 1,812,314
158 (926)Employee Pensions and Benefits 770,878 1,341,490
159 (927)Franchise Requirements 6,250 5,775
160 (928)Regulatory Commission Expenses 4,043,080 3,546,475
161 (929)(Less)Duplicate Charges-Cr.
162 (930.1)General Advertising Expenses 5,683 446,612
163 (930.2)Miscellaneous General Expenses 2,646,755 2,703,685
164 (931)Rents 5,614,878 5,290,145
165 TOTAL Operation (Enter Total of lines 151 thru 164)43,162,705 36,954,199
166 Maintenance
167 (935)Maintenance of General Plant 3,010,632 2,473,457
168 TOTAL Admin &General Expenses (Total of lines 165 thru 167)46,173,337 39,427,656
169 TOTAL Elec Op and Maint Expn (Tot 80,100,126,134,141,148,168)373,576,881 770,095,870
I I I
FERC FORM NO.1 (ED.12-93)Page 323
Name of Respondent This Report is:Date of Report Year of Report
Avista Corp (1)X An Original (Mo,Da,Yr)Dec.31 2002
(2)A Resubmission 04/30/2003 '
PURCHASED POWER (Account 555)(Including power excnanges)
1.Report all power purchases made during the year.Also report exchanges of electricity (i.e.,transactions involving a balancing of
debits and credits for energy,capacity,etc.)and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a).Do not abbreviate or truncate the name or use
acronyms.Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b),enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (i.e.,the
supplier includes projects load for this service in its system resource planning).In addition,the reliability of requirement service must
be the same as,or second only to,the supplier's service to its own ultimate consumers.
LF -for long-term firm service."Long-term"means five years or longer and "firm"means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g.,the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service).This category should not be used for long-term firm service firm service
which meets the definition of RQ service.For all transaction identified as LF,provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF -for intermediate-term firm service.The same as LF service expect that "intermediate-term"means longer than one year but less
than five years.
SF -for short-term service.Use this category for all firm services,where the duration of each period of commitment for service is one
year or less.
LU -for long-term service from a designated generating unit."Long-term"means five years or longer.The availability and reliability of
service,aside from transmission constraints,must match the availability and reliability of the designated unit.
IU -for intermediate-term sentice from a designated generating unit.The same as LU service expect that "intermediate-term"means
longer than one year but less than five years.
EX -For exchanges of electricity.Use this category for transactions involving a balancing of debits and credits for energy,capacity,etc.
and any settlements for imbalanced exchanges.
OS -for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year.Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual De nand (MW)
Classifi-Schedule or Monthly Billing Average Average
No.(Footnote Affiliations)cation Tariff Number Demand (MW)Monthly NCP Demand Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 American Electric Power SF Mkt Tariff
2 Aquila Merchant Services Inc.SF Mkt Tariff &WSPP
3 Black Creek Hydro LU FERC #1
4 Benton PUD No1 of Benton County SF WSPP
5 BP Energy Company SF Mkt Tariff &WSPP
6 Bonneville Power Administration LF WNP#3 Agr.
7 Bonneville Power Administration LF Sup/Entit Cap.97
8 Bonneville Power Administration EX NWPP
9 Bonneville Power Administration OS NWPP
10 Bonneville Power Administration SF WSPP
11 Chelan County Public Utility Dist.#1 LU Rocky Reach
12 Chelan County Public Utility Dist.#1 SF WSPP
13 Columbia Storage Power Exchange LF 97
14 Cogentrix Power Marketing SF Mkt Tariff
Total
FERC FORM NO.1 (ED.12-90)Page 326
Name of Respondent This Report Is:Date of Report Year of Report
Avista Co (1)QX An Original (Mo,Da,Yr)Dec.31,2002rp.(2)QA Resubmission 04/30/2003
PU BCHASED POWEH(Account 555)(continued)(Including power exchanges)
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
4.In column (c),identify the FERC Rate Schedule Number or Tariff,or,for non-FERC jurisdictional sellers,include an appropriate
designation for the contract.On separate lines,list all FERC rate schedules,tariffs or contract designations under which service,as
identified in column (b),is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer)basis,enter
the monthly average billing demand in column (d),the average monthly non-coincident peak (NCP)demand in column (e),and the
average monthly coincident peak (CP)demand in column (f).For all other types of service,enter NA in columns (d),(e)and (f).Monthly
NCP demand is the maximum metered hourly (60-minute integration)demand in a month.Monthly CP demand is the metered demand
during the hour (60-minute integration)in which the supplier's system reaches its monthly peak.Demand reported in columns (e)and (f)
must be in megawatts.Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g)the megawatthours shown on bills rendered to the respondent.Report in columns (h)and (i)the megawatthours
of power exchanges received and delivered,used as the basis for settlement.Do not report net exchange.
7.Report demand charges in column (j),energy charges in column (k),and the total of any other types of charges,including
out-of-period adjustments,in column (I).Explain in a footnote all components of the amount shown in column (l).Report in column (m)
the total charge shown on bills received as settlement by the respondent.For power exchanges,report in column (m)the settlement
amount for the net receipt of energy.If more energy was delivered than received,enter a negative amount.If the settlement amount (I)
include credits or charges other than incremental generation expenses,or (2)excludes certain credits or charges covered by the
agreement,provide an explanatory footnote.
8.The data in column (g)through (m)must be totalled on the last line of the schedule.The total amount in column (g)must be
reported as Purchases on Page 401,line 10.The total amount in column (h)must be reported as Exchange Received on Page 401,
line 12.The total amount in column (i)must be reported as Exchange Delivered on Page 401,line 13.
9.Footnote entries as required and provide explanations following all required data.
I POWER EXCHANGES COST/SETTLEMENT OF POWERMegaWettHnnrs Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges |Energy Charges Other Charges Total (j+k+l)No.Received Delivered ($)($)($)of Settlement ($)
(g)(h)(i)(j)(k)(1)(m)
169,826 5,671,942 5,671,942 1
87,12E 2,557,81E 2,557,816 2
9,65E 112,00E 112,008 3
12,51C 334,540 334,540 4
46,944 1,373,57€1,373,576 5
398,75E 10,780,257 10,780,257 6
297 78 21,48E 21,486 7
1,285 1,670 -492 -492 8
1,945 1,945 9
87,14E 1,293,482 1,293,482 10
169,51C 1,842,057 1,842,057 11
26,80C 890,21C 890,210 12
39,715 13
16,976 277,47C 277,470 14
4,664,491 632,543 607,430 952,750 109,445,154 4,884,184 115,282,08E
FERC FORM NO.1 (ED.12-90)Page 327
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
PURCHASED POWER (Account 555)(Including power exchanges)
1.Report all power purchases made during the year.Also report exchanges of electricity (i.e.,transactions involving a balancing of
debits and credits for energy,capacity,etc.)and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a).Do not abbreviate or truncate the name or use
acronyms.Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b),enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (i.e.,the
supplier includes projects load for this service in its system resource planning).In addition,the reliability of requirement service must
be the same as,or second only to,the supplier's service to its own ultimate consumers.
LF -for long-term firm service."Long-term"means five years or longer and "firm"means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g.,the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service).This category should not be used for long-term firm service firm service
which meets the definition of RO service.For all transaction identified as LF,provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF -for intermediate-term firm service.The same as LF service expect that "intermediate-term"means longer than one year but less
than five years.
SF -for short-term service.Use this category for all firm services,where the duration of each period of commitment for service is one
year or less.
LU -for long-term service from a designated generating unit."Long-term"means five years or longer.The availability and reliability of
service,aside from transmission constraints,must match the availability and reliability of the designated unit.
IU -for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term"means
longer than one year but less than five years.
EX -For exchanges of electricity.Use this category for transactions involving a balancing of debits and credits for energy,capacity,etc.
and any settlements for imbalanced exchanges.
IOS-for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year.Describe the nature
of the service in a footnote for each adjustment.
Line Nameof Company or Public Authority Statistical FERC Rate Average Actual De nand (MW)
Classifi-Schedule or Monthly Billing Average AverageNo.(Footnote Affiliations)cation Tariff Number Demand (MW)Monthly NCP Demand Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Constellation Power Source SF Mkt Tariff &WSPP
2 Coral Power LLC SF Mkt Tariff &WSPP
3 Douglas County Public Utility Dist.#1 LU Wells
4 Douglas County Public Utility Dist.#1 SF WSPP
5 Douglas County Public Utility Dist.#1 EX Douglas PUD various
6 Duke Energy Trading &Marketing SF Mkt Tariff &WSPP
7 Dynegy Power Marketing SF Mkt Tariff &WSPP
8 El Paso Merchant Energy SF Mkt Tariff &WSPP
9 Enmax Energy Corporation SF Mkt Tariff &WSPP
10 Enron Power Marketing Inc.OS Mkt Tariff &WSPP
11 EugeneWater &Electric Board SF WSPP
12 Franklin County PUD #1 SF WSPP
13 Grant County Public Utility Dist.#2 LU Wanapum
14 Grant County Public Utility Dist.#2 LU Priest Rapids
Total
FERC FORM NO.1 (ED.12-90)Page 326.1
Name of Respondent This Report Is:Date of Report Year of Report
Avista Co .
(1)QX An Original (Mo,Da,Yr)Dec.31,2002rp(2)A Resubmission 04/30/2003
PU -icHAS QWl-H(Account 555)(continued)(I ing power exchanges)
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
4.In column (c),identify the FERC Rate Schedule Number or Tariff,or,for non-FERC jurisdictional sellers,include an appropriate
designation for the contract.On separate lines,list all FERC rate schedules,tariffs or contract designations under which service,as
identified in column (b),is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer)basis,enter
the monthly average billing demand in column (d),the average monthly non-coincident peak (NCP)demand in column (e),and the
average monthly coincident peak (CP)demand in column (f).For all other types of service,enter NA in columns (d),(e)and (f).Monthly
NCP demand is the maximum metered hourly (60-minute integration)demand in a month.Monthly CP demand is the metered demand
during the hour (60-minute integration)in which the supplier's system reaches its monthly peak.Demand reported in columns (e)and (f)
must be in megawatts.Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g)the megawatthours shown on bills rendered to the respondent.Report in columns (h)and (i)the megawatthours
of power exchanges received and delivered,used as the basis for settlement.Do not report net exchange.
7.Report demand charges in column (j),energy charges in column (k),and the total of any other types of charges,including
out-of-period adjustments,in column (I).Explain in a footnote all components of the amount shown in column (I).Report in column (m)
the total charge shown on bills received as settlement by the respondent.For power exchanges,report in column (m)the settlement
amount for the net receipt of energy.If more energy was delivered than received,enter a negative amount.If the settlement amount (I)
include credits or charges other than incremental generation expenses,or (2)excludes certain credits or charges covered by the
agreement,provide an explanatory footnote.
8.The data in column (g)through (m)must be totalled on the last line of the schedule.The total amount in column (g)must be
reported as Purchases on Page 401,line 10.The total amount in column (h)must be reported as Exchange Received on Page 401,
line 12.The total amount in column (i)must be reported as Exchange Delivered on Page 401,line 13.
9.Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES COST/SETTLEMENT OF POWERMgeWattHours I ine
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Received Delivered ($)($)($)of Settlement ($)
(g)(h)(i)(j)(k)(I)(m)
56,82E 1,644,476 1,644,475 1
25 625 625 2
130,44E 1,099,75E 1,099,755 3
43,672 698,936 698,935 4
124,562 124,055 952,750 952,750 5
40C 11,50C 11,500 6
26,00C 550,80C 550,800 7
190,94C 5,830,191 5,830,191 8
1,062 18,001 18,001 9
2,928,450 2,928,450 10
11,04A 203,43E 203,438 11
8,26E 246,76E 246,768 12
298,38E 3,096,20E 3,096,209 13
238,30E 1,768,402 1,768,402 14
4,664,491 632,543 607,430 952,750 109,445,154 4,884,184 115,282.08E
FERC FORM NO.1 (ED.12-90)Page 327.1
Name of Respondent This Re ort Is:Date of Report Year oϾport
Avista Corp (1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
PURCHASED POWER (Account 555)(Including power excnanges)
1.Report all power purchases made during the year.Also report exchanges of electricity (i.e.,transactions involving a balancing of
debits and credits for energy,capacity,etc.)and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a).Do not abbreviate or truncate the name or use
acronyms.Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b),enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (i.e.,the
supplier includes projects load for this service in its system resource planning).In addition,the reliability of requirement service must
be the same as,or second only to,the supplier's service to its own ultimate consumers.
LF -for long-term firm service."Long-term"means five years or longer and "firm"means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g.,the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service).This category should not be used for long-term firm service firm service
which meets the definition of RQ service.For all transaction identified as LF,provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF -for intermediate-term firm service.The same as LF service expect that "intermediate-term"means longer than one year but less
than five years.
SF -for short-term service.Use this category for all firm services,where the duration of each period of commitment for service is one
year or less.
LU -for long-term service from a designated generating unit."Long-term"means five years or longer.The availability and reliability of
service,aside from transmission constraints,must match the availability and reliability of the designated unit.
IU -for intermediate-term service from a designated generating unit.The same as LU senrice expect that "intermediate-term"means
longer than one year but less than five years.
EX -For exchanges of electricity.Use this category for transactions involving a balancing of debits and credits for energy,capacity,etc.
and any settlements for imbalanced exchanges.
OS -for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year.Describe the nature
of the service in a footnote for each adjustment.
Line Nameof Company or PublicAuthority Statistical FERC Rate Average Actual Denand (MW)
Classifi-Schedule or Monthly Billing Average AverageNo.(Footnote Affiliations)cation Tariff Number Demand (MW)Monthly NCP Demand Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Grant County Public Utility Dist.#2 SF WSPP
2 Grays Harbor Public Utility Dist.#1 SF WSPP
3 Hydro Technology Systems LU PURPA Agmt
4 IdaCorp Energy SF Mkt Tariff &WSPP
5 Inland Power &Light Company RQ Mkt Tariff
6 Klamath Falls,City of SF Mkt Tariff &WSPP
7 Jim Ford Creek Hydro LU PURPA Agmt
8 John Day Hydro LU PURPA Agmt
9 MIECO Inc.IF Mkt Tariff &WSPP
10 Minnesota Methane LU PURPA Agmt
11 Modesto irrigation District SF WSPP
12 Morgan Stanley Capital Group SF Mkt Tariff &WSPP
13 Northern Cal Power Authority SF WSPP
14 Northpoint Energy Solutions SF Mkt Tariff &WSPP.
Total
FERC FORM NO.1 (ED.12-90)Page 326.2
'Name of Respondent This Report Is:Date of Report Year of Report(1)QX An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp.(2)A Resubmission 04/30/2003 '
PU -tcHAS QWI-R(Account 555)(continued)(I ing power exchanges)
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
4.In column (c),identify the FERC Rate Schedule Number or Tariff,or,for non-FERC jurisdictional sellers,include an appropriate
designation for the contract.On separate lines,list all FERC rate schedules,tariffs or contract designations under which service,as
identified in column (b),is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer)basis,enter
the monthly average billing demand in column (d),the average monthly non-coincident peak (NCP)demand in column (e),and the
average monthly coincident peak (CP)demand in column (f).For all other types of service,enter NA in columns (d),(e)and (f).Monthly
NCP demand is the maximum metered hourly (60-minute integration)demand in a month.Monthly CP demand is the metered demand
during the hour (60-minute integration)in which the supplier's system reaches its monthly peak.Demand reported in columns (e)and (f)
must be in megawatts.Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g)the megawatthours shown on bills rendered to the respondent.Report in columns (h)and (i)the megawatthours
of power exchanges received and delivered,used as the basis for settlement.Do not report net exchange.
7.Report demand charges in column (j),energy charges in column (k),and the total of any other types of charges,including
out-of-period adjustments,in column (I).Explain in a footnote all components of the amount shown in column (1).Report in column (m)
the total charge shown on bills received as settlement by the respondent.For power exchanges,report in column (m)the settlement
amount for the net receipt of energy.If more energy was delivered than received,enter a negative amount.If the settlement amount (I)
include credits or charges other than incremental generation expenses,or (2)excludes certain credits or charges covered by the
agreement,provide an explanatory footnote.
8.The data in column (g)through (m)must be totalled on the last line of the schedule.The total amount in column (g)must be
reported as Purchases on Page 401,line 10.The total amount in column (h)must be reported as Exchange Received on Page 401,
line 12.The total amount in column (i)must be reported as Exchange Delivered on Page 401,line 13.
9.Footnote entries as required and provide explanations following all required data.
I POWER EXCHANGES COST/SETTLEMENT OF POWERMagaWettHolirs 1ine
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges 'Total (j+k+1)No.Received |Delivered ($)($)($)of Settlement ($)
(g)(h)(i)(j)(k)(I)(m)
44,20E 979,797 979,797 1
12,465 375,457 375,457 2
8,582 187,391 187,391 3
3,366 51,23E 51,238 4
3,17C 3,170 5
3,334 103,986 103,989 6
3,826 207,631 207,631 7
1,851 65,165 65,165 8
169,00C 4,647,84C 4,647,840 9
3,662 77,98C 77,980 10
32C 6,88C 6,880 11
2,752 38,84C 38,840 12
1,60C 34,80C 34,800 13
1,211 25,114 25,114 14
4,664,491 632,543 607,430 952,750 109,445,154 4,884,184 115,282,08E
FERC FORM NO.1 (ED.12-90)Page 327.2
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)OX An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
PURCHASED POWER (Account 565)(Including power excnanges)
1.Report all power purchases made during the year.Also report exchanges of electricity (i.e.,transactions involving a balancing of
debits and credits for energy,capacity,etc.)and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a).Do not abbreviate or truncate the name or use
acronyms.Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b),enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (i.e.,the
supplier includes projects load for this service in its system resource planning).In addition,the reliability of requirement service must
be the same as,or second only to,the supplier's service to its own ultimate consumers.
LF -for long-term firm sentice."Long-term"means five years or longer and "firm"means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g.,the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service).This category should not be used for long-term firm service firm service
which meets the definition of RQ service.For all transaction identified as LF,provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF -for intermediate-term firm service.The same as LF service expect that "intermediate-term"means longer than one year but less
than five years.
SF -for short-term service.Use this category for all firm services,where the duration of each period of commitment for service is one
year or less.
LU -for long-term service from a designated generating unit."Long-term"means five years or longer.The availability and reliability of
service,aside from transmission constraints,must match the availability and reliability of the designated unit.
IU -for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term"means
longer than one year but less than five years.
EX -For exchanges of electricity.Use this category for transactions involving a balancing of debits and credits for energy,capacity,etc.
and any settlements for imbalanced exchanges.
OS -for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year.Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authorhy Statistical FERC Rate Average Actual De nand (MW)
Classifi-Schedule or Monthly Billing Average AverageNo.(Footnote Affiliations)cation Tariff Number Demand (MW)Monthly NCP Demand Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 NorthWestern Energy SF Mkt Tariff &WSPP.
2 Okanogan Public Utility District SF Okanogan PUD
3 Pacific NW Generation Coop SF Mkt Tariff &WSPP.
4 PacificCorp SF Mkt Tariff &WSPP
5 PacificCorp EX 160
6 PacificCorp Power Marketing SF Mkt Tariff &WSPP
7 Pend Oreille County PUD #1 SF Pend Oreille PUD
8 Pend Oreille County PUD #1 EX Generation Imbalae
9 Pend Oreille County PUD #1 EX NWPP
10 PG&E Energy Trading SF Mkt Tariff &WSPP
11 Phillips Ranch LU PURPA Agmt
12 Plummer Forest Products EX Generation Imbalan
13 Portland General Electric Company EX Vol No.9 Sch D
14 Portland General Electric Company EX 178
Total
FERC FORM NO.1 (ED.12-90)Page 326.3
Name of Respondent This Report Is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp(2)A Resubmission 04/30/2003 '
PU ACHASED POWEH(Account 555)(continued)(Including power exchanges)
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
4.In column (c),identify the FERC Rate Schedule Number or Tariff,or,for non-FERC jurisdictional sellers,include an appropriate
designation for the contract.On separate lines,list all FERC rate schedules,tariffs or contract designations under which service,as
identified in column (b),is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer)basis,enter
the monthly average billing demand in column (d),the average monthly non-coincident peak (NCP)demand in column (e),and the
average monthly coincident peak (CP)demand in column (f).For all other types of service,enter NA in columns (d),(e)and (f).Monthly
NCP demand is the maximum metered hourly (60-minute integration)demand in a month.Monthly CP demand is the metered demand
during the hour (60-minute integration)in which the supplier's system reaches its monthly peak.Demand reported in columns (e)and (f)
must be in megawatts.Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g)the megawatthours shown on bills rendered to the respondent.Report in columns (h)and (i)the megawatthours
of power exchanges received and delivered,used as the basis for settlement.Do not report net exchange.
7.Report demand charges in column (j),energy charges in column (k),and the total of any other types of charges,including
out-of-period adjustments,in column (I).Explain in a footnote all components of the amount shown in column (I).Report in column (m)
the total charge shown on bills received as settlement by the respondent.For power exchanges,report in column (m)the settlement
amount for the net receipt of energy.If more energy was delivered than received,enter a negative amount.If the settlement amount (I)
include credits or charges other than incremental generation expenses,or (2)excludes certain credits or charges covered by the
agreement,provide an explanatory footnote.
8.The data in column (g)through (m)must be totalled on the last line of the schedule.The total amount in column (g)must be
.reported as Purchases on Page 401,line 10.The total amount in column (h)must be reported as Exchange Received on Page 401,
,line 12.The total amount in column (i)must be reported as Exchange Delivered on Page 401,line 13.
9.Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES I COST/SETTLEMENT OF POWERIWl"0aWatt Hours I ine
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Received Delivered ($)($)($)of Settlement ($)
(g)(h)(i)(j)(k)(I)(m)
3,066 67,09E 67,098 1
128,496 2,307,092 2,307,093 2
1,71E 46,442 46,443 3
42,257 872,80E 872,805 4
26,850 27,600 696,377 696,377 5
29,631 887,26E 887,265 6
28,08C 562,37E 562,378 7
4,415 62,508 62,508 8
12,674 14,482 -11,039 -11,039 9
2,00C 41,80C 41,800 10
41 1,15E 1,156 11
277 12
9,679 9,528 13
428,675 429,740 14
4,664.491 632,543 607,430 952,750 109,445,154 4,884,184 115,282,08E
FERC FORM NO.1 (ED.12-90)Page 327.3
Name of Respondent This Report Is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp(2)A Resubmission 04/30/2003 '
PURCHASED POWER (Account 565)(Including power excnanges)
1.Report all power purchases made during the year.Also report exchanges of electricity (i.e.,transactions involving a balancing of
debits and credits for energy,capacity,etc.)and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a).Do not abbreviate or truncate the name or use
acronyms.Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b),enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (i.e.,the
supplier includes projects load for this service in its system resource planning).In addition,the reliability of requirement service must
be the same as,or second only to,the supplier's service to its own ultimate consumers.
LF -for long-term firm service."Long-term"means five years or longer and "firm"means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g.,the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service).This category should not be used for long-term firm service firm service
which meets the definition of RQ service.For all transaction identified as LF,provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF -for intermediate-term firm service.The same as LF service expect that "intermediate-term"means longer than one year but less
than five years.
SF -for short-term service.Use this category for all firm services,where the duration of each period of commitment for service is one
year or less.
LU -for long-term service from a designated generating unit."Long-term"means five years or longer.The availability and reliability of
service,aside from transmission constraints,must match the availability and reliability of the designated unit.
IU -for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term"means
longer than one year but less than five years.
EX -For exchanges of electricity.Use this category for transactions involving a balancing of debits and credits for energy,capacity,etc.
and any settlements for imbalanced exchanges.
OS -for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year.Describe the nature
of the service in a footnote for each adjustment.
Line Nameof Company or Public Authority Statistical FERC Rate Average Actual De nand (MW)
Classifi-Schedule or Monthly Billing Average Average
No.(Footnote Affiliations)cation Tariff Number Demand (MW)Monthly NCP Demand Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Portland General Electric Company SF Mkt Tariff &WSPP
2 Pinnacle West Capital Corp SF Mkt Tariff &WSPP
3 PPL Montana SF MktTariff &WSPP
4 Power Exchange Corp.SF WSPP
5 Puget Sound Energy SF MktTariff &WSPP
6 Puget Sound Energy EX MktTariff &WSPP
7 Sacramento Municipal Dist SF WSPP
8 Seattle City Light SF WSPP
9 Sempra Energy Trading SF Mkt Tariff &WSPP
10 Sheep Creek Hydro LU PURPA Agmt
11 Sierra Pacific Power SF Mkt Tariff &WSPP
12 Sovereign Energy IF Vol.No.10
13 Spokane,City of -Upriver Project LU PURPA Agmt
14 Tacoma Power SF WSPP
Total
FERC FORM NO.1 (ED.12-90)Page 326.4
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)X An Original (Mo,Da,Yr)Dec.31 2002(2)A Resubmission 04/30/2003 '
PU icHAshb POWEH(Account 555)(continued)(Including power exchanges)
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
4.In column (c),identify the FERC Rate Schedule Number or Tariff,or,for non-FERC jurisdictional sellers,include an appropriate
designation for the contract.On separate lines,list all FERC rate schedules,tariffs or contract designations under which service,as
identified in column (b),is provided.
5.For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer)basis,enter
the monthly average billing demand in column (d),the average monthly non-coincident peak (NCP)demand in column (e),and the
average monthly coincident peak (CP)demand in column (f).For all other types of service,enter NA in columns (d),(e)and (f).Monthly
NCP demand is the maximum metered hourly (60-minute integration)demand in a month.Monthly CP demand is the metered demand
during the hour (60-minute integration)in which the supplier's system reaches its monthly peak.Demand reported in columns (e)and (f)
must be in megawatts.Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g)the megawatthours shown on bills rendered to the respondent.Report in columns (h)and (i)the megawatthours
of power exchanges received and delivered,used as the basis for settlement.Do not report net exchange.
7.Report demand charges in column (j),energy charges in column (k),and the total of any other types of charges,including
out-of-period adjustments,in column (I).Explain in a footnote all components of the amount shown in column (1).Report in column (m)
the total charge shown on bills received as settlement by the respondent.For power exchanges,report in column (m)the settlement
amount for the net receipt of energy.If more energy was delivered than received,enter a negative amount.If the settlement amount (I)
include credits or charges other than incremental generation expenses,or (2)excludes certain credits or charges covered by the
agreement,provide an explanatory footnote.
8.The data in column (g)through (m)must be totalled on the last line of the schedule.The total amount in column (g)must be
reported as Purchases on Page 401,line 10.The total amount in column (h)must be reported as Exchange Received on Page 401,
line 12.The total amount in column (i)must be reported as Exchange Delivered on Page 401,line 13.
9.Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES I COST/SETTLEMENT OF POWERMegaWattHours Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Received Delivered ($)($)($)of Settlement ($)
(g)(h)(i)(j)(k)(I)(m)
I 40,101 1,082,82C 1,082,820 1
17,235 426,885 426,885 2
|
205,261 5,369,67E 5,369,678 3
35,53E 876,26E 876,269 4
47,161 1,338,95€1,338,956 5
112,097 112,097 6
2E 625 625 7
33,58C 542,31E 542,318 8
62,00C 1,352,112 1,352,112 9
i 7,29E 457,561 457,561 10
5,25C 182,35C 182,350 11
9,34E 193,404 193,404 12
69,234 1,642,057 1,642,057 13
94,742 1,642,39E 1,642,393 14
4,664,491 632,543 607,430 952,750 109,445,154 4,884,184 115,282,08E
FERC FORM NO.1 (ED.12-90)Page 327.4
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)DX An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
PURCHASED POWER (Account 555)(Including power excnanges)
1.Report all power purchases made during the year.Also report exchanges of electricity (i.e.,transactions involving a balancing of
debits and credits for energy,capacity,etc.)and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a).Do not abbreviate or truncate the name or use
acronyms.Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3.In column (b),enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service.Requirements service is service which the supplier plans to provide on an ongoing basis (i.e.,the
supplier includes projects load for this service in its system resource planning).In addition,the reliability of requirement service must
be the same as,or second only to,the supplier's service to its own ultimate consumers.
LF -for long-term firm service."Long-term"means five years or longer and "firm"means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g.,the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service).This category should not be used for long-term firm service firm service
which meets the definition of RQ service.For all transaction identified as LF,provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF -for intermediate-term firm service.The same as LF service expect that "intermediate-term"means longer than one year but less
than five years.
SF -for short-term service.Use this category for all firm services,where the duration of each period of commitment for service is one
year or less.
LU -for long-term service from a designated generating unit."Long-term"means five years or longer.The availability and reliability of
service,aside from transmission constraints,must match the availability and reliability of the designated unit.
IU -for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term"means
longer than one year but less than five years.
EX -For exchanges of electricity.Use this category for transactions involving a balancing of debits and credits for energy,capacity,etc.
and any settlements for imbalanced exchanges.
OS -for other service.Use this category only for those services which cannot be placed in the above-definedcategories,such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year.Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Denand (MW)
Classifi-Schedule or Monthly Billing Average Average
No.(Footnote Affiliations)cation Tariff Number Demand (MW)Monthly NCP Demand Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Tech Cominco Metals Ltd SF Mkt Tariff &WSPP
2 TransAlta Energy Marketing SF Mkt Tariff &WSPP
3 TransAlta Energy Marketing IF Mkt Tariff &WSPP
4 Turlock Irrigation District SF WSPP
5 TXU Energy Trading SF Mkt Tariff &WSPP
6 Williams Energy Marketing &Trading SF Mkt Tariff &WSPP
7 Wood Power Incorporated LU PURPA Agmt
8 Xcel Energy SF Mkt Tariff &WSPP
9 Jim White LU PURPA Agmt
10 Avista Corporation-Transmission SF 888
11 Other -Inadvertent Interchange EX
12
13
14
Total
FERC FORM NO.1 (ED.12-90)Page 326.5
Name of Respondent This Report Is:Date of Report Year of Report(1)OX An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp.(2)A Resubrnission 04/30/2003 '
TRANSMISSIOWOF ELECTRICITY FOR OTHERS (Account 456)(Continued)(including transactions reffered to as 'wheeling')
OS -for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
nonfirm service regardless of the length of the contract and service from,designated units of less than one year.Describe the nature of
the service in a footnote for each adjustment.
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
5.In column (e),identify the FERC Rate Schedule or Tariff Number,On separate lines,list all FERC rate schedules or contract
designations under which service,as identified in column (d),is provided.
6.Report receipt and delivery locations for all single contract path,"point to point"transmission service.In column (f),report the
designation for the substation,or other appropriate identification for where energy was received as specified in the contract.In column
(g)report the designation for the substation,or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h)the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h)must be in megawatts.Footnote any demand not stated on a megawatts basis and explain.
FERC Rate Point of Receipt Pointof Delivery Billing TRANSFER OF ENERGY LineScheduleof(Subsatation or Other (Substation or Other Demand MegaWatt Hours i MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)(g)(h)(i)(j)
FERC Elc Trf,26,789 26,78E 1
FERC Elc Trf,32,869 32,86E 2
FERC Elc Trf,3,395 3,396 3
FERC Elc Trf,8,400 8,40C 4
=ERCElc Trf,50 5C 5
FERC Elc Trf,20,636 20,63E 6
FERC No.Various Various 1,584,726 1,584,72E 7
ERC Elc Trf,10,709 10,70E 8
FERC Elc Trf,7,882 7,882 9
FERC Elc Trf,Bell Substation Consolidated 23 5,791 5,791 10
2ERC Elc Trf,5,451 5,451 11
FERC Elc Trf,37,843 37,842 12
FERC Elc Trf,4,984 4,984 13
=ERCElc Trf,11,301 11,301 14
PERC Elc Trf,1,296 1,29E 15
FERC Elc Trf,224 224 16
2ERC Elc Trf,976 97E 17
558 3,735,844 3,735,844
FERC FORM NO.1 (ED.12-90)Page 329
Name of Respondent This Report Is:Date of Report Year of Report
Avista Co (1)X An Original (Mo,Da,Yr)Dec.31 2002rp.(2)A Resubmission 04/30/2003 '
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)(Includingtransactions reffered to as 'wheeling')
8.Report in column (i)and (j)the total megawatthours received and delivered.
9.In column (k)through (n),report the revenue amounts as shown on bills or vouchers.In column (k),provide revenues from demand
charges related to the billing demand reported in column (h).In column (I),provide revenues from energy charges related to the
amount of energy transferred.In column (m),provide the total revenues from all other charges on bills or vouchers rendered,including
out of period adjustments.Explain in a footnote all components of the amount shown in column (m).Report in coltimn (n)the total
charge shown on bills rendered to the entity Listed in column (a).If no monetary settlement was made,enter zero (11011)in column
(n).Provide a footnote explaining the nature of the non-monetary settlement,including the amount and type of energy or service
rendered.
10.Provide total amounts in column (i)through (n)as the last Line.Enter "TOTAL"in column (a)as the Last Line.The total amounts
in columns (i)and (j)must be reported as Transmission Received and Delivered on Page 401,Lines 16 and 17,respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges I (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
49,096 49,096 1
90,474 90,474 2
10,053 10,053 3
32,153 32,153 4
948 948 5
46,586 15,634 62,220 6
6,677,624 6,677,624 7
34,255 34,255 8
16,388 16,388 9
32,582 57,376 89,958 10
13,848 13,848 11
83,339 83,339 12
10,115 10,115 13
22,949 22,949 14
2,638 2,638 15
457 457 16
1,964 1,964 17
11,033,648 27,261 135,680 11,196,589
FERC FORM NO.1 (ED.12-90)Page 330
Name of Respondent This Re ort Is:Date of Report Year of Report
Avista Corp (1)X An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
TRANSMI3SION OF ELECTRICITY FOR OTHE RS (Account 456)(Includingtransactions referred to as 'wheeling')
1.Report all transmission of electricity,i.e.,wheeling,provided for other electric utilities,cooperatives,municipalities,other public
authorities,qualifying facilities,non-traditional utility suppliers and ultimate customers.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a),(b)and (c).
3.Report in column (a)the company or public authority that paid for the transmission service.Report in column (b)the company or
public authority that the energy was received from and in column (c)the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority.Do not abbreviate or truncate name or use acronyms.Explain in a footnote
I any ownership interest in or affiliation the respondent has with the entities listed in columns (a),(b)or (c)
4.In column(d)enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
LF -for Long-term firm transmission service."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
LF,provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get
out of the contract.
SF -for short-term firm transmission service.Use this category for all firm services,where the duration of each period of commitment
for service is less than one year.
Line Payment By Energy Received From Energy Delivered To Statistical
No (Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 Grant County Public Utility District Grant County Public Utility Dist Grant County Public Utility Dist LF
2 Idacorp Energy Puget Sound Energy Idaho Power Company SF
3 Idacorp Energy Douglas PUD Idaho Power Company SF
4 Idacorp Energy Chelan PUD Idaho Power Company SF
5 Idacorp Energy Pacificorp Idaho Power Company SF
6 Idacorp Energy Bonneville Power Administration Idaho Power Company SF
7 Idacorp Energy Seattle City Light Idaho Power Company SF
8 Idaho Power Company Idaho Power Company Portland General Electric OS
9 Idaho Power Company Idaho Power Company Puget Sound Energy OS
10 Idaho Power Company Idaho Power Company Bonneville Power Administration OS
11 Idaho Power Company Idaho Power Company Pacificorp OS
12 Idaho Power Company Portland General Electric Idaho Power Company OS
I 13 Idaho Power Company Puget Sound Energy Idaho Power Company OS
14 Idaho Power Company Grant County PUD Idaho Power Company OS
15 Idaho Power Company Pacificorp Idaho Power Company OS
16 Idaho Power Company Bonneville Power Administration Idaho Power Company OS
17 Idaho Power Company Douglas PUD Idaho Power Company OS
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.1
Name of Ñspondent This Report is:Date of Report Year of Report
Avista Corp (1)OX An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TRANSMISSIOWOF ELECTRICITY FOR OTHERS (Account 456)(Continued)(including transactions reffered to as 'wheeling')
OS -for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
nonfirm service regardless of the length of the contract and service from,designated units of less than one year.Describe the nature of
the service in a footnote for each adjustment.
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
5.In column (e),identify the FERC Rate Schedule or Tariff Number,On separate lines,list all FERC rate schedules or contract
designations under which service,as identified in column (d),is provided.
6.Report receipt and delivery locations for all single contract path,"point to point"transmission service.In column (f),report the
designation for the substation,or other appropriate identification for where energy was received as specified in the contract.In column
(g)report the designation for the substation,or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h)the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h)must be in megawatts.Footnote any demand not stated on a megawatts basis and explain.
FERC Rate Point of Receipt Point of Delivery I Billing TRANSFER OF ENERGY LineScheduleof(Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWattHours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)(g)(h)(i)(j)
FERC No.Larson Substation Round Lk Coulee City 25 97,445 97,44E 1
FERC Elc Trf,200 20C 2
FERC Elc Trf,400 40C 3
FERC Elc Trf,400 40C 4
FERC Elc Trf,830 83C 5
FERC Elc Trf,5,286 5,286 6
FERC Elc Trf,215 21E 7
FERC Elc Trf,200 20C 8
FERC Elc Trf,25,568 25,56E 9
FERC Elc Trf,9,410 9,41C 10
FERC Elc Trf,950 95C 11
FERC ElcTd,851 851 12
FERC Elc Trf,6,567 6,567 13
FERC Elc Trf,18,501 18,501 14
FERC Elc Trf,2,015 2,01E 15
FERC Eic Trf,16,816 16,81E 16
FERC Elc Trf,1,113 1,112 17
558 3,735,844 3,735,844
FERC FORM NO.1 (ED.12-90)Page 329.1
Jame of Respondent This Report Is:Date of Report Year of Report
wista Corp.(1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)(Including transactions reffered to as 'wheeling')
.Report in column (i)and (j)the total megawatthours received and delivered.
9.In column (k)through (n),report the revenue amounts as shown on bills or vouchers.In column (k),provide revenues from demand
charges related to the billing demand reported in column (h).In column (l),provide revenues from energy charges related to the
imount of energy transferred.In column (m),provide the total revenues from all other charges on bills or vouchers rendered,including
>ut of period adjustments.Explain in a footnote all components of the amount shown in column (m).Report in column (n)the total
charge shown on bills rendered to the entity Listed in column (a).If no monetary settlement was made,enter zero (11011)in column
).Provide a footnote explaining the nature of the non-monetary settlement,including the amount and type of energy or service
andered.
40.Provide total amounts in column (i)through (n)as the last Line.Enter "TOTAL"in column (a)as the Last Line.The total amounts
in columns (i)and (j)must be reported as Transmission Received and Delivered on Page 401,Lines 16 and 17,respectively.
I 1.Footnote entries and provide explanations following all required data.
REVENUE FROMTRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+1+m)No.
(k)(l)(m)(n)
21,830 7,601 29,431 1
573 573 2
1,146 1,146 3
1,145 1,145 4
2,377 2,377 5
15,138 15,138 6
616 616 7
400 400 8
2,567 2,567 9
18,144 18,144 10
1,848 1,848 11
4,359 4,359 12
24,735 24,735 13
109,940 109,940 14
9,173 9,173 15
34,772 34,772 16
2,673 2,673 17
11,033,648 27,261 135,680 11,196,589
FERC FORM NO.1 (ED.12-90)Page 330.1
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TRANSMl3SION OFELECTRICITY FOR OTHERS (Account 456)(Including transactions referred to as 'wheeling')
1.Report all transmission of electricity,i.e.,wheeling,provided for other electric utilities,cooperatives,municipalities,other public
authorities,qualifying facilities,non-traditional utility suppliers and ultimate customers.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a),(b)and (c).
3.Report in column (a)the company or public authoritythat paid for the transmission service.Report in column (b)the company or
public authority that the energy was received from and in column (c)the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority.Do not abbreviate or truncate name or use acronyms.Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a),(b)or (c)
4.In column(d)enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
LF -for Long-term firm transmission service."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
LF,provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get
out of the contract.
SF -for short-term firm transmission service.Use this categoryfor all firm services,where the duration of each period of commitment
for service is less than one year.
Line Payment By Energy Received From Energy Delivered To Statistical
No (Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 Idaho Power Company Chelan PUD Idaho Power Company OS
2 idaho Power Company Tacoma Idaho Power Company OS
3 Idaho Power Company Seattle City Light Idaho Power Company OS
4 Idaho Power Company Northwestern Energy Idaho Power Company OS
5 Idaho Power Company Bonneville Power Administratio Northwestern Energy OS
6 Idaho Power Company Northwestern Energy Puget Sound Energy OS
7 Idaho Power Company Northwestern Energy Portland General Electric OS
8 Idaho Power Company Idaho Power Company Puget Sound Energy SF '
9 Idaho Power Company Idaho Power Company Bonneville Power Administration SF
10 \daho Power Company Idaho Power Company Grant PUD SF
11 Idaho Power Company Idaho Power Company Pacificorp SF
12 Idaho Power Company Idaho Power Company Portland General Electric SF
13 Idaho Power Company Bonneville Power Administration Idaho Power Company SF
14 Idaho Power Company Grant PUD Idaho Power Company SF
15 Idaho Power Company Pacificorp Idaho Power Company SF
16 Idaho Power Company Portland General Electric Idaho Power Company SF
17 Idaho Power Company Puget Sound Energy Idaho Power Company SF
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.2
Name of Respondent This Report Is:Date of Report Year of Report
Avista Co (1)QX An Original (Mo,Da,Yr)Dec.31,2002rp.(2)CA Resubmission 04/30/2003
TRANSMISSIOWOF ELECTRICITY FOR OTHERS (Account 456)(Continued)(Including transactions reffered to as 'wheeling')
OS -for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
nonfirm service regardless of the length of the contract and service from,designated units of less than one year.Describe the nature of
the service in a footnote for each adjustment.
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
5.In column (e),identify the FERC Rate Schedule or Tariff Number,On separate lines,list all FERC rate schedules or contract
designations under which service,as identified in column (d),is provided.
6.Report receipt and delivery locations for all single contract path,"point to point"transmission service.In column (f),report the
designation for the substation,or other appropriate identification for where energy was received as specified in the contract.In column
(g)report the designation for the substation,or other appropriate identification for where energy was delivered as specified in thecontract.
7.Report in column (h)the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h)must be in megawatts.Footnote any demand not stated on a megawatts basis and explain.
FERC Rate Point of Receipt Pointof Delivery Billing TRANSFER OF ENERGY LineScheduleof(Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)(9)(h)(i)(j)
FERC Elc Trf,16,920 16,92C 1
FERC Elc Trf,96 96 2
FERC Elc Trf,5,710 5,71C 3
IFERC Elc Trf,1,116 1,116 4
FERC Eic Trf,48 4E 5
FERC Elc Trf,4,640 4,64C 6
FERC Elc Trf,2,400 2,40C 7
FERC Elc Trf,32,584 32,584 8
FERC Elc Trf,30,366 30,36E 9
IFERC Elc Trf,1,260 1,26C 10
FERC Elc Trf,3,480 3,48C 11
FERC Elc Trf,28,149 28,14E 12
FERC Elc Trf,195,653 195,652 13
FERC Elc Trf,1,197 1,197 14
FERC Eic Trf,4,157 4,157 15
FERC Elc Trf,250 25C 16
FERC Elc Trf,426 42E 17
558 3,735,844 3,735,844
FERC FORM NO.1 (ED.12-90)Page 329.2
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)OX An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)(Including transactions reffered to as 'wheeling')
8.Report in column (i)and (j)the total megawatthours received and delivered.
9.In column (k)through (n),report the revenue amounts as shown on bills or vouchers.In column (k),provide revenues from demand
charges related to the billing demand reported in column (h).In column (I),provide revenues from energy charges related to the
amount of energy transferred.In column (m),provide the total revenues from all other charges on bills or vouchers rendered,including
out of period adjustments.Explain in a footnote all components of the amount shown in column (m).Report in column (n)the total
charge shown on bills rendered to the entity Listed in column (a).If no monetary settlement was made,enter zero (11011)in column
(n).Provide a footnote explaining the nature of the non-monetary settlement,including the amount and type of energy or service
rendered.
10.Provide total amounts in column (i)through (n)as the last Line.Enter "TOTAL"in column (a)as the Last Line.The total amounts
in columns (i)and (j)must be reported as Transmission Received and Delivered on Page 401,Lines 16 and 17,respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERO
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
63,418 63,418 1
192 192 2
32,046 32,046 3
2,232 2,232 4
372 372 5
9,024 9,024 6
4,668 4,668 7
108,056 108,056 8
106,902 106,902 9
4,732 4,732 10
12,874 12,874 11
92,067 92,067 12
406,341 406,341 13
4,113 4,113 14
13,767 13,767 15
879 879 16
1,278 1,278 17
11,033,648 27,261 135,680 11,196,589
FERC FORM NO.1 (ED.12-90)Page 330.2
Name of Respondent This Report Is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp(2)A Resubmission 04/30/2003 '
I TRANSMISSION OF ELECTRICITY FOR OTHE RS (Account 456)(Including transactions referred to as 'wheeling')
L Report all transmission of electricity,i.e.,wheeling,provided for other electric utilities,cooperatives,municipalities,other public
authorities,qualifying facilities,non-traditional utility suppliers and ultimate customers.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a),(b)and (c).
3.Report in column (a)the company or public authority that paid for the transmission service.Report in column (b)the company or
3ublic authority that the energy was received from and in column (c)the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority.Do not abbreviate or truncate name or use acronyms.Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a),(b)or (c)
4.In column(d)enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
-F -for Long-term firm transmission service."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
LF,provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get
out of the contract.
AF -for short-term firm transmission service.Use this category for all firm services,where the duration of each period of commitment
for service is less than one year.
ine Payment By Energy Received From Energy Delivered To Statistical
(Company of Public Authority)(Company of Public Authority)(Companyof Public Authority)Classifi-No.(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 Idaho Power Company Douglas PUD Idaho Power Company SF
2 Idaho Power Company Chelan PUD Idaho Power Company SF
3 Idaho Power Company Seattle City Light Idaho Power Company SF
4 Idaho Power Company Northwestern Energy Bonneville Power Administration SF
5 Mirant Bonneville Power Administration Idaho Power Company OS
6 Mirant Bonneville Power Administration Northwestern Energy OS
7 Mirant Grant PUD Northwestern Energy OS
8 Mirant Pacificorp Northwestern Energy OS
9 Morgan Stanley Capital Group Chelan PUD Idaho Power Company OS
10 Morgan Stanley Capital Group Bonneville Power Administration Idaho Power Company OS
11 Morgan Stanley Capital Group Northwestern Energy Idaho Power Company OS
12 Morgan Stanley Capital Group Portland General Electric Idaho Power Company OS
13 Morgan Stanley Capital Group Pacificorp Idaho Power Company OS
14 Morgan Stanley Capital Group Puget Sound Energy Idaho Power Company OS
15 Morgan Stanley Capital Group Northwestern Energy Puget Sound Energy OS
16 Morgan Stanley Capital Group Northwestern Energy Pacificorp OS
17 Morgan Stanley Capital Group Northwestern Energy Bonneville Power Administration OS
I
I
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.3
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)X An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)(Including transactions reffered to as 'wheeling')
OS -for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
nonfirm service regardless of the length of the contract and service from,designated units of less than one year.Describe the nature of
the service in a footnote for each adjustment.
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
5.In column (e),identify the FERC Rate Schedule or Tariff Number,On separate lines,list all FERC rate schedules or contract
designations under which service,as identified in column (d),is provided.
6.Report receipt and delivery locations for all single contract path,"point to point"transmission service.In column (f),report the
designation for the substation,or other appropriate identification for where energy was received as specified in the contract.In column
(g)report the designation for the substation,or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h)the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h)must be in megawatts.Footnote any demand not stated on a megawatts basis and explain.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineScheduleof(Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)(g)(h)(i)(j)
,FERC Elc Trf,128 12E 1
FERC Elc Trf,4,006 4,00E 2
IFERC Elc Trf,9,775 9,776 3
FERC Elc Trf,3,775 3,776 4
FERC Elc Trf,60 6C 5
FERC Elc Trf,800 80C 6
FERC Elc Trf,400 40C 7
FERC Elc Trf,400 40C 8
FERC Elc Trf,400 40C 9
FERC Elc Trf,1,600 1,60C 10
FERC Elc Trf,5,800 5,80C 11
FERC Elc Trf,576 57E 12
FERC Elc Trf,224 224 13
FERC Elc Trf,800 80C 14
FERC Elc Trf,896 89E 15
FERC Elc Trf,3,189 3,18E 16
FERC Elc Trf,400 40C 17
558 3,735,844 3,735,844
FERC FORM NO.1 (ED.12-90)Page 329.3
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)DX An Original (Mo,Da,Yr)Dec.31,2002
I
(2)A Resubmission 04/30/2003
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)(Including transactions reffered to as 'wheeling')
1.Report in column (i)and (j)the total megawatthours received and delivered.
9.In column (k)through (n),report the revenue amounts as shown on bills or vouchers.In column (k),provide revenues from demand
charges related to the billing demand reported in column (h).In column (I),provide revenues from energy charges related to the
amount of energy transferred.In column (m),provide the total revenues from all other charges on bills or vouchers rendered,including
aut of period adjustments.Explain in a footnote all components of the amount shown in column (m).Report in column (n)the total
charge shown on bills rendered to the entity Listed in column (a).If no monetary settlement was made,enter zero (11011)in column
n).Provide a footnote explaining the nature of the non-monetary settlement,including the amount and type of energy or service
endered.
10.Provide total amounts in column (i)through (n)as the last Line.Enter "TOTAL"in column (a)as the Last Line.The total amounts
in columns (i)and (j)must be reported as Transmission Received and Delivered on Page 401,Lines 16 and 17,respectively.
11.Footnote entries and provide explanations following all required data.
I
REVENUE FROM TRANSMlSSICN OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
356 356 1
11,896 11,896 2
32,373 32,373 3
14,162 14,162 4
121 121 5
1,610 1,610 6
805 805 7
805 805 8
914 914 9
3,429 3,429 10
13,233 13,233 11
1,317 1,317 12
512 512 13
1,829 1,829 14
1,901 1,901 15
6,639 6,639 16
867 867 17
11,033,648 27,261 135,680 11,196,589
FERC FORM NO.1 (ED.12-90)Page 330.3
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TRANSMI SION OF ELECTRICITY FOR OTHERS (Account 456)(Including transactions referred to as 'wheeling')
1.Report all transmission of electricity,i.e.,wheeling,provided for other electric utilities,cooperatives,municipalities,other public
authorities,qualifying facilities,non-traditional utility suppliers and ultimate customers.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a),(b)and (c).
3.Report in column (a)the company or public authority that paid for the transmission service.Report in column (b)the company or
public authority that the energy was received from and in column (c)the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority.Do not abbreviate or truncate name or use acronyms.Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a),(b)or (c)
4.In column(d)enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
LF -for Long-term firm transmission service."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
LF,provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get
out of the contract.
SF -for short-term firm transmission service.Use this category for all firm services,where the duration of each period of commitment
for service is less than one year.
Line Payment By Energy Received From Energy Delivered To Statistical
No (Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(FootnoteAffiliation)(FootnoteAffiliation)(FootnoteAffiliation)cation
(a)(b)(c).(d)
1 Northwestern Energy Idaho Power Company Northwestern Energy SF
2 Northwestern Energy Northwestern Energy Bonneville Power Administration OS
3 Northwestern Energy Northwestern Energy Portland General Electric OS
4 Northwestern Energy Northwestern Energy Chelan PUD OS
5 Northwestern Energy Bonneville Power Administration Idaho Power Company OS
6 Northwestern Energy Northwestern Energy Puget Sound Energy OS
7 PacifiCorp Northwestern Energy Pacificorp OS
8 PacifiCorp PacifiCorp Northwestern Energy OS
9 PacifiCorp PacifiCorp PacifiCorp LF
10 Pacific Power Marketing Northwestern Energy Bonneville Power Adminstration OS
11 Pacific Power Marketing Northwestern Energy Portland General Electric OS
12 PPL Montana Northwestern Energy Pacificorp OS
13 PPL Montana Northwestern Energy Portland General Electric OS
14 PPL Montana Northwestern Energy Chelan PUD OS
15 PPL Montana Northwestern Energy Grant County PUD OS
16 PPL Montana Northwestern Energy Puget Sound Energy SF
17 PPL Montana Northwestern Energy Bonneville Power Adminstration SF
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.4
Name of Respondent This Report Is:Date of Report Year of Report
Avista Cor .
(1)OX An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)(Including transactions reffered to as 'wheeling')
OS -for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
nonfirm service regardless of the length of the contract and service from,designated units of less than one year.Describe the nature of
the service in a footnote for each adjustment.
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
5.In column (e),identify the FERC Rate Schedule or Tariff Number,On separate lines,list all FERC rate schedules or contract
designations under which service,as identified in column (d),is provided.
6.Report receipt and delivery locations for all single contract path,"point to point"transmission service.In column (f),report the
designation for the substation,or other appropriate identification for where energy was received as specified in the contract.In column
(g)report the designation for the substation,or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h)the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h)must be in megawatts.Footnote any demand not stated on a megawatts basis and explain.
FERC Rate Pointof Receipt Point of Delivery Billing TRANSFER OF ENERGY LineScheduleof(Subsatation or Other (Substation or Other Demand MegaWatt Hours 'MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)(g)(h)(i)(j)
'FERC Elc Trf,9,597 9,597 1
FERC Elc Trf,1,541 1,541 2
FERC Elc Trf,220 22C 3
ERC Elc Trf,46 46 4
ERC Elc Trf,80 8C 5
FERC Elc Trf,355 355 6
FERC Elc Trf,44,114 44,114 7
ERC Eic Trf,35,849 35,84E 8
FERC No.182 Lolo-WallaWalla Dry Gulch 115/60 KV 20 73,733 73,732 9
FERC Elc Trf,600 60C 10
ERC Elc Trf,400 40C 11
FERC Elc Trf,2,281 2,281 12
.FERC Elc Trf,11,685 11,68E 13
FERC Elc Trf,1,967 1,967 14
'FERC Elc Trf,2,538 2,53E 15
FERC Elc Trf,5,816 5,81E 16
FERC Elc Trf,18,546 18,54E 17
558 3,735,844 3,735,844
FERC FORM NO.1 (ED.12-90)Page 329.4
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
I HANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)(Including transactions reffered to as 'wheeling')
8.Report in column (i)and (j)the total megawatthours received and delivered.
9.In column (k)through (n),report the revenue amounts as shown on bills or vouchers.In column (k),provide revenues from demand
charges related to the billing demand reported in column (h).In column (I),provide revenues from energy charges related to the
amount of energy transferred.In column (m),provide the total revenues from all other charges on bills or vouchers rendered,including
out of period adjustments.Explain in a footnote all components of the amount shown in column (m).Report in column (n)the total
charge shown on bills rendered to the entity Listed in column (a).If no monetary settlement was made,enter zero (11011)in column
(n).Provide a footnote explaining the nature of the non-monetary settlement,including the amount and type of energy or service
rendered.
10.Provide total amounts in column (i)through (n)as the last Line.Enter "TOTAL"in column (a)as the Last Line.The total amounts
in columns (i)and (j)must be reported as Transmission Received and Delivered on Page 401,Lines 16 and 17,respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
214,152 214,152 1
3,587 3,587 2
566 566 3
95 95 4
186 186 5
1,379 1,379 6
96,808 96,808 7
75,088 75,088 8
242,017 242,017 9
1,200 1,200 10
800 800 11
4,579 4,579 12
23,453 23,453 13
4,370 4,370 14
5,080 5,080 15
11,576 11,576 16
37,390 37,390 17
11,033,648 27,261 135,680 11,196,589
FERC FORM NO.1 (ED.12-90)Page 330.4
Name of Respondent This Report Is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp(2)A Resubmission 04/30/2003 '
TRANSMI3SION OF ELECTRICITY FOR OTHE RS (Account 456)(Including transactions referred to as 'wheeling')
1.Report all transmission of electricity,i.e.,wheeling,provided for other electric utilities,cooperatives,municipalities,other public
authorities,qualifying facilities,non-traditional utility suppliers and ultimate customers.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a),(b)and (c).
3.Report in column (a)the company or public authority that paid for the transmission service.Report in column (b)the company or
public authority that the energy was received from and in column (c)the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority.Do not abbreviate or truncate name or use acronyms.Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a),(b)or (c)
4.In column(d)enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
LF -for Long-term firm transmission service."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
LF,provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get
out of the contract.
SF -for short-term firm transmission service.Use this category for all firm services,where the duration of each period of commitment
for service is less than one year.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Companyof Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 PPL Montana Chelan PUD Northwestern Energy OS
2 PPL Montana Bonneville Power Adminstration Northwestern Energy OS
3 PPL Montana PacifiCorp Northwestern Energy OS
4 PPL Montana Grant County PUD Northwestern Energy OS
5 Pinnacle West Idaho Power Company Puget Sound Energy OS
6 Pinnacle West Idaho Power Company Portland General Electric OS
7 Pinnacle West Idaho Power Company Bonneville Power Adminstration OS
8 PinnacleWest !Idaho Power Company Grant PUD OS
9 PinnacleWest Bonneville Power Adminstration Idaho Power Company OS
10 Pinnacle West Grant PUD Idaho Power Company OS
11 Pinnacle West PacifiCorp Idaho Power Company OS
I
12 Pinnacle West Bonneville Power Adminstration PacifiCorp OS
,13 PinnacleWest Puget Sound Energy Idaho Power Company OS
14 PinnacleWest Chelan PUD Idaho Power Company OS
'15 PinnacleWest Douglas PUD Idaho Power Company OS
16 PinnacleWest Tacoma Power Idaho Power Company OS
17 Pinnacle West Seattle City Light Idaho Power Company OS
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.5
Name of Respondent This Re ort Is:Date of Report Year of Report
Avista Corp.(1)X An Original (Mo,Da,Yr)Dec.31 2002
(2)A Resubmission 04/30/2003 '
TRANSMISSIOW OF ELECTRICITY FOR OTHERS (Account 456)(Continued)(Including transactions reffered to as 'wheeling')
OS -for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
nonfirm service regardless of the length of the contract and service from,designated units of less than one year.Describe the nature of
the service in a footnote for each adjustment.
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
5.In column (e),identify the FERC Rate Schedule or Tariff Number,On separate lines,list all FERC rate schedules or contract
designations under which service,as identified in column (d),is provided.
6.Report receipt and delivery locations for all single contract path,"point to point"transmission service.In column (f),report the
designation for the substation,or other appropriate identification for where energy was received as specified in the contract.In column
(g)report the designation for the substation,or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h)the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h)must be in megawatts.Footnote any demand not stated on a megawatts basis and explain.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineScheduleof(Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)(j)
FERC Elc Trf,400 40C 1
FERC Elc Trf,25 25 2
FERC Elc Trf,150 15C 3
FERC Elc Trf,340 34C 4
FERC Elc Trf,200 20C 5
FERC Elc Trf,963 962 6
FERC Elc Trf,400 40C 7
FERC Elc Trf,200 20C 8
FERC Elc Trf,53,784 53,784 9
FERC Elc Trf,912 912 10
FERC Elc Trf,2,767 2,767 11
FERC Elc Trf,597 597 12
FERC Elc Trf,25,301 25,301 13
FERC Elc Trf,8,275 8,27E 14
FERC Elc Trf,800 80C 15
FERC Elc Trf,373 372 16
FERC Elc Trf,3,320 3,32C 17
558 3,735,844 3,735,844
FERC FORM NO.1 (ED.12-90)Page 329.5
Mame of Respondent This Report Is:Date of Report Year of Report
(1)QXAn Original (Mo,Da,Yr)Dec.31 2002AvistaCorp.(2)A Resubmission 04/30/2003 '
TRANSMlŠSION OF ELECTRICITY FOR¯OTHERS(Account 456)(Continued)(Including transactions reffered to as 'wheeling')
1.Report in column (i)and (j)the total megawatthours received and delivered.
9.In column (k)through (n),report the revenue amounts as shown on bills or vouchers.In column (k),provide revenues from demand
charges related to the billing demand reported in column (h).In column (1),provide revenues from energy charges related to the
amount of energy transferred.In column (m),provide the total revenues from all other charges on bills or vouchers rendered,including
>ut of period adjustments.Explain in a footnote all components of the amount shown in column (m).Report in column (n)the total
charge shown on bills rendered to the entity Listed in column (a).If no monetary settlement was made,enter zero (11011)in column
'n).Provide a footnote explaining the nature of the non-monetary settlement,including the amount and type of energy or service
endered.
10.Provide total amounts in column (i)through (n)as the last Line.Enter "TOTAL"in column (a)as the Last Line.The total amounts
in columns (i)and (j)must be reported as Transmission Received and Delivered on Page 401,Lines 16 and 17,respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERO
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
800 800 1
50 50 2
300 300 3
680 680 4
404 404 5
1,944 1,944 6
800 800 7
400 400 8
150,810 150,810 9
2,357 2,357 10
7,285 7,285 11
1,890 1,890 12
68,436 68,436 13
23,210 23,210 14
2,068 2,068 15
814 814 16
9,728 9,728 17
|
11,033,648 27,261 135,680 11,196,589
FERC FORM NO.1 (ED.12-90)Page 330.5
Name of Respondent This Report Is:Date of Report Year of Report
(1)[¯]XAn Original (Mo,Da,Yr)Dec.31 2002AvistaCorp.(2)A Resubmission 04/30/2003 '
TRANSMI3SION OF ELECTRICITY FOR OTHERS (Account 456)(Including transactions referred to as 'wheeling')
1.Report all transmission of electricity,i.e.,wheeling,provided for other electric utilities,cooperatives,municipalities,other public
authorities,qualifying facilities,non-traditional utility suppliers and ultimate customers.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a),(b)and (c).
3.Report in column (a)the company or public authority that paid for the transmission service.Report in column (b)the company or
public authority that the energy was received from and in column (c)the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority.Do not abbreviate or truncate name or use acronyms.Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a),(b)or (c)
4.In column(d)enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
LF -for Long-term firm transmission service."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
LF,provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get
out of the contract.
SF -for short-term firm transmission service.Use this category for all firm services,where the duration of each period of commitment
for service is less than one year.
Line Payment By Energy Received From Energy Delivered To Statistical
No (Companyof Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 Pinnacle West Seattle City Light Portland General Electric OS
2 Pinnacle West Portland General Electric Idaho Power Company OS
3 Pinnacle West Bonneville Power Adminstration Idaho Power Company SF
4 Pinnacle West Chelan PUD Idaho Power Company SF
5 Pinnacle West Grant PUD idahu Fovvm Company O'¯
6 Pinnacle West PacifiCorp Idaho Power Company SF
7 Pinnacle West Puget Sound Energy Idaho Power Company SF
8 Pinnacle West Seattle City Light Idaho Power Company SF
9 Pinnacle West Bonneville Power Adminstration PacifiCorp SF
10 Powerex Northwestern Energy Bonneville Power Administration LF
11 Powerex Northwestern Energy Chelan PUD LF
12 Powerex Northwestern Energy Portland General Electric LF
13 Powerex Northwestern Energy Puget Sound Energy LF
14 Powerex Northwestern Energy Bonneville Power Administration OS
15 Powerex Northwestern Energy Grant PUD OS
16 Powerex Idaho Power Company Bonneville Power Administration OS
17 Powerex Bonneville Power Administration Northwestern Energy OS
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.6
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TRANSMISSIObl OF ELECTRICITY FOR OTHERS (Account 456)(Continued)(Including transactions reffered to as 'wheeling')
~)S
-for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
nonfirm service regardless of the length of the contract and service from,designated units of less than one year.Describe the nature of
the service in a footnote for each adjustment.
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
5.In column (e),identify the FERC Rate Schedule or Tariff Number,On separate lines,list all FERC rate schedules or contract
designations under which service,as identified in column (d),is provided.
5.Report receipt and delivery locations for all single contract path,"point to point"transmission service.In column (f),report the
designation for the substation,or other appropriate identification for where energy was received as specified in the contract.In column
I (g)report the designation for the substation,or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h)the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h)must be in megawatts.Footnote any demand not stated on a megawatts basis and explain.
I
I FERC Rate Pointof Receipt 'Point of Delivery Billing TRANSFER OF ENERGY LineScheduleof(Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.
,Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)(g)(h)(i)(j)
FERC Elc Trf,40 4C 1
ERC Elc Trf,400 40C 2
FERC Elc Trf,31,491 31,491 3
¯ERC Elc Trf,4,575 4,57E 4
ERC Elc Trf,9,431 9,431 5
FERC Elc Trf,1,233 1,232 6
FERC Elc Trf,955 95E 7
ERC Elc Trf,1,244 1,244 8
FERC Eic Trf,200 20C 9
FERC Elc Trf,Hot Springs Vantage 100 4,665 4,66E 10
ERC Elc Trf,Hot Springs Vantage 100 180 18C 11
FERC Elc Trf,Hot Springs Vantage 100 7,330 7,33C 12
FERC Elc Trf,Hot Springs Vantage 100 24 24 13
FERC Elc Trf,13,380 13,38C 14
FERCElcTd,75 7E 15
FERC Elc Trf,191 191 16
FERC Elc Trf,432 432 17
558 3,735,844 3,735,844
FERC FORM NO.1 (ED.12-90)Page 329.6
Name of Respondent This Report Is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp.(2)A Resubmission 04/30/2003 '
TRANSMISSION OF El ECTRICITY FOR OTHERS (Account 456)(Continued)(including transactions reffered to as 'wheeling')
8.Report in column (i)and (j)the total megawatthours received and delivered.
9.In column (k)through (n),report the revenue amounts as shown on bills or vouchers.In column (k),provide revenues from demand
charges related to the billing demand reported in column (h).In column (I),provide revenues from energy charges related to the
amount of energy transferred.In column (m),provide the total revenues from all other charges on bills or vouchers rendered,including
out of period adjustments.Explain in a footnote all components of the amount shown in column (m).Report in column (n)the total
charge shown on bills rendered to the entity Listed in column (a).If no monetary settlement was made,enter zero (11011)in column
(n).Provide a footnote explaining the nature of the non-monetary settlement,including the amount and type of energy or service
rendered.
10.Provide total amounts in column (i)through (n)as the last Line.Enter "TOTAL"in column (a)as the Last Line.The total amounts
in columns (i)and (j)must be reported as Transmission Received and Delivered on Page 401,Lines 16 and 17,respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSIC N OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
127 127 1
1,034 1,034 2
140,850 140,850 3
27,152 27,152 4
55,972 55,972 5
7,317 7,317 6
5,668 5,668 7
7,383 7,383 8
1,187 1,187 9
53,537 53,537 10
2,066 2,066 11
84,122 84,122 12
275 275 13
27,586 27,586 14
157 157 15
385 385 16
877 877 17
11,033,648 27,261 135,680 11,196,589
FERC FORM NO.1 (ED.12-90)Page 330.6
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)X An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
TRANSMISSION OF ELECTRICITYFOR OTHE RS (Account 456)(Including transactions referred to as 'wheeling')
1.Report all transmission of electricity,i.e.,wheeling,provided for other electric utilities,cooperatives,municipalities,other public
authorities,qualifying facilities,non-traditional utility suppliers and ultimate customers.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a),(b)and (c).
3.Report in column (a)the company or public authority that paid for the transmission service.Report in column (b)the company orpublicauthoritythattheenergywasreceivedfromandincolumn(c)the company or public authority that the energy was delivered to.Provide the full name of each company or public authority.Do not abbreviate or truncate name or use acronyms.Explain in a footnoteanyownershipinterestinoraffiliationtherespondenthaswiththeentitieslistedincolumns(a),(b)or (c)
4.In column(d)enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
LF -for Long-term firm transmission service."Long-term"means one year or longer and "firm"means that service cannot beinterruptedforeconomicreasonsandisintendedtoremainreliableevenunderadverseconditions.For all transactions identified asLF,provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally getoutofthecontract.
SF -for short-term firm transmission service.Use this category for all firm services,where the duration of each period of commitment
for service is less than one year.
Line Payment By Energy Received From Energy Delivered To Statistical
No (Company of Public Authority)(Company of Public Authority)(Companyof PublicAuthority)Classifi-(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation(a)(b)(c)(d)
1 Powerex Bonneville Power Administration Idaho Power Company OS
2 Powerex PugetSound Energy Idaho Power Company OS
3 Puget Sound Energy Bonneville Power Administration Bonneville Power Administration OS
4 Puget Sound Energy Bonneville Power Administration Pacificorp OS
5 Puget Sound Energy Bonneville Power Administration Grant PUD OS
6 Puget Sound Energy Bonneville Power Administration Puget Sound Energy OS
7 Puget Sound Energy Northwestern Energy Grant PUD OS
8 Puget Sound Energy Northwestern Energy Puget Sound Energy OS
9 Puget Sound Energy Northwestern Energy Bonneville Power Administration OS
10 Puget Sound Energy Idaho Power Company Puget Sound Energy OS
11 Seattle City Light Northwestern Energy Bonneville Power Administration OS
12 Seattle City Light Seattle City Light Seattle City Light LF
13 Sierra Pacific Power Bonneville Power Administration Idaho Power Company OS
14 Sierra Pacific Power Douglas PUD Idaho Power Company OS
15 Sierra Pacific Power Chelan PUD Idaho Power Company OS
16 Sierra Pacific Power Grant PUD Idaho Power Company OS
17 Sierra Pacific Power Portland General Electric Idaho Power Company OS
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.7
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp(2)A Resubmission 04/30/2003 '
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
(Including transactions reffered to as 'wheeling')
OS -for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
nonfirm service regardless of the length of the contract and service from,designated units of less than one year.Describe the nature of
the service in a footnote for each adjustment.
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
5.In column (e),identify the FERC Rate Schedule or Tariff Number,On separate lines,list all FERC rate schedules or contract
designations under which service,as identified in column (d),is provided.
6.Report receipt and delivery locations for all single contract path,"point to point"transmission service.In column (f),report the
designation for the substation,or other appropriate identification for where energy was received as specified in the contract.In column
(g)report the designation for the substation,or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h)the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h)must be in megawatts.Footnote any demand not stated on a megawatts basis and explain,
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineScheduleof(Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)(j)
FERC Elc Trf,1,705 1,705 1
FERC Elc Trf,413 412 2
FERC Elc Trf,15,870 15,87C 3
FERC Elc Trf,3,830 3,83C 4
FERC Elc Trf,2,298 2,29E 5
FERC Elc Trf,106 10€6
FERC Elc Trf,3,168 3,16E 7
FERC Elc Trf,20,735 20,735 8
FERC Elc Trf,4,181 4,181 9
FERC Elc Trf,100 10C 10
FERC Elc Trf,19 1E 11
FERC No.Main Canal/SmmrFalls Bell Substation 233,841 233,841 12
FERC Elc Trf,143,050 143,05C 13
FERC Elc Trf,1,360 1,36C 14
FERC Elc Trf,91,012 91,012 15
FERC Elc Trf,6,525 6,52E 16
FERC Elc Trf,3,851 3,851 17
558 3,735,844 3,735,844
FERC FORM NO.1 (ED.12-90)Page 329.7
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)OX An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)(Including transactions reffered to as 'wheeling')
8.Report in column (i)and (j)the total megawatthours received and delivered.
9.In column (k)through (n),report the revenue amounts as shown on bills or vouchers.In column (k),provide revenues from demand
charges related to the billing demand reported in column (h).In column (l),provide revenues from energy charges related to the
amount of energy transferred.In column (m),provide the total revenues from all other charges on bills or vouchers rendered,including
out of period adjustments.Explain in a footnote all components of the amount shown in column (m).Report in column (n)the total
charge shown on bills rendered to the entity Listed in column (a).If no monetary settlement was made,enter zero (11011)in column
(n).Provide a footnote explaining the nature of the non-monetary settlement,including the amount and type of energy or service
rendered.
10.Provide total amounts in column (i)through (n)as the last Line.Enter "TOTAL"in column (a)as the Last Line.The total amounts
in columns (i)and (j)must be reported as Transmission Received and Delivered on Page 401,Lines 16 and 17,respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)|No.
(k)(I)(m)(n)
3,385 3,385 1
1,082 1,082 2
39,453 39,453 3
8,470 8,470 4
4,801 4,801 5
212 212 6
6,336 6,336 7
42,421 42,421 8
8,469 8,469 9
212 212 10
38 38 11
102,780 102,780 12
295,859 295,859 13
2,784 2,784 14
185,628 185,628 15
13,570 13,570 16
7,911 7,911 17
11,033,648 27,261 135,680 11,196,589
FERC FORM NO.1 (ED.12-90)Page 330.7
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)QX An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TRANSMISSION OF ELECTRICITY FOR OTHERS¯(ÃõcounfX56)
(including transactions referred to as 'wheeling')
1.Report all transmission of electricity,i.e.,wheeling,provided for other electric utilities,cooperatives,municipalities,other public
authorities,qualifying facilities,non-traditional utility suppliers and ultimate customers.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a),(b)and (c).
3.Report in column (a)the company or public authority that paid for the transmission service.Report in column (b)the company or
public authority that the energy was received from and in column (c)the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority.Do not abbreviate or truncate name or use acronyms.Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a),(b)or (c)
4.In column(d)enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
LF -for Long-term firm transmission service."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
LF,provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get
out of the contract.
SF -for short-term firm transmission service.Use this category for all firm services,where the duration of each period of commitment
for service is less than one year.
Line PaymentBy Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 Sierra Pacific Power Seattle City Light Idaho Power Company OS
2 Sierra Pacific Power Tacoma Power Idaho Power Company OS
3 Sierra Pacific Power Northwestern Energy Idaho Power Company OS
4 Sierra Pacific Power Pacificorp Idaho Power Company OS
5 Sierra Pacific Power Puget Sound Energy Idaho Power Company OS
6 City of Spokane City of Spokane Puget Sound Energy LF
7 Spokane Tribe of Indians Bonneville Power Administration Spokane Indian Tribes LF
8 Tacoma City Light Tacoma City Light Tacoma City Light LF
9 US Bureau of Reclamation Bonneville Power Administration East Greenacres LF
10 Xcel Energy Idaho Power Company Bonneville Power Administration OS
11 Xcel Energy Idaho Power Company Portland General Electric OS
12 Xcel Energy Idaho Power Company Northwestern Energy OS
13 Xcel Energy Northwestern Energy Bonneville Power Administration OS
14 Xcel Energy Northwestern Energy Chelan PUD OS
15 Xcel Energy Northwestern Energy Pacificorp OS
16 Xcel Energy Northwestern Energy Portland General Electric OS
17 Xcel Energy Northwestern Energy Puget Sound Energy OS
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.8
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)X An Original (Mo,Da,Yr)Dec.31 2002
(2)A Resubmission 04/30/2003 '
TRANSMISSiOWOF ELECTRICITY FOR OTHERS (Account 456)(Continued)(Includingtransactions reffered to as 'wheeling')
3S -for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
nonfirm service regardless of the length of the contract and service from,designated units of less than one year.Describe the nature of
the service in a footnote for each adjustment.
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
5.In column (e),identify the FERC Rate Schedule or Tariff Number,On separate lines,list all FERC rate schedules or contract
designations under which service,as identified in column (d),is provided.
6.Report receipt and delivery locations for all single contract path,"point to point"transmission service.In column (f),report the
designation for the substation,or other appropriate identification for where energy was received as specified in the contract.In column
(g)report the designation for the substation,or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h)the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h)must be in megawatts.Footnote any demand not stated on a megawatts basis and explain.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineScheduleof(Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)(j)
'FERC Elc Trf,4,160 4,16C 1
FERC Elc Trf,275 276 2
FERC Elc Trf,5,400 5,40C 3
FERC Elc Trf,2,091 2,091 4
ERC Elc Trf,3,225 3,22E 5
FERC No.Sunset Trans.Line Westside Substation 23 146,963 146,962 6
FERC No.Westside Substation Little Falls Substa.2 2,735 2,73E 7
ERC No.Main Canal/SmmrFalls Bell Substation 58 233,841 233,841 8
FERC No.90.2 Bell Substation E Greenacres Irr 3 4,943 4,942 9
FERC Elc Trf,150 15C 10
FERC Elc Trf,394 39A 11
FERC Elc Trf,18 1E 12
IFERC Elc Trf,17,947 17,947 13
FERC Elc Trf,1,250 1,25C 14
FERC Elc Trf,15,049 15,04E 15
FERC Elc Trf,18,550 18,55C 16
FERC Elc Trf,11,087 11,087 17
558 3,735,844 3,735,844
FERC FORM NO.1 (ED.12-90)Page 329.8
Name of Respondent This Report Is:Date of Report Year of Report
Avista Cor (1)X An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)(including transactions reffered to as 'wheeling')
8.Report in column (i)and (j)the total megawatthours received and delivered.
9.In column (k)through (n),report the revenue amounts as shown on bills or vouchers.In column (k),provide revenues from demand
charges related to the billing demand reported in column (h).In column (I),provide revenues from energy charges related to the
amount of energy transferred.In column (m),provide the total revenues from all other charges on bills or vouchers rendered,including
out of period adjustments.Explain in a footnote all components of the amount shown in column (m).Report in column (n)the total
charge shown on bills rendered to the entity Listed in column (a).If no monetary settlement was made,enter zero (11011)in column
(n).Provide a footnote explaining the nature of the non-monetary settlement,including the amount and type of energy or service
rendered.
10.Provide total amounts in column (i)through (n)as the last Line.Enter "TOTAL"in column (a)as the Last Line.The total amounts
in columns (i)and (j)must be reported as Transmission Received and Delivered on Page 401,Lines 16 and 17,respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERJ
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
8,600 8,600 1
588 588 2
11,215 11,215 3
4,328 4,328 4
6,619 6,619 5
127,505 32,088 159,593 6
21,350 21,350 7
102,780 102,780 8
29,235 29,235 9
305 305 10
800 800 11
1,196 1,196 12
54,604 54,604 13
3,221 3,221 14
31,859 31,859 15
39,273 39,273 16
27,348 27,348 17
11,033,648 27,261 135,680 11,196,589
FERC FORM NO.1 (ED.12-90)Page 330.8
Name of Respondent This Report Is.Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp.(2)A Resubmission 04/30/2003 '
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Including transactions referred to as 'wheeling')
1.Report all transmission of electricity,i.e.,wheeling,provided for other electric utilities,cooperatives,municipalities,other public
authorities,qualifying facilities,non-traditional utility suppliers and ultimate customers.
2.Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a),(b)and (c).
3.Report in column (a)the company or public authority that paid for the transmission service.Report in column (b)the company or
public authority that the energy was received from and in column (c)the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority.Do not abbreviate or truncate name or use acronyms.Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a),(b)or (c)
4.In column(d)enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
LF -for Long-term firm transmission service."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
LF,provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get
out of the contract.
SF -for short-term firm transmission service.Use this category for all firm services,where the duration of each period of commitment
for service is less than one year.
Line Payment By Energy Received From Energy Delivered To Statistical
(Companyof Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
1 Xcel Energy Douglas County PUD Northwestern Energy OS
2 Xcel Energy Pacificorp Northwestern Energy OS
3 Xcel Energy Bonneville Power Administration Northwestern Energy OS
4 Xcel Energy Chelan County PUD Northwestern Energy OS
5 Xcel Energy Grant PUD Northwestern Energy OS
6 Vaagen Brothers Lumber Company Vaagen Brothers Lumber Company Idaho Power Company LF
7 Various Various Various OS
8
9
10
12
13
14
15
16
17
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.9
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)OXAn Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)(Including transactions reffered to as 'wheeling')
OS -for other service.Use this category only for those services which cannot be placed in the above-defined categories,such as all
nonfirm service regardless of the length of the contract and service from,designated units of less than one year.Describe the nature of
the service in a footnote for each adjustment.
AD -for out-of-period adjustment.Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years.Provide an explanation in a footnote for each adjustment.
5.In column (e),identify the FERC Rate Schedule or Tariff Number,On separate lines,list all FERC rate schedules or contract
designations under which service,as identified in column (d),is provided.
6.Report receipt and delivery locations for all single contract path,"point to point"transmission service.In column (f),report the
designation for the substation,or other appropriate identification for where energy was received as specified in the contract.In column
(g)report the designation for the substation,or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h)the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h)must be in megawatts.Footnote any demand not stated on a megawatts basis and explain.
FERC Rate Pointof Receipt Point of Delivery Billing TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWattHours No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)(j)
FERC Elc Trf,400 40C 1
FERC Elc Trf,464 464 2
FERC Elc Trf,7,686 7,68E 3
FERC Elc Trf,3,625 3,62E 4
FERC Elc Trf,475 47E 5
FERC No.Colville Substation LoLo-Oxbow 230kv 4 27,261 27,261 6
FERC Elc Trf,7
8
9
10
11
12
13
14
15
16
17
558 3,735,844 3,735,844
FERC FORM NO.1 (ED.12-90)Page 329.9
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)(Including transactions reffered to as 'wheeling')
8.Report in column (i)and (j)the total megawatthours received and delivered.
9.In column (k)through (n),report the revenue amounts as shown on bills or vouchers.In column (k),provide revenues from demand
Icharges related to the billing demand reported in column (h).In column (I),provide revenues from energy charges related to the
amount of energy transferred.In column (m),provide the total revenues from all other charges on bills or vouchers rendered,including
out of period adjustments.Explain in a footnote all components of the amount shown in column (m).Report in column (n)the total
charge shown on bills rendered to the entity Listed in column (a).If no monetary settlement was made,enter zero (11011)in column
(n).Provide a footnote explaining the nature of the non-monetary settlement,including the amount and type of energy or service
rendered.
10.Provide total amounts in column (i)through (n)as the last Line.Enter "TOTAL"in column (a)as the Last Line.The total amounts
in columns (i)and (j)must be reported as Transmission Received and Delivered on Page 401,Lines 16 and 17,respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHER:1
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
927 927 1
1,055 1,055 2
17,646 17,646 3
8,444 8,444 4
1,219 1,219 5
67,488 27,261 22,981 117,730 6
7
8
9
12
13
14
15
16
17
11,033,648 27,261 135,680 11,196,589
FERC FORM NO.1 (ED.12-90)Page 330.9
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TRANSivISSIONOF ELECTRICITY BY OTHEHS (Account 565)
(Includingtransactions referred to as "wheeling")
1.Report all transmission,i.e.,wheeling of electricity provided to respondent by other electric utilities,cooperatives,municipalities,or
other public authorities during the year.
2.In column (a)report each company or public authority that provide transmission service.Provide the full name of the company;
abbreviate if necessary,but do not truncate name or use acronyms.Explain in a footnote any ownership interest in or affiliation with the
transmission service provider.
3.Provide in column (a)subheadings and classify transmission service purchased form other utilities as:"Delivered Power to
Wheeler"or "Received Power from Wheeler."
4.Report in columns (b)and (c)the total Megawatthours received and delivered by the provider of the transmission service.
5.In columns (d)through (g),report e×penses as shown on bills or vouchers rendered to the respondent.In column (d),provide
demand charges.In column (e),provide energy charges related to the amount of energy transferred.In column (f),provide the total of
all other charges on bills or vouchers rendered to the respondent,including any out of period adjustments.Explain in a footnote all
components of the amount shown in column (f).Report in column (9)the total charge shown on bills rendered to the respondent.If no
monetary settlement was made,enter zero ("0")column (g).Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6.Enter "TOTAL"in column (a)as the last Line.Provide a total amount in columns (b)through (g)as the last Line.Energy provided by
the respondent for the wheeler's transmission tosses should be reported on the Electric Energy Account,Page 401.If the respondent
received power from the wheeler,energy provided to account for Losses should be reported on Line 19.Transmission By Others
Losses,on Page 401.Otherwise,Losses should be reported on line 27,Total Energy Losses,Page 401.
7.Footnote entries and provide explanations following all required data.
Line Name of Company or Public TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
No.Authority (Footnote Affiliations)Magawatt-Magawatt-Demand Energy Uther Total Cost of
hours hours Charges Charges Charges Tran ssionReceivedDelivered($)($)($)
(a)(b)(c)(d)(e)(f)
1 Bonneville Power Admin 2,928 2,928
2 Bonneville Power Admin 1,174,032 1,174,032
3 Bonneville Power Admin 4,454,912 4,454,912
4 Bonneville Power Admin 676,629 676,629
5 Bonneville Power Admin 12,903 12,903
6 Bonneville Power Admin -3,819 -3,819
7 Bonneville Power Admin 1,100,126 1,100,126
8 Bonneville Power Admin 48 192 192
9 Bonneville Power Admin 86 344 344
10 Bonneville Power Admin 125 447 -594 -147
11 Bonneville Power Admin 5,836 20,892 2,043 22,935
12 Benton County PUD 4,263 6,704 6,704
13 Benton County PUD 2,295 7,664 7,664
14 Grant County PUD 29,410 57,129 57,129
15 Grant County PUD 1,600 3,200 3,200
16 Grays Harbor PUD 400 800 800
TOTAL 98,705 21,77E 8 068,229 377,319 -4,321 8,441,227
FERC FORM NO.1 (ED.12-90)Page 332
Name of Respondent This Report Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)2002AvistaCorp.(2)A Resubmission 04/30/2003 Dec.31,
TRANSNISSION OF ELECTRICITY BY OTHEHS (Account 565)(Including transactions referred to as "wheeling")
1.Report all transmission,i.e.,wheeling of electricity provided to respondent by other electric utilities,cooperatives,municipalities,or
other public authorities during the year.
|2.In column (a)report each company or public authority that provide transmission service.Provide the full name of the company;
abbreviate if necessary,but do not truncate name or use acronyms.Explain in a footnote any ownership interest in or affiliation with the
transmission service provider.
3.Provide in column (a)subheadings and classify transmission service purchased form other utilities as:"Delivered Power to
Wheeler"or "Received Power from Wheeler."
4.Report in columns (b)and (c)the total Megawatthours received and delivered by the provider of the transmission service.
5.In columns (d)through (g),report expenses as shown on bills or vouchers rendered to the respondent.In column (d),provide
demand charges.In column (e),provide energy charges related to the amount of energy transferred.In column (f),provide the total of
all other charges on bills or vouchers rendered to the respondent,including any out of period adjustments.Explain in a footnote all
components of the amount shown in column (f).Report in column (9)the total charge shown on bills rendered to the respondent.If no
monetary settlement was made,enter zero ("0")column (g).Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6.Enter "TOTAL"in column (a)as the last Line.Provide a total amount in columns (b)through (g)as the last Line.Energy provided by
the respondent for the wheeler's transmission tosses should be reported on the Electric Energy Account,Page 401.If the respondent
received power from the wheeler,energy provided to account for Losses should be reported on Line 19.Transmission By Others
Losses,on Page 401.Otherwise,Losses should be reported on line 27,Total Energy Losses,Page 401.
7.Footnote entries and provide explanations following all required data.
Line Name of Company or Public TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
No.Authority (Footnote Affiliations)Magawatt.Magawatt-Demand Energy Uther |Total Cost ofhourshoursCharaesChargesChargesITranssionReceivedDelivered($¶($)($)(a)(b)(c)(d)(e)(f)
1 Kootenai Electric Coop 32,112 32,112
2 NorthWestern Energy 33,895 30,156 163,207 -1,323 192,040
3 Portland General Elec 2,343 5,472 5,472
4 Portland General Elec 584,431 584,431
I5PugetSoundEnergy9,805 58,117 58,117
6 Seattle City Light 3,632 7,512 7,512
7 Snohomish PUD -628 -628
8 Sierra Pacific 8,878 13,632 13,632
9 Sierra Pacific 11,693 19,151 19,151
10 Tacoma 6,132 12,786 12,786
11 Tacoma 40 70 70
12 TOTAL 98,705 21,776 8,068,229 377,319 -4,321 8,441,227
13
14
15
16
TOTAL 98,705 21,776 8,068,229 377,319 -4,321 8,441,227
FERC FORM NO.1 (ED.12-90)Page 332.1
Name of Respondent This ort is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31 2002
(2)A Resubmission 04/30/2003 '
MISCELLANEOUS GENERAL EXPENSES (Account 930.2)(ELECTRIC)
Line Description Amount
No.(a)(b)
1 Industry Association Dues 242,436
2 Nuclear Power Research Expenses
3 Other Experimentaland General Research Expenses
4 Pub &Dist Info to Stkhldrs...expn servicing outstanding Securities 16,008
5 Oth Expn >=5,000 show purpose,recipient,amount.Group if <$5,000 746,884
6 Directors Fees and Expenses 238,923
7 .Miscellaneous General Expenses (930.20)515,561
8 Community Relations (930.22)577,686
9 Educational -Informational (930.23)189,156
10 Other Miscellaneous General Expenses (930.29)22,526
11 Other Miscellaneous Labor(930.27 &930.28)97,575
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 2,646,755
FERC FORM NO.1 (ED.12-94)Page 335
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403,404,405)
(Except amortization of aquisition adjustments)
1.Report in Section A for the year the amounts for:(a)Depreciation Expense (Account 403);(b)Amortization of Limited-Term Electric
Plant (Account 404);and (c)Amortization of Other Electric Plant (Account 405).
2.Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405).State the basis used
to compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3.Report all available information called for in Section C every fifth year beginning with report year 1971,reporting annually only
changes to columns (c)through (g)from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed,list numerically in column (a)each plant subaccount,account or functional classification,as appropriate,to which a rate is applied.Identify at the bottom of Section C the type of plant
included in any sub-account used.
In column (b)report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and
showing composite total.Indicate at the bottom of section C the manner in which column balances are obtained.If average balances,
state the method of averaging used.
For columns (c),(d),and (e)report available information for each plant subaccount,account or functional classification Listed in column
(a).If plant mortality studies are prepared to assist in estimating average service Lives,show in column (f)the type mortality curve
selected as most appropriate for the account and in column (g),if available,the weighted average remaining life of surviving plant.If
composite depreciation accounting is used,report available information called for in columns (b)through (g)on this basis.
4.If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates,state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A.Summary of Depreciationand Amortization Charges
Line Deoreciation 'Amortization of Amortization ofFunctionalClassificationExpenseLimitedTermElec-Other Electric TotalNo(Account 403)tric Plant (Acc 404)Plant (Acc 405)(a)(b)(c)(d)(e)
1 Intangible Plant 5,016,406 5,016,406
2 Steam Production Plant 11,318,227 11,318,227
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 5,287,107 5,287,107
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 1,564,686 2,480,620 4,045,306
7 Transmission Plant 7,076,915 7,076,915
8 Distribution Plant 15,097,039 15,097,039
9 General Plant 2,268,704 2,268,704
10 Common Plant-Electric 3,568,202 3,568,202
11 TOTAL 46,180,880 5,016,406 2,480,620 53,677,906
B.Basis for Amortiza ion Charges
1.Amortization of Limited -Term Electric Plant -Account 404 includes:
(a)$350 amortization of limited term electric plant is based upon the operation portion of the Noxon Rapids Licensed Project #2075 which ends
5/1/2005.
(b)$327,364 amortization of Noxon and Cabinet Rellecense over 45 years.
(c)$12,189 amortization of contribution for construction of Sandcreek Substation.
(d)$802 amortization of Misc.Intangible Electric Plant pursuant to FERC order dated 6/16/1986,Docket #EC86-17-000 relating to Company'scontributiontotheconstructionoftheSandDunes-Taunton 115kv Transmission line in the Grant County,WA in 1986.
(e)$4,072,954 amortization of software.
(f)$602,747 allocated poriton of Amortization Leasehold Improvements from common plant.
2.Account 405 -Reflects amortization of the investment in settlement exchange power for WNP #3.
FERC FORM NO.1 (ED.12-88)Page 336
Nameof Respondent ThisRepodis:DateofRepon YearofRepon
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C.Factors Used in Estimating Depreciation Charges
Line 'Depreciable Estimated Net Applied Mortality Average
No Account No.Plant Base Avg.Service Salvage Depr.rates Curve Remaining
(In Thousands)Life (Percent)(Percent)Type Life
(a)(b)(c)(d)(e)(T)(g)
12 STEAM PLAbn
13 ColstripNo.3
14 311 50,625
15 312 72,604
16 314 16,750
17 315 8,070
18 316 8,610
19 Subtotal 156,659
20
21 ColstripNo.4
22 311 48,827
23 312 zWl,007
24 314 14,427
25 315 5,411
26 316 4,003
27 Subtotal 116,675
28
29 Keule Falls
30 310 148
31 311 23,951
32 312 39,537
33 314 13,378
34 315 10,285
35 316 2,393
36 Subtotal 89,692
37
38 HYDRO PLAJAT
39 Cabinet Gorge
40 330 7,195
41 331 9,287
42 332 18,873
43 333 28,031
44 334 5,110
45 335 2,382
46 336 1,099
47 Subtotal 71,977
48
49 Noxon Rapids
50 330 29,974
FERC FORM NO.1 (ED.12-95)Page 337
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)g An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C.Factors Used in Estimating Depreciation Charges
Line Depreciable Estimated Net Applied Mortality Average
No Account No.Plant Base Avg.Service Salvage Depr.rates Curve Remaining(In Thousands)Life (Percent)(Percent)Type Life(a)(b)(c)(d)(e)(1)(g)
12 331 11,073
13 332 30,617
14 333 30,938
15 334 9,621
16 335 2,602
17 336 217
'18 Subtotal 115,042
19
20 Post Falls
21 330 2,732
22 331 611
23 332 4,055
24 333 2,215
25 334 846
26 335 214
27 Subtotal 10,673
28
29 Long Lake
30 330 418
31 331 1,611
32 332 16,506
33 333 8,804
34 334 2,617
35335 355
36 Subtotal 30,311
37
38 Little Falls
39 330 4,217
40331 904
41 332 5,007
42 333 3,966
43 334 1,623
44335 137
45 Subtotal 15,854
46
47 Upper Falls
48 330 65
49331 474
50 332 2,104
FERC FORM NO.1 (ED.12-95)Page 337.1
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C.Factors Used in Estimating Depreciation Charges
Line Depreciable Estimated |Net Applied Mortality Average
No.Account No.Plant Base Avg.Service Salvage Depr.rates Curve Remaining
(In Thousands)Life (Percent)(Percent)Type Life
(a)(b)(c)(d)(e)(t)(g)
12 333 1,090
13 334 777
14 335 107
15 Subtotal 4,617
16
17 Nine Mile
18 330 11
19 331 3,922
20 332 11,841
21 333 9,458
22 334 2,589
23335 282
24336 625
25 Subtotal 28,728
26
27 Centralia-Skookumchuck
28331 51
29 332 3
30333 434
31 334 91
32 Subtotal 579
33
34 Monroe Street
35 331 8,147
36 332 8,045
37 333 11,018
38 334 1,606
39 335 22
40 336 50
41 Subtotal 28,888
42
43 OTHER PRODUCTION
44 Northeast Turbine
45 341 257
46 342 1,145
47 343 8,228
48 344 2,595
49 345 334
50 346 241
FERC FORM NO.1 (ED.12-95)Page 337.2
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C.Factors Used in Estimating Depreciation Charges
Line Depreciable Estimated Net I Applied Mortality Average
No.Account No.Plant Base Avg.Service Salvage Depr.rates Curve Remaining(In Thousands)Life (Percent)(Percent)T e Life(a)(b)(c)(d)(e)(g)
12 Subtotal 12,800
13
14 Other Generation
15 340 1
16344 472
17345 26
18 Subtotal 499
19
20 Rathdrum Leasehold imp
21 343 1,868
22344 603
23 345 194
24 Subtotal 2,665
25
26 Kettle Falls Bi-Fuel
27 342 99
28 Subtotal 99
29
30 Kettle Falls CT
31 341
32 342 89
33 343 9,071
34 344 4
35 345 5
36 346
37 Subtotal 9,169
38
39 Boulder Park
40341 704
41 342 116
42 343
43 344 29,657
44345 248
45 346 3
46 Subtotal 30,728
47
48 TRANSMISSION PLANT
49 350 9,474
50 352 8,816
FERC FORM NO.1 (ED.12-95)Page 337.3
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C.Factors Used in Estimating Depreciation Charges
Line i Deprectable I t-stimated |Net Applied 'Mortality 'Average
No Account No.Plant Base Avg.Service Salvage Depr.rates Curve Remaining
(In Thousands)Life (Percent)(Percent)T e Life
(a)(b)(c)(d)(e)(g)
12 353 112,161
13 354 17,058
14 355 74,276
15 356 63,884
16 357 561
17 358 1,318
18 359 1,824
19 Subtotal 289,372
20
21 DISTRIBUTION PLANT
22 361 9,782
23 362 66,460
24 364 146,935
25 365 100,365
26 366 45,338
27 367 76,385
28 368 116,471
29 369 80,325
30 370 23,549
31 373 10,117
32 373.4 8,811
33 Subtotal 684,538
34
35 GENERAL PLANT
36 390.1 1,637
37 391.1 58
38 393 99
39 394 2,669
40 395 2,849
41 397 17,157
42 398 2
43 Subtotal 24,471
44
45 MISC POWER
46 392 1,065
47 396 1,432
48 Subtotal 2,497
49
50 TOTAL COMPANY 1,726,533
FERC FORM NO.1 (ED.12-95)Page 337.4
This Page Intentionally Left Blank
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
REGULATORY COMMISSION EXPENSES
1.Report particulars (details)of regulatory commission expenses incurred during the current year (or incurred in previous years,if
being amortized)relating to format cases before a regulatory body,or cases in which such a body was a party.
2.Report in columns (b)and (c),only the current year's expenses that are not deferred and the current year's amortization of amounts
defe red in previous years.
Line Description Assessed by 'Expenses Total .Deterred
No.(Furnish name of regulatory commission or body the Regulatory of Expense for in Account
docket or case number and a description of the case)Commission Utility Curbrent ear Beginn rig3o Year
(a)(b)(c)(d)(e)
1 FEDERAL ENERGY REGULATORY COMMISSION
2 FERC Cases.Doc #'s:CPO2-39,40,41,42,CP93-618,
3 GTO2-37,GTO2-503,RPOO-412,RPOO-414,RPO1-94,
4 RPO2-164,RPO2-169,RPO2-191,RPO2-272,RPO2-323,
5 RPO2-331,RPO2-337,RPO2-344,RPO2-362,RPO2-391,
6 RPO2-410,RPO2-451,RPO2-452,RPO2-453,RPO2-455,
7 RPO2-471,RPO2-503,RPO2-552,RPO2-553,RPO2-564,
8 RPO2-69,RPO3-18,RPO3-41,RPO3-68&70 2,136,368 100,232 2,236,600
9
10 WASH.UTILITIES &TRANSPORTATION COMM.
11 Electric -Docket #'s:
12 UE-011595,UE-020344,UE-020352,UE-020471
13 UE-020635,UE-020699,UE-020765,UE-021052
14 UE-021124,UE-021123,UE-021455,UE-021521
15 UE-021699,UE-0021731 477,420 673,142 1,150,562
16
17 Gas -Docket #'s UG-020219,UG-020218,UG-020345
18 UG-020472,UG-020575,UG-020700,UG-021043,
19 UG-021258,UG-021456,UG-021584,UG-021639 301,836 162,836 464,672
20
21 IDAHO PUBLIC UTILITIES COMMISSION
22 Electric -Docket #'s:AVU-E-02-2,AVU-E-02-3
23 AVU-E-02-4,AVU-E-02-5,AVU-E-02-6
24 AVU-E-02-7,AVU-E-02-8
25 Advise #s:02-01-E,02-03-E,02-04-E
26 General Docket #s:GNR-E-02-1,GNR-E-02-2 420,728 235,190 655,918
27
28 Gas -Docket #'s:AVU-G-01-3,AVU-G-02-1
29 AVU-G-02-2
30 Advice #s:02-01-G,02-02-G,02-03-G,02-04-G
31 General Docket #:GNR-U-02-1 149,438 88,538 237,976
32
33 OREGON PUBLIC UTILITIESCOMMISSION
34 Docket #'s:UM-903,UM-1056,AR-357/427,
35 UG-148,UF4153/4079
36 Advice #s:01-8-G,02-1-G,02-2-G,02-9-G,
37 02-10-G,02-11-G,02-12-G,02-13-G 217,216 191,484 408,700
38
39 CALIFORNIA PUBLIC UTILITIES COMMISSION
40 Decisions:01-05-033,01-07-026,01-08-065,
41 02-10-040,02-21-011
42 Resolutions:E-3524,G-3303,G-3329
43 Advice #s:U907GIC44G-C50G
44 Rulemaking #s:98-7-026,01-05-047,01-08-027,
45 02-10-001 16,602 85,969 102,571
46 TOTAL 3,719,608 1,537,391 5,256,999
FERC FORM NO.1 (ED.12-96)Page 350
\Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)g An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
REGJLATORY COMMISSION EXPENSES (Continued)
3.Show in column (k)any expenses incurred in prior years which are being amortized.List in column (a)the period of amortization.
4.List in column (f),(g),and (h)expenses incurred during year which were charged currently to income,plant,or other accounts.
5.Minor items (less than $25,000)may be grouped.
EXPENSES INCURRED DURING YEAR AMORTlZED DURING Y TAR
CURRENTLY CHARGED TO Deferred to Contra Amount Deferred in LineDepartment|AccNount Amount Account 182.3 Account A cnodont 8a2.3 No.
(f)(g)(h)(i)(j)(k)(l)
1
2
3
4
5
6
7
Electric 0928 2,236,600 8
9
10
12
13
14
Electric 0928 1,150,562 15
17
18
Gas 1928 464,672
20
21
22
23
24
25
Electric 0928 655,918 26
27
28
29
30
Gas 1928 237,976 31
32
33
34
35
36
Gas 2928 408,700 37
38
39
40
41
42
43
44
Gas 2928 102,571 45
5,256,999 46
ERC FORM NO.1 (E 3.12-96)Page 351
Name of Respondent This Report is:Date of Report Year of Report
(1)An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp(2)A Resubmission 04/30/2003
DISTRIBUTION OF SALARIES AND NAGES
Report below the distribution of total salaries and wages for the year.Segregate amounts originally charged to clearing accounts to
Utility Departments,Construction,Plant Removals,and Other Accounts,and enter such amounts in the appropriate lines and columns
provided.In determining this segregation of salaries and wages originally charged to clearing accounts,a method of approximation
giving substantially correct results may be used.
Line Classification D re t Pa roll Pay cah rged for Total
No.|Cleanng Accounts
(a)(b)(c)(d)
1 Electric
2 Operation
3 Production 7,448,601
4 Transmission 1,746,532
5 Distribution 4,899,800
6 Customer Accounts 4,454,808
7 Customer Service and Informational 43,424
8 Sales 516,401
9 Administrative and General 9,737,935
10 TOTAL Operation (Enter Total of lines 3 thru 9)28,847,501
11 Maintenance
12 Production 2,753,739
13 Transmission 738,689
14 Distribution 3,938,933
15 Administrative and General 690,140
16 TOTAL Maint.(Total of lines 12 thru 15)8,121,501
17 Total Operation and Maintenance
18 Production (Enter Total of lines 3 and 12)10,202,340
19 Transmission (Enter Total of lines 4 and 13)2,485,221
20 Distribution (Enter Total of lines 5 and 14)8,838,733
21 Customer Accounts (Transcribe from line 6)4,454,808
22 Customer Service and Informational (Transcribe from line 7)43,424
23 Sales (Transcribe from line 8)516,401
24 Administrative and General (Enter Total of lines 9 and 15)10,428,075
TOTAL Oper.and Maint.(Total of lines 18 thru 24)36,969,002
27 Operation
28 Production-Manufactured Gas
29 Production-Nat.Gas (Including Expl.and Dev.)
30 Other Gas Supply 335,330
31 Storage,LNG Terminaling and Processing
32 Transmission
33 Distribution 5,074,534
34 Customer Accounts 3,809,779
35 Customer Service and Informational 111,842
36 Sales 310,451
37 Administrative and General 3,777,353
38 TOTAL Operation (Enter Total of lines 28 thru 37)13,419,289
39 Maintenance
40 Production-Manufactured Gas
41 Production-Natural Gas
42 Other Gas Supply
43 Storage,LNG Terminaling and Processing
44 Transmission
45 Distribution 1,597,762
46 Administrative and General 183,084
47 TOTAL Maint.(Enter Total of lines 40 thru 46)1,780,846
FERC FORM NO.1 (ED.12-88)Page 354
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original (Mo,Da,Yr)Dec.31 2002
I
Avista Corp.(2)A Resubmission 04/30/2003 '
DISTHIBUTION OF SALARIES AND WAGES (Continued)
Line Classification D re t Pa roll Pay cah rged for Total
No.Cleanng Accounts(a)(b)(c)(d)
48 Total Operation and Maintenance
49 Production-Manufactured Gas (Enter Total of lines 28 and 40)
50 Production-Natural Gas (Including Expl.and Dev.)(Total lines 29,
51 Other Gas Supply (Enter Total of lines 30 and 42)335,330
52 Storage,LNG Terminaling and Processing (Total of lines 31 thru
53 Transmission (Lines 32 and 44)
54 Distribution (Lines 33 and 45)6,672,296
55 Customer Accounts (Line 34)3,809,779
56 Customer Service and Informational (Line 35)111,842
57 Sales (Line 36)310,451
58 Administrative and General (Lines 37 and 46)3,960,437
59 TOTAL Operation and Maint.(Total of lines 49 thru 58)15,200,135 445,043 15,645,178
60 Other Utility Departments
61 Operation and Maintenance
62 TOTAL All Utility Dept.(Total of lines 25,59,and 61)52,169,137 2,022,328 54,191,465
63 Utility Plant
64 Construction (By Utility Departments)
65 Electric Plant 15,165,287 1,420,734 16,586,021
66 Gas Plant 4,961,097 271,180 5,232,277
67 Other (provide details in footnote):
68 TOTAL Construction (Total of lines 65 thru 67)20,126,384 1,691,914 21,818,298
69 Plant Removal (By Utility Departments)
70 Electric Plant 603,682 -1,330 602,352
71 Gas Plant 53,810 725 54,535
72 Other (provide details in footnote):
73 I TOTAL Plant Removal (Total of lines 70 thru 72)657,492 -605 656,887
74 Other Accounts (Specify,provide details in footnote):
75 Stores Expense (163)41 41
76 Prepayments (165)
77 Preliminary Survey and Investigation (183)32,503 1,830 34,333
78 Small Tools Expense (184)54,604 6,477 61,081
79 Miscellaneous Deferred Debits (186)34,601,080 26,646 34,627,726
80 Capital Stock Expense (214)
81 Merchandising Expenses (416)369,904 1,579 371,483
82 Non-operating Expenses (417)780,418 21,390 801,808
83 Expenditures of Certain Civic,Political and Related Activiti 257,273 920 258,193
84 Purchase and Stores Expense (980)1,182,363 -1,165,372 16,991
85 Transportation Expense (981)1,339,182 -1,320,122 19,060
86 Cafeteria Expense-Labor (984)
87 Spokane Central Operating Facility Expense (985)761,378 -757,222 4,156
88 Clark Fork Relicensing (987)536,108 -529,804 6,304
89
90
91
92
93
94
95 TOTAL Other Accounts 39,914,813 -3,713,637 36,201,176
96 TOTAL SALARIES AND WAGES 112,867,826 112,867,826
FERC FORM NO.1 (ED.12-88)Page 355
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)An Original (Mo,Da,Yr)
(2)A Resubmission 04/30/2003 Dec.31,2002
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 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 amortizationfor 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 order of the Commission or other
authorization.
Acct.No.
303 Intangible $8,951,629
389 Land and Land Rights 1,556,606
390 structures and Improvements 23,313,071
391 Office Furniture and Equipment 21,061,906
392 Transportation Equipment 1,820,853
393 Stores Equipment 826,344
394 Tools,Shop &Garage Equipment 643,177
395 Laboratory Equipment 728,737
396 Power Operated Equipment 1,444,046
397 Communications Equipment 12,842,165
398 Miscellaneous Equipment 290,551
Total Common Plant 73,479,085
Const.Work In Progress 767,323
Total Utility Plant 74,246,408
Acc.Prov.for Dep.&Amort.31,676,743
Net Utility Plant 42,569,664
FERCFORMNO.1(ED.12-87)Page 356
!Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
ELECTRIC ENERGY ACCOUFT
Report below the information called for concerning the disposition of electric energy generated,purchased,exchanged and wheeled during the year.
Line Item MegaWatt Hours Line Item MegaWatt Hours
No.No.(a)(b)(a)(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use):22 Sales to UltimateConsumers (Including 7,598,029
3 Steam 1,658,53C InterdepartmentalSales)
4 Nuclear 23 RequirementsSales for Resale (See
5 Hydro-Conventional 4,009,637 instruction 4,page 311.)
6 Hydro-Pumped Storage 24 Non-RequirementsSales for Resale (See 2,215,545
7 Other 55,752 instruction 4,page 311.)
8 Less Energy for Pumping 25 Energy Furnished Without Charge
9 Net Generation (Enter Total of lines 3 5,723,91;26 Energy Used by the Company (Electric 7,486
through 8)Dept Only,Excluding Station Use)
10 Purchases 4,664,491 27 Total Energy Losses 592,463
11 Power Exchanges:J 28 TOTAL (Enter Total of Lines 22 Through 10,413,523
12 Received 632,543 27)(MUST EQUAL LINE 20)
13 Delivered 607,43C
14 Net Exchanges (Line 12 minus line 13)25,113
15 Transmission For Other (Wheeling)
16 Received 3,735,844
17 Delivered 3,735,844
18 Net Transmission for Other (Line 16 minus
iline 17)
,19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9,10,14,18 10,413,523
and 19)
FERC FORM NO.1 (ED.12-90)Page 401a
'Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
MONTHLY PEAKS AND OUTPUT
1.If the respondent has two or more power systems which are not physically integrated,furnish the required information for each non-integrated system.
2.Report in column (b)the system's energy output for each month such that the total on Line 41 matches the total on Line 20.
3.Report in column (c)a monthly breakdown of the Non-Requirements Sales For Resale reported on Line 24.include in the monthly amounts any
energy losses associated with the sales so that the total on Line 41 exceeds the amount on Line 24 by the amount of losses incurred (or estimated)in
making the Non-Requirements Sales for Resale.
4.Report in column (d)the system's monthly maximum megawatt Load (60-minute integration)associated with the net energy for the system defined as
the difference between columns (b)and (c)
5.Report in columns (e)and (f)the specified information for each monthly peak load reported in column (d).
NAME OF SYSTEM:Avista Corporation
Line Monthly Non-Requirments IV ONTHLY PEAKSalesforResale&No.Month Total Monthly Energy Associated Losses Megawatts (See Instr.4)Day of Month Hour
(a)(b)(c)(d)(e)(f)
29 January '876,384 105,228 1,333 29 1800
30 February 785,919 101,899 1,326 25 800
31 March 886,676 157,370 1,340 6 1900
32 April 825,744 199,125 1,123 24 800
33 May 909,080 278,072 1,128 7 900
34 June 1,037,755 394,963 1,313 26 1700
35 July 988,103 279,752 1,389 12 1400
36 August 884,350 216,391 1,273 14 1700
37 September 734,766 136,213 1,138 12 1700
38 October 768,698 96,513 1,298 29 1800
39 November 820,297 118,933 1,264 1 800
40 December 895,751 131,086 1,346 9 1800
41 TOTAL 10,413,523 2,215,545
FERC FORM NO.1 (ED.12-90)Page 401b
This Page Intentionally Left Blank
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original (Mo,Da,Yr)Avista Corp.(2)A Resubmission 04/30/2003 Dec.31,2002
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Report data for plant in Service only.2.Large plants are steam plants with installed capacity (name plate rating)of 25,000 Kw or more.Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more,and nuclear plants.3.Indicate by a footnote any plant leased or operated
as a joint facility.4.If net peak demand for 60 minutes is not available,give data which is available,specifying period.5.If any employees attend
more than one plant,report on line 11 the approximate average number of employees assignable to each plant.6.If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7.Quantities of fuel burned (Line 37)and average cost
per unit of fuel burned (Line 40)must be consistent with charges to expense accounts 501 and 547 (Line 41)as show on Line 19.8.If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
No.Name:Kettle Falls Bi-Fuel Name:SpokaneN.E.
(a)(b)(c)
1 Kind of Plant (Internal Comb,Gas Turb,Nuclear internal Comb Gas Turbine
2 Type of Constr (Conventional,Outdoor,Boiler,etc)Conventional Not Applicable
3 Year Originally Constructed 2001 1978
4 Year Last Unit was Installed 2001 1978
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)10.80 61.80
6 Net Peak Demandon Plant -MW (60 minutes)9 24
7 Plant Hours Connected to Load 36 25
8 Net Continuous Plant Capability (Megawatts)O O
9 When Not Limited by Condenser Water 0 0
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 0 1
12 Net Generation,Exclusive of Plant Use -KWh 293000 198000
13 Cost of Plant:Land and Land Rights 0 129664
14 Structures and Improvements 0 256673
15 Equipment Costs 98802 13984321
16 Total Cost 98802 14370658
17 Cost per KW of Installed Capacity (line 5)9.1483 232.5349
18 Production Expenses:Oper,Supv,&Engr 16956 0
19 Fuel 19501 113616
20 Coolants and Water (Nuclear Plants Only)0 0
21 Steam E×penses O O
22 Steam From Other Sources O O
23 Steam Transferred (Cr)0 0
24 Electric Expenses -224179 49772
25 Misc Steam (or Nuclear)Power Expenses O O
26 Rents 4594959 0
27 Allowances O O
28 Maintenance Supervision and Engineering 35 54060
29 Maintenance of Structures 0 35079
30 Maintenance of Boiler (or reactor)Plant 0 0
31 Maintenance of Electric Plant -283 124419
32 Maintenance of Misc Steam (or Nuclear)Plant 0 0
33 Total Production Expenses 4406989 376946
34 Expenses per Net KWh 15.0409 1.9038
35 Fuel:Kind (Coal,Gas,Oil,or Nuclear)Oil Gas Oil Gas
36 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)Bbl Mcf Bbl Mcf
37 Quantity (units)of Fuel Burned 263 1501 0 0 4887 0
38 Avg Heat Cont -Fuel Burned (btulindicate if nuclear)140000 1019000 0 0 1019000 0
39 Avg Cost of Fuellunit,as Delvd f.o.b.during year 42.340 5.580 0.000 0.000 23.250 0.000
40 Average Cost of Fuel per Unit Burned 42.340 5.580 0.000 0.000 23.250 0.000
41 Average Cost of Fuel Burned per Million BTU 7.200 5.480 0.000 0.000 22.810 0.000
42 Average Cost of Fuel Burned per KWh Net Gen 0.038 0.029 0.000 0.000 0.574 0.000
43 Average BTU per KWh Net Generation 10491.000 10491.000 0.000 0.000 25151.000 0.000
FERC FORM NO.1 (ED.12-95)Page 402
Name of Respondent This Report Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)Avista Corp (2)A Resubmission 04/30/2003 Dec.31,2002
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9.Items under Cost of Plantare based on U.S.of A.Accounts.Production expenses do not include Purchased Power,System Control and Load
Dispatching,and Other Expenses Classified as Other Power Supply Expenses.10.For IC and GT plants,report Operating Expenses,Account Nos.
547 and 549 on Line 24 "Electric Expenses,"and Maintenance Account Nos.553 and 554 on Line 31,"Maintenanceof Electric Plant."Indicate plants
designed for peak load service.Designate automatically operated plants.11.For a plant equipped with combinations of fossil fuel steam,nuclear
steam,hydro,internal combustion or gas-turbine equipment,report each as a separate plant.However,if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit,include the gas-turbine with the steam plant.12.If a nuclear power generating plant,briefly explain by
footnote (a)accounting method for cost of power generated including any excess costs attributed to research and development;(b)types of cost units
used for the various components of fuel cost;and (c)any other informative data concerning plant type fuel used,fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant Line
Name:Kettle Falls Name:Colstrip Name:Rathdrum No.
(d)(e)(f)
Steam Steam Gas Turbine 1
Conventional Conventional Not Applicable i
1983 1984 1995 3
1983 1985 1995 4
46.00 233.40 166.50 5
54 225 170 6
6066 0 310 7
50 0 0 8
I 47 0 0 9
47 0 0 10
29 0 2 11
261425000 1397105000 39424000 12
941300 1307499 484415 13
23978019 99570102 325 14
65579036 175609823 4451875 15
90498355 276487424 4936615 16
1967.3555 1184.6076 29.6493 17
101200 113175 199 18
6254516 9276929 2751987 19
O 0 0 20
405462 410316 0 21
0 2878 0 22
0 0 0 23
547261 43146 353146 24
388257 2581593 0 25
10419 51623 4804625 26
0 0 0 27
44980 170192 32265 28
24197 304675 278 29
1025698 2127593 0 30
453814 585659 278559 31
143897 275240 0 32
9399701 15943019 8221059 33
0.0360 0.0114 0.2085 34
Wood Gas Coal Oil Gas 35
Tons Mcf Tons Bbl Mcf 36
426973 7078 0 874216 2403 0 476211 0 0 37
8500000 1019000 0 17011833 140000 0 1019000 0 0 38
14.540 6.810 0.000 10.504 39.047 0.000 5.780 0.000 0.000 39
14.540 6.810 0.000 10.504 39.047 0.000 5.780 0.000 0.000 40
1.710 6.680 0.000 0.617 6.640 0.000 5.670 0.000 0.000 41
0.024 0.078 0.000 0.007 0.000 0.000 0.070 0.000 0.000 42
13910.000 13910.000 0.000 10661.000 10661.000 0.000 12309.000 0.000 0.000 43
FERC FORM NO.1 (ED.12-88)Page 403
Name of Respondent This Report Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)2002AvistaCorp(2)A Resubmission 04/30/2003 Dec.31,
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1.Report data for plant in Service only.2.Large plants are steam plants with installed capacity (name plate rating)of 25,000 Kw or more.Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more,and nuclear plants.3.Indicate by a footnote any plant leased or operated
as a joint facility.4.If net peak demand for 60 minutes is not available,give data which is available,specifying period.5.If any employees attend
more than one plant,report on line 11 the approximate average number of employees assignable to each plant.6.If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7.Quantities of fuel burned (Line 37)and average cost
per unit of fuel burned (Line 40)must be consistent with charges to expense accounts 501 and 547 (Line 41)as show on Line 19.8.If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
No.Name:Boulder Park Name:
(a)(b)(c)
1 Kind of Plant (Internal Comb,Gas Turb,Nuclear internal Comb
2 Type of Constr (Conventional,Outdoor,Boiler,etc)Conventional
3 Year Originally Constructed 2002
4 Year Last Unit was Installed 2002
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)24.60 0.00
6 Net Peak Demand on Plant -MW (60 minutes)25 0
7 Plant Hours Connected to Load 656 0
8 Net Continuous Plant Capability (Megawatts)0 0
9 When Not Limited by Condenser Water 0 0
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 2 0
12 Net Generation,Exclusive of Plant Use -KWh 8537000 0
13 Cost of Plant:Land and Land Rights 144675 0
14 Structures and Improvements 703852 0
15 Equipment Costs 30023517 0
16 Total Cost 30872044 0
17 Cost per KW of Installed Capacity (line 5)1254.9611 0.0000
18 Production Expenses:Oper,Supv,&Engr 2805 0
19 Fuel 5044978 0
20 Coolants and Water (Nuclear Plants Only)0 0
21 Steam Expenses O O
22 Steam From Other Sources O O
23 Steam Transferred (Cr)0 0
24 Electric Expenses 120226 0
25 Misc Steam (or Nuclear)Power Expenses O O
26 Rents O O
27 Allowances O O
28 Maintenance Supervision and Engineering 76403 0
29 Maintenance of Structures 4094 0
30 Maintenance of Boiler (or reactor)Plant 0 0
31 Maintenance of Electric Plant 177520 0
32 Maintenance of Misc Steam (or Nuclear)Plant 0 0
33 Total Production Expenses 5426026 0
34 Expenses per Net KWh 0.6356 0.0000
35 Fuel:Kind (Coal,Gas,Oil,or Nuclear)Gas
36 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)Mcf
37 Quantity (units)of Fuel Burned 78026 O O O O O
38 Avg Heat Cont -Fuel Burned (btu/indicate if nuclear)1019000 0 0 0 0 0
39 Avg Cost of Fuellunit,as Delvd f.o.b.during year 6.470 0.000 0.000 0.000 0.000 0.000
40 Average Cost of Fuel per Unit Burned 6.470 0.000 0.000 0.000 0.000 0.000
41 Average Cost of Fuel Burned per Million BTU 6.345 0.000 0.000 0.000 0.000 0.000
42 Average Cost of Fuel Burned per KWh Net Gen 0.059 0.000 0.000 0.000 0.000 0.000
43 Average BTU per KWh Net Generation 9313.000 0.000 0.000 0.000 0.000 0.000
FERC FORM NO.1 (ED.12-95)Page 402.1
Name of Respondent This Report is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)Avista Corp.(2)A Resubmission 04/30/2003 Dec.31,2002
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9.Items under Cost of Plantare based on U.S.of A.Accounts.Production expenses do not include Purchased Power,System Control and Load
Dispatching,and Other Expenses Classified as Other Power Supply Expenses.10.For IC and GT plants,report Operating Expenses,Account Nos.
547 and 549 on Line 24 "Electric Expenses,"and MaintenanceAccount Nos.553 and 554 on Line 31,"Maintenance of Electric Plant."Indicate plants
designed for peak load service.Designate automatically operated plants.11.For a plant equipped with combinations of fossil fuel steam,nuclear
steam,hydro,internal combustion or gas-turbine equipment,report each as a separate plant.However,if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit,include the gas-turbine with the steam plant.12.If a nuclear power generating plant,briefly explain by
footnote (a)accounting method for cost of power generated including any excess costs attributed to research and development;(b)types of cost units
used for the various components of fuel cost;and (c)any other informative data concerning plant type fuel used,fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant Line
Name:Name:Name:No.
(d)(e)(f)
1
2
3
4
0.00 0.00 0.00 5
0 0 0 6
0 0 0 7
O O O 8
0 0 0 9
0 0 0 10
0 0 0 11
0 0 0 12
0 0 0 13
0 0 0 14
0 0 0 15
0 0 0 16
0.0000 0.0000 0.0000 17
0 0 0 18
0 0 0 19
0 0 0 20
0 0 0 21
0 0 0 22
0 0 0 23
0 0 0 24
0 0 0 25
0 0 0 26
0 0 0 27
O O 0 28
0 0 0 29
0 0 0 30
0 0 0 31
0 0 0 32
O O 0 33
0.0000 0.0000 0.0000 34
35
36
0 0 0 0 0 0 0 0 0 37
0 0 0 0 0 0 0 0 0 38
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 39
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43
FERC FORM NO.1 (ED.12-88)Page 403.1
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original (Mo,Da,Yr)Avista Corp.(2)A Resubmission 04/30/2003 Dec.31,2002
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2.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 plan,report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.2545 FERC Licensed Project No.2545
No-Plant Name:Monroe Street Plant Name:Upper Falls
(a)(b)(c)
1 Kind of Plant (Run-of-River or Storage)Run-of-River Run-of-River
2 Plant Construction type (Conventional or Outdoor)Conventional Conventional
3 Year Originally Constructed 1890 1922
4 Year Last Unit was Installed 1992 1922
5 Total installed cap (Gen name plate Rating in MW)14.80 10.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)17 12
7 Plant Hours Connect to Load 8,152 8,676
8 Net PlantCapability (in megawatts)0
9 (a)Under Most Favorable Oper Conditions 15 10
10 (b)Under the Most Adverse Oper Conditions 13 10
11 Average Number of Employees 5 6
12 Net Generation,Exclusive of Plant Use -Kwh 104,697,000 74,623,000
13 Cost of Plant 0
14 Land and Land Rights 0 1,081,854
15 Structures and Improvements 8,146,667 491,800
16 Reservoirs,Dams,and Waterways 8,045,079 2,103,911
17 Equipment Costs 12,652,705 1,972,998
18 Roads,Railroads,and Bridges 50,448 0
19 TOTAL cost (Total of 14 thru 18)28,894,899|5,650,563
20 Cost per KW of Installed Capacity (line 5)1,952.3580 565.0563
21 Production Expenses 0
22 Operation Supervision and Engineering 7,563 8,821
23 Water for Power 0 0
24 Hydraulic Expenses 9,783 11,024
25 Electric Expenses 193,494 187,013
26 Misc Hydraulic Power Generation Expenses 39,657 43,852
27 Rents O O
28 Maintenance Supervision and Engineering 10,037 0
29 Maintenance of Structures 3,569 1,132
30 Maintenance of Reservoirs,Dams,and Waterways 35,422 20,246
31 Maintenance of Electric Plant 113,931 24,696
32 Maintenance of Misc Hydraulic Plant 2,288 0
33 Total Production Expenses (total 22 thru 32)415,744 296,784
34 Expenses per net KWh 0.0040 0.0040
FERC FORM NO.1 (ED.12-88)Page 406
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original (Mo,Da,Yr)Avista Corp.(2)A Resubmission 04/30/2003 Dec.31,2002
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
5.The items under Cost of Plant represent accounts or combinationsof accounts prescribed by the Uniform System of Accounts.Production Expenses
do not include Purchased Power,System control and Load Dispatching,and Other Expenses classified as "Other Power Supply Expenses."
6.Report as a separate plant any plant equipped with combinations of steam,hydro,internal combustion engine,or gas turbine equipment.
FERC Licensed Project No.2058 FERC Licensed Project No.2058 FERC Licensed Project No.2545 LinePlantName:Cabinet Gorge Plant Name:Noxon Rapids Plant Name:Long Lake No.(d)(e)(f)
Storage Storage Storage 1
Outdoor Outdoor Conventional 2
1952 1959 1915 3
1953 1977 1924 4
245.10 466.20 70.00 5
259 548 89 6
8,760 7,657 7,728 7
8
246 527 88 9
239 390 84 10
11 11 8 11
1,084,836,000 1,816,491,000 510,996,000 12
0 13
7,410,089 30,923,726 1,598,139 14
8,937,960 11,091,034 1,617,368 15
17,580,769 30,765,492 16,506,159 16
34,999,720 43,787,449 11,763,212 17
1,098,564 218,199 0 18
70,027,102 116,785,900 31,484,878 19
285.7083 250.5060 449.7840 20
0 21
81,660 82,509 85,461 22
0 64,933 0 23
322,574 361,093 544 24
652,768 699,041 423,624 25
63,366 51,458 81,839 26
O 0 0 27
14,305 13,524 3,815 28
49,048 50,086 28,625 29
68,815 13,244 32,998 30
368,271 540,757 101,112 31
834 9,232 10,294 32
1,621,641 1,885,877 768,312 33
0.0015 0.0010 0.0015 34
FERC FORM NO.1 (ED.12-88)Page 407
Name of Respondent This Report is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)Avista Corp.(2)A Resubmission 04/30/2003 Dec.31,2002
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2.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 plan,report on line 11 the approximate average number of employees assignable to each
plant.
Line Item 'FERC Licensed Project No.2545 FERC Licensed Project No.2545
No.Plant Name:Nine Mile Falls Plant Name:Post Falls
(a)(b)(c)
1 Kind of Plant (Run-of-River or Storage)Run-of-River Storage
2 Plant Construction type (Conventional or Outdoor)Conventional Conventional
3 Year Originally Constructed 1908 1906
4 Year Last Unit was Installed 1994 1980
5 Total installed cap (Gen name plate Rating in MW)26.40 14.80
6 Net Peak Demand on Plant-Megawatts (60 minutes)24 18
7 Plant Hours Connect to Load 8,760 8,760
8 Net Plant Capability (in megawatts)
9 (a)Under Most Favorable Oper Conditions 25 18
10 (b)Under the Most Adverse Oper Conditions 14 9
11 Average Number of Employees 1 1
12 Net Generation,Exclusive of Plant Use -Kwh 125,566,000 87,468,000
13 Cost of Plant
14 Land and Land Rights 33,429 3,095,284
15 Structures and Improvements 3,922,073 611,288
16 Reservoirs,Dams,and Waterways 11,840,543 4,054,643
17 Equipment Costs 12,327,758 3,275,383
18 Roads,Railroads,and Bridges 625,181 0
19 TOTAL cost (Total of 14 thru 18)28,748,984 11,036,598
20 Cost per KW of Installed Capacity (line 5)1,088.9767 745.7161
21 I Production Expenses Ò Ñ 0
22 Operation Supervision and Engineering 15,107 25,337
23 Water for Power 0 21,296
24 Hydraulic Expenses 9,928 9,954
25 Electric Expenses 293,653 288,002
26 Misc Hydraulic Power Generation Expenses 42,745 40,282
27 Rents O O
28 Maintenance Supervision and Engineering 2,837 16,719
29 Maintenance of Structures 12,294 2,751
30 Maintenance of Reservoirs,Dams,and Waterways 91,762 203,601
31 Maintenance of Electric Plant 210,342 39,819
32 Maintenance of Misc Hydraulic Plant 28 0
33 Total Production Expenses (total 22 thru 32)678,696 647,761
34 Expenses per net KWh 0.0054 0.0074
FERC FORM NO.1 (ED.12-88)Page 406.1
Name of Respondent This Report Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)Avista Corp.(2)A Resubmission 04/30/2003 Dec.31,2002
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
5.The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts.Production Expenses
do not include Purchased Power,System control and Load Dispatching,and Other Expenses classified as "Other Power Supply Expenses."
6.Report as a separate plant any plant equipped with combinations of steam,hydro,internal combustion engine,or gas turbine equipment.
FERC Licensed Project No.O FERC Licensed Project No.O FERC Licensed Project No.O LinePlantName:Little Falls Plant Name:Plant Name:No.(d)(e)(f)
Run-of-River i
Conventional 2
1910 3
1911 4
32.00 0.00 0.00 5
41 0 0 6
7,634 0 0 7
8
36 0 0 9
30 0 0 10
3 0 0 11
204,960,000 0 0 12
4,325,371 0 0 14
904,066 0 0 15
4,989,819 0 0 16
5,725,381 0 0 17
0 0 0 18
15,944,637 0 0 19
498.2699 0.0000 0.0000 20
21
23,589 0 0 22
0 0 0 23
174 0 0 24
336,333 0 0 25
36,518 0 0 26
468,032 0 0 27
1,896 0 0 28
13,606 O 0 29
71,862 0 0 30
78,566 0 0 31
0 0 0 32
1,030,576 0 0 33
0.0050 0.0000 0.0000 34
FERC FORM NO.1 (ED.12-88)Page 407.1
Name of Respondent This Report Is:Date of Report Year of Report(1)An Original (Mo,Da,Yr)Avista Corp.(2)A Resubmission 04/30/2003 Dec.31,2002
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2.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 plan,report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.O FERC Licensed Project No.O
No.Plant Name:Plant Name:
(a)(b)(c)
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)0.00 0.00
6 Net PeakDemand on Plant-Megawatts (60 minutes)0 0
7 Plant Hours Connect to Load 0 0
8 Net Plant Capability (in megawatts)
9 (a)Under Most Favorable Oper Conditions O O
10 (b)Under the Most Adverse Oper Conditions 0 0
11 Average Number of Employees O O
12 Net Generation,Exclusive of Plant Use -Kwh 0 0
13 Cost of Plant 0
14 Land and Land Rights O O
15 Structures and Improvements O O
16 Reservoirs,Dams,and Waterways O O
17 Equipment Costs 0 0
18 Roads,Railroads,and Bridges 0 0
19 TOTAL cost (Total of 14 thru 18)0 0
20 Cost per KW of Installed Capacity (line 5)0.0000 0.0000
21 Production Expenses NN
22 Operation Supervision and Engineering 0 0
23 Water for Power 0 0
24 Hydraulic Expenses O 0
25 Electric Expenses O O
26 Misc Hydraulic Power Generation Expenses O O
27 Rents O O
28 Maintenance Supervision and Engineering 0 0
29 Maintenanceof Structures O O
30 Maintenance of Reservoirs,Dams,and Waterways O O
31 Maintenance of Electric Plant 0 0
32 Maintenance of Misc Hydraulic Plant 0 0
33 Total Production Expenses (total 22 thru 32)0 0
34 Expenses per net KWh 0.0000 0.0000
FERC FORM NO.1 (ED.12-88)Page 406.2
Name of Respondent This Report Is:Date of Report Year of Report(1)§An Original (Mo,Da,Yr)Avista Corp'(2)A Resubmission 04/30/2003 Dec.31,2002
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
5.The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts.Production Expenses
do not include Purchased Power,System control and Load Dispatching,and Other Expenses classified as "Other Power Supply Expenses."
6.Report as a separate plant any plant equipped with combinations of steam,hydro,internal combustion engine,or gas turbine equipment.
FERC Licensed Project No.O FERC Licensed Project No.O FERC Licensed Project No-0 LinePlantName:Plant Name:Plant Name:No.(d)(e)(f)
1
2
3
4
0.00 0.00 0.00 5
0 0 0 6
0 0 0 7
0 8
0 0 0 9
0 0 0 10
0 0 0 11
0 0 0 12
13
0 0 0 14
0 0 0 15
0 0 0 16
0 0 0 17
0 0 0 18
0 0 0 19
0.0000 0.0000 0.0000 20
21
O'O O 22
0 0 0 23
0 0 0 24
0 0 0 25
0 0 0 26
O O 0 27
0 0 0 28
0 0 0 29
0 0 0 30
0 0 0 31
0 0 0 32
0 0 0 33
0.0000 0.0000 0.0000 34
FERC FORM NO.1 (ED.12-88)Page 407.2
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
GENERATING PLANT STATlŠTICS (Small Plants)
1.Small generating plants are steam plants of,less than 25,000 Kw,internal combustion and gas turbine-plants,conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating).2.Designate any plant leased from others,operated under a license from
the Federal Energy Regulatory Commission,or operated as a joint facility,and give a concise statement of the facts in a footnote.If licensed project,
give project number in footnote.
Year Installed Óapacity Net Peak Net GenerationLineNameofPlantOrig.Name Plate Ratint Demand Excluding Cost of Plant
No.Const.(In MW)MW Plant Use
(a)(b)(c)(60 in.)(e)(f)
1 Kettle Falls CT 2002 6.87 9.0 7,300,000 9,169,338
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
ERC FORM NO.1 (ED.12-87)Page 410
Name of Respondent This Re ort Is:Date of Report Year of Report
1 (1)X An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp.(2)A Resubmission 04/30/2003 '
GENERATING PLANT STATISTICS (Small Plants)(Continued)
3.List plants appropriately under subheadings for steam,hydro,nuclear,internal combustion and gas turbine plants.For nuclear,see instruction 11,Page 403.4.If net peak demand for 60 minutes is not available,give the which is available,specifying period.5.If any plant is equipped withcombinationsofsteam,hydro internal combustion or gas turbine equipment,report each as a separate plant.However,if the exhaust heat from the gasturbineisutilizedinasteamturbineregenerativefeedwatercycle,or for preheated combustion air in a boiler,report as one plant.
Plant Cost Per MW Operation Production Expenses Fuel Costs (in cents LineInstCapacityExc'l.Fuel l-uel Maintenance Kind of Fuel (per Million Btu)No.(g)(h)(i)(j)(k)(I)
1,335 538,313 Nat Gas 6 1
2
3
4
5
6
7
8
9
10
.12
'13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO.1 (ED.12-87)Page 411
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
TRANSMISSION LINE STATIST CS
1.Report information concerning transmission lines,cost of lines,and expenses for year.List each transmission line having nominal voltage of 132
kilovolts or greater.Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121,Nonutility Property.
5.Indicate whether the type of supporting structure reported in column (e)is:(1)single pole wood or steel;(2)H-frame wood,or steel poles;(3)tower:
or (4)underground construction If a transmission line has more than one type of supporting structure,indicate the mileage of each type of construction
by the use of brackets and extra lines.Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6.Report in columns (f)and (g)the total pole miles of each transmission line.Show in column (f)the pole miles of line on structures the cost of which is
reported for the line designated;conversely,show in column (g)the pole miles of line on structures the cost of which is reported for another line.Report
pole miles of line on leased or partly owned structures in column (g).In a footnote,explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line DEŠlÓNATIÖN VÖLYAÖË (KV)LENGTH (Pole miles)(Indicate where Type of (la the case of NumberNo.other than underground lines
60 cycle,3 ph ase)Supporting report circuit miles)Of
Un Structure Un ctures CircuitsFromToOperatingDesignedStructureofLineoftherDesianatedine(a)(b)(c)(d)(e)(f)(g)(h)
1 Group Sum 60.0C 60.00 1.00
2
3 Group Sum 115.0C 115.00 1,535.00
4
5 Beacon Sub #4 BPA Bell Sub 230.0(230.00 Steel Tower 1.00 1
6 Beacon Sub BPA Bell Sub 230.00 230.00 H Type 5.00 1
7 Beacon Sub #5 BPA Bell Sub 230.00 230.00 H Type 6.00 1
8 Beacon Cabinet Gorge Plant 230.0C 230.00 Steel Tower 1.00 1
9 Beacon Cabinet Gorge Plant 230.0E 230.00 H Type 77.00 1
10 Beacon Sub Lolo Sub 230.00 230.00 Steel Tower 1.00 1
11 Beacon Sub Lolo Sub 230.0(230.00 H Type 108.00 1
12 Noxon Plant Pine Creek Sub 230.0E 230.00 H Type 43.00 1
13 Cabinet Gorge Plant Noxon 230.00 230.00 H Type 19.00 1
14 Benewah Sw.Station Pine Creek Sub 230.00 230.00 Steel Tower 1
15 Benewah Sw.Station PineCreek Sub 230.0(230.00 H Type 43.00 1
16 Divide Creek Lolo Sub 230.0C 230.00 Steel Tower 1
17 Divide Creek Lolo Sub 230.00 230.00 H Type 63.00 1
18 N.Lewiston Walla Walla 230.00 230.00 Steel Tower 70.00 1
19 Walla Walla Wanapum 230.0(230.00 Alum.1
20 Walla Walla Wanapum 230.0E 230.00 H Type 78.00 1
21 BPA (Libby)Noxon Plant 230.00 230.00 Steel Tower 1.00 1
22 BPA/Hot Springs #1 Noxon Plant 230.00 230.00 Steel Tower 1.00 1
23 BPA/Hot Springs #2 Noxon Plant (dead)230.0(230.00 Steel Tower 2.00 1
24 BPA/Hot Springs #2 Noxon Plant 230.0(230.00 H Type 68.00 1
25 BPA Line West Side Sub 230.0(230.00 Steel Pole 4.00 2
26 Hatwai N.Lewiston Sub 230.0C 230.00 H Type 7.00 1
27 Divide Creek Imnaha 230.00 230.00 H Type 20.00 1
28
29 Colstrip Plant Broadview 500.0(500.00
30
31
32
33
34
35
36 TOTAL 2,151.00 3.00 24
FERC FORM NO.1 (ED.12-87)Page 422
Name of Respondent This Report is:Date of Report Year of Report
Avista Corp.(1)QAn Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
RANSMISSION LINE STATISTICS (Continued)
7.Do not report the same transmission line structure twice.Report Lower voltage Lines and higher voltage lines as one line.Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines.If two or more transmission line structures support lines of the same voltage,report the
pole miles of the primary structure in column (f)and the pole miles of the other line(s)in column (g)
18.Designate any transmission line or portion thereof for which the respondent is not the sole owner.If such property is leased from another company,
give name of lessor,date and terms of Lease,and amount of rent for year.For any transmission line other than a leased line,or portion thereof,for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of,furnish a succinct statement explaining the
arrangement and giving particulars (details)of such matters as percent ownership by respondent in the line,name of co-owner,basis of sharing
expenses of the Line,and how the expenses borne by the respondent are accounted for,and accounts affected.Specify whether lessor,co-owner,or
other party is an associated company.
9.Designate any transmission line leased to another company and give name of Lessee,date and terms of lease,annual rent for year,and how
determined.Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j)to (I)on the book cost at end of year.
ÓÓŠT ÓF LINE (Include in Ôolumn (j)Land'EXPENSES,EXCEPT DEPRECIATION AND TAXES
Size of Land rights,and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOtherCostsExpensesExpensesExpenses(i)(j)(k)(1)(m)(n)(o)(p)No.
136,496 174,429 310,928 1
2
3,681,031 71,316,021 74,997,052 199,155 116,350 2,962 318,467 3
4
95 McMACSR 5
1272 McMACSR 17,912 289,560 307,472 142 142 6
1272 McMAL 30,325 362,996 393,319 7
795 McMACSR 8
795 McMACSR 260,607 13,997,555 14,258,162 1,687 1,687 9
795 McMACSR 10
1272 McMAL 455,942 4,168,292 4,624,235 3,955 17,617 21,572 11
54 McMAL 105,64)14,712,791 14,818,438 13,489 13,48E 12
954 McMAL 49,04E 1,057,380 1,106,429 13
954 McMAL 14
954 McMAL 157,191 2,238,750 2,395,943 3,391 7,315 10,706 15
1272 McMAL 16
1272 McMAL 86,22E 3,548,205 3,634,433 3,348 461 672 4,481 17
1272 McMAL 18
1272 McMAL 19
1272 McMAL 70,781 2,190,398 2,261,179 1,647 1,647 20
1272 McMAL 21
1272 McMAL 18,143 18,143 22
1272 McMAL 23
1272 McMAL 144,63E 3,283,337 3,427,975 4,483 4,812 300 9,595 24
1272 McMAL 36,461 587,224 623,685 25
1272 McMACSR 106,581 1,549,898 1,656,479 26
1272McMAL 17,554 1,284,858 1,302,412 27
28
595,78E 28,260,542 28,856,331 77,194 17,212 71,925 166,331 29
30
31
32
33
34
35
5,952,236 149,040,379 154,992,615 306,804 165,454 75,859 548,117 36
FERC FORM NO.1 (ED.12-87)Page 423
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
RANSMISSION LINES ADDED DURING YEAR
1.Report below the information called for concerning Transmission lines added or altered during the year.It is not necessary to report
minor revisions of lines.
2.Provide separate subheadings for overhead and under-ground construction and show each transmission line separately.If actual
costs of competed construction are not readily available for reporting columns (I)to (o),it is permissible to report in these columns the
Line LINE DE$lGNATlÒN Line ŠUPPÓRTINÓ ŠTRUÓTURE |ÓlRÓUITS PERŠTRUCTUR ËLengthAverageINo.From To in Type Number per :Present UltimateMilesMiles
(a)(b)(c)(d)(e)(f)(g)
1 Liberty Lake Opportunity 7.40|Steel 1 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 7.40 1 1
FERC FORM NO.1 (ED.12-86)Page 424
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
TRANSMISSION LINES ADDED DURING YEAR (Continued)
Josts.Designate,however,if estimated amounts are reported.Include costs of Clearing Land and Rights-of-Way,and Roads and
frails,in column (I)with appropriate footnote,and costs of Underground Conduit in column (m).
3.If design voltage differs from operating voltage,indicate such fact by footnote;also where line is other than 60 cycle,3 phase,
,ndicate such other characteristic.
CONDUCTORE Voltage LINE COST Line
Size Specification Configuration KV Land and Poles,Towers Conductors Total No.
and Spacing (Operating)Land Rights and Fixtures and Devices(h)(i)(j)(k)(1)(m)(n)(o)
115 32,995 1,006,087 608,570 1,647,652 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
32,995 1,006,087 608,570 1,647,652 44
FERC FORM NO.1 (ED.12-86)Page 425
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp (1)X An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale,may be grouped according
to functional character,but the number of such substations must be shown.
4.Indicate in column (b)the functional character of each substation,designating whether transmission or distribution and whether
attended or unattended.At the end of the page,summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation I Character of Substation Primary Secondary Tert¡ary
(a)(b)(c)(d)(e)
1 STATE OF WASHINGTON
2
3 Airway Heights Distr.Unattended 115.00 13.80
4 Barker Road Distr.Unattended 110.00 13.80
5 Beacon Trnsm &Dist Unattd 230.00 115.00 13.80
6 Boundary Transm.Unattended 230.00 115.00 13.80
7 Chester Distr.Unattended 115.00 13.80
8 Chewelah 115Kv Distr.Unattended 115.00 13.80
9 Colbert Distr.Unattended 115.00 13.80
10 College &Walnut Distr.Unattended 115.00 13.80
11 Colville 115Kv Distr.Unattended 115.00 13.80
12 Dry Gulch Distr.Unattended 115.00 13.80
13 East Colfax Distr.Unattended 115.00 13.80
14 East Farms Distr.Unattended 115.00 13.80
15 Fort Wright Distr.Unattended 115.00 13.80
16 Fourth &Herald Distr.Unattended 115.00 13.80
17 Francis and Cedar Distr.Unattended 115.00 13.80
18 Gifford Distr.Unattended 115.00 34.00
19 Glenrose Distr.Unattended 115.00 13.80
20 Greenwood Distr.Unattended 115.00 13.80
21 Industrial Park Distr.Unattended 115.00 13.80
22 Kettle Falls Distr.Unattended 115.00 13.80
23 Lee &Reynolds Distr.Unattended 115.00 13.80
24 Liberty Lake Distr.Unattended 115.00 13.80
25 Little Falls 115/34Kv Distr.Unattended 115.00 34.00
26 Lyons &Standard Distr.Unattended 115.00 13.80
27 Mead Distr.Unattended 115.00 13.80
28 Metro Distr.Unattended 115.00 13.80
29 Milan Distr.Unattended 115.00 13.80
30 Millwood Trnsm &Dist Unattd 115.00 60.00 13.80
31 Ninth &Central Distr.Unattended 115.00 13.80
32 Northeast Distr.Unattended 115.00 13.80
33 Northwest Distr.Unattended 115.00 13.80
34 Opportunity Dist &Whrs Unattnd 115.00 13.80
35 Othello Distr.Unattended 115.00 13.80
36 Post Street Distr.Attended 115.00 13.80
37 Pound Lane Distr.Unattended 115.00 13.80
38 Pullman Dist &Trfr Unattnd 115.00 13.80
39 Ross Park Distr.Unattended 115.00 13.80
40 Roxboro Distr.Unattended 115.00 24.00
FERC FORM NO.1 (ED.12-96)Page 426
Name of Respondent This Report is:Date of Report Year of Report(1)OX An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp(2)A Resubmission 04/30/2003 '
SUBSTATIONS(Continued)
5.Show in columns (I),(j),and (k)special equipment such as rotary converters,rectifiers,condensers,etc.and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others,jointly owned with others,or operated otherwise than by
reason of sole ownership by the respondent.For any substation or equipment operated under lease,give name of lessor,date and
period of lease,and annual rent.For any substation or equipment operated other than by reason of sole ownership or lease,give name
of co-owner or other party,explain basis of sharing expenses or other accounting between the parties,and state amounts and accounts
affected in respondent's books of account.Specify in each case whether lessor,co-owner,or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUlPMENT Line
(In Service)(In MVa)Transfeoreers TranSsoar
ers Type of Equipment Number of Units Tot CMapacity No.
(f)(g)(h)(i)(j)(k)
2
24 2 Frcd Oil &Air Fan 2 40 3
12 1 Two Stage Fan 1 20 4
536 4 Frcd Oil &Air Fan 4 560 5
75 1 6
24 2 Frcd Oil &Air Fan 2 40 7
15 3 Frcd Air 3 15 8
12 1 Frcd Oil &Air Fan 1 20 9
36 2 TwoStageFan 2 60 10
31 3 Frcd Oil &Air Fan 3 45 11
24 2 Frcd Oil &Air Fan 2 40 12
12 1 FrOil/Air Fan 1
20=13
12 1 Two Stage Fan 1 20 14
24 2 Fr Oil/Air/2StgFan 2 40 15
12 1 Frcd Oil &Air 1 20 16
60 2 Frcd Air Fan 2 36 17
12 1 18
12 1 Frcd Oil &Air Fan 1 20 19
13 4 1 FrOil/Air/Two Stage 4 22 20
28 3 Two Stg/Pt/Frcd Oil 40 40 21
12 1 Frcd Oil &Air Fan 1 20 22
12 1 Two Stage Fan 1 20 23
24 2 TwoSugeFan 2 40 24
12 1 25
36 2 Two Stage Fan 2 60 26
18 1 Two Stage Fan 1 30 27
24 2 Two Stage Fan 2 40 28
12 1 Frcd Oil &Air Fan 1 20 29
44 3 1 FrcAir/FrcOil/AirFan 3 61 30
24 2 1 Frcd &Two Stage Fan 2 40 31
24 2 Two Stage Fan 2 40 32
24 2 Two Stage Fan 2 40 33
24 2 Two Stage Fan 2 40 34
24 2 FrOil/AirFan 2 40 35
82 5 3 Frcd Oil &Wt Fan 4 6 36
24 2 Two Stage Fan 2 40 37
24 2 Frcd Oil &Air Fan 2 40 38
30 2 Two Stage Fan 2 60 39
24 2 Two Stage Fan 2 40 40
FERC FORM NO.1 (ED.12-96)Page 427
Name of Respondent This Report Is Date of Report Year of Report(1)X An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp.(2)A Resubmission 04/30/2003 '
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale,may be grouped according
to functional character,but the number of such substations must be shown.
4.Indicate in column (b)the functional character of each substation,designating whether transmission or distribution and whether
attended or unattended.At the end of the page,summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Shawnee Trans.Unattended 230.00 115.00
2 Silver Lake Distr.Unattended 115.00 13.80
3 Southeast Distr.Unattended 115.00 13.80
4 South Othello Distr.Unattended 115.00 13.80
5 South Pullman Distr.Unattended 115.00 13.80
6 Sunset Distr.Unattended 115.00 13.80
7 Third &Hatch Distr.Unattended 115.00 13.80
8 Waikiki Distr.Unattended 115.00 13.80
9 West Side Trans.Unattended 230.00 115.00 13.80
10 Other:74 substa less than 10MVA Distr.Unattended
11
12 STATE OF IDAHO
13 Appleway Dist &Trfr Unattnd 115.00 13.80
14 Benewah Trans.Unattended 230.00 115.00 13.80
15 Big Creek Distr.Unattended 115.00 13.80
16 Blue Creek Distr.Unattended 115.00 13.80
17 Bunker Hill Distr.Attended 115.00 13.80
18 Clark Fork Distr.Unattended 115.00 21.80
19 Coeur d'Alene 15th Ave Distr.Unattended 115.00 13.80
20 Dalton Distr.Unattended 115.00 13.80
21 Grangeville Dist &Trfr Unattnd 115.00 13.80
22 Holbrook Distr.Unattended 115.00 13.80
23 Huetter Distr.Unattended 115.00 13.80
24 Juliaetta Distr.Unattended 115.00 13.80
25 Kamiah Dist &Trfr Unattnd 115.00 13.80
26 Kooskia Distr.Unattended 115.00 13.80
27 Lolo Tran &Dist Unattnd 230.00 115.00 13.80
28 Moscow Distr.Unattended 115.00 13.80
29 Moscow 230Kv Tran &Dist Unattnd 230.00 115.00 13.80
30 North Moscow Distr.Unattended 115.00 13.80
31 Newport Tran &Trfr Unattnd 115.00 60.00
32 North Lewtston Tran &Trfr Unattnd 115.00 13.80
33 North Lewiston Distr.Unattended 115.00 13.80
34 Oden Distr.Unattended 115.00 21.80
35 Orofino Distr.Unattended 115.00 13.80
36 Osburn Distr.Unattended 115.00 13.80
37 Pine Creek Tran &Dist Unattnd 230.00 110.00 13.80
38 Pleasant View Distr.Unattended 115.00 13.80
39 Post Falls Distr.Unattended 115.00 13.80
40 Potlatch Dist &Trfr Unattnd 115.00 13.80
FERC FORM NO.1 (ED.12-96)Page 426.1
Name of Respondent This Re ort Is:Date of Report Year of Report
Avista Corp (1)X An Original (Mo,Da,Yr)Dec.31,2002(2)A Resubmission 04/30/2003
SUBSTATIONS(Continued)
5.Show in columns (I),(j),and (k)special equipment such as rotary converters,rectifiers,condensers,etc.and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others,jointly owned with others,or operated otherwise than byreasonofsoleownershipbytherespondent.For any substation or equipment operated under lease,give name of lessor,date andperiodoflease,and annual rent.For any substation or equipment operated other than by reason of sole ownership or lease,give name
of co-owner or other party,explain basis of sharing expenses or other accounting between the parties,and state amounts and accountsaffectedinrespondent's books of account.Specify in each case whether lessor,co-owner,or other party is an associated company.
Capacity of Substation i Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT LineTransformersSpare(In Service)(In MVa)In Service Transformers Type of Equipment Numberof Units Total Capacity No.
(in MVa)(f)(g)(h)(i)(j)(k)
250 1 1
12 1 Frcd Oil &Air Fan 1 20 2
30 2 Two Stage Fan 2 50 3
12 1 Two Stage Fan 1 20 4
30 2 Two Stage Fan 240 50 5
35 4 1 Pt.&Two Stage Fan 4 50 6
54 3 Two Stg Fan &Cap 103 90 7
24 2 Two Stage Fan 2 40 8
250 2 9
197 144 1 10
11
12
30 2 Two Stage Fan 2 50 13
125 1 14
18 2 Portable Fan 2 22 15
20 3 1 16
22 1 Frcd Air Fan!1 26 17
10 1 Frcd Air Fan 1 13 18
36 2 TwoStageFan 2 60 19
24 2 FrcOil/Air2StgFan 2 40 20
25 4 FrcdOil/Air/Pt Fan 2 34 21
12 1 Two Stage Fan 1 20 22
12 1 Two Stage Fan 1 20 23
12 1 Frcd Oil &Air Fan 1 20 24
12 1 Two Stage Fan 1 20 25
15 3 Frcd Air Fan 2 20 26
270 3 Frcd Oil/Air/Two Stg 1 262 27
24 2 FrOil/Air/2Stg Fan 2 40 28
137 2 1 Capacitors 80 182 29
12 1 Two Stage Fan 1 20 30
15 3 31
250 1 FrcdOil/AirFan/Cptrs 80 295 32
10 3 33
10 1 Frcd Air Fan 13 34
20 2 Frcd Oil &Air Fan 1 28 35
12 1 PodableFan 1 15 36
262 3 Capacitors 80 307 37
12 1 Two Stage Fan 1 20 38
18 1 Two Stage Fan 1 30 39
15 2 Portable Fan 2 19 40
FERC FORM NO.1 (ED.12-96)Page 427.1
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale,may be grouped according
to functional character,but the number of such substations must be shown.
4.Indicate in column (b)the functional character of each substation,designating whether transmission or distribution and whether
attended or unattended.At the end of the page,summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Prarie Distr.Unattended 115.00 13.80
2 Priest River Distr.Unattended 115.00 20.80
3 Sandpoint Distr.Unattended 115.00 20.80
4 South Lewiston Distr.Unattended 115.00 13.80
5 Sweetwater Distr.Unattended 115.00 24.00
6 St.Maries Distr.Unattended 115.00 24.00
7 Tenth &Stewart Distr.Unattended 115.00 13.80
8 Wallace Dist &Whse Unattnd 115.00 13.80
9 Rathdrum Tran &Dist Unattnd 230.00 115.00 13.80
10 Other:30 substa less than 10 MVA Distr.Unattended
11
12 STATE OF MONTANA
13 1 substation less than 10 MVA Distr.Unattended
14
15 SUBSTA.@ GENERATING PLANTS
16 STATE OF WASHINGTON
17 Boulder Park Trans Step-Up 115.00 13.80.
18 Kettle Falls Trans Step-Up 115.00 13.80
19 Long Lake Trans.115.00 4.00 4.00
20 Nine Mile Trns Step-Up &Dist 115.00 60.00 2.30
21 Little Falls Trans.115.00 4.00
22 Northeast Trans.Step-Up 115.00 13.80
23
24 STATE OF IDAHO
25 Cabinet Gorge Trans.Step-Up 115.00 13.80
26 Cabinet Gorge Trans.Step-Up 230.00 13.80
27 Post Falls Trans.Step-Up 115.00 2.30
28 Rathdrum Trans.Step-Up 115.00 13.80
29
30 STATE OF MONTANA
31 Noxon Trans.Step-Up 230.00 13.80
32
33 SUMMARY:
34 Washington:1 sub Distr.Attended
35 9 subs Trans.Unattended
36 115 subs Distr.Unattended
37 2 subs Tran &Dist Unattnd
38 Idaho:1 sub Distr.Attended
39 7 subs Trans.Unattended
40 60 subs Distr.Unattended
FERC FORM NO.1 (ED.12-96)Page 426.2
Name of Respondent This Report Is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp.(2)A Resubmission 04/30/2003 '
SUBSTATIONS (Continued)
5.Show in columns (l),(j),and (k)special equipment such as rotary converters,rectifiers,condensers,etc.and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others,jointly owned with others,or operated otherwise than by
reason of sole ownership by the respondent.For any substation or equipment operated under lease,give name of lessor,date and
period of lease,and annual rent.For any substation or equipment operated other than by reason of sole ownership or lease,give name
of co-owner or other party,explain basis of sharing expenses or other accounting between the parties,and state amounts and accounts
affected in respondent's books of account.Specify in each case whether lessor,co-owner,or other party is an associated company.
Capacity of Substation Number of Number of |CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)Transfeoreers TranSsoar
ers Type of Equipment Number of Units Total CMapacity No.
(f)(g)(h)(i)(j)(k)
12 1 Frcd Oil &Air Fan 1 20 1
10 1 1 Frcd Air Fan 1 13 2
30 3 Frcd Air Fan 3 38 3
27 4 Port Fan/FrcdOil/Air 4 39 4
12 1 Frcd Oil &Air Fan 1 20 5
24 2 Two Stage Fan 2 40 6
30 2 Frcd Oil/Air/Two Stg 2 50 7
10 3 8
462 3 FrcdOil/AirFan/Cptrs 243 470 9
83 48 10
11
12
5 1 13
14
15
16
36 1 Two Stage Fan 1 60 17
30 1 Two Stage Fan 1 62 18
80 4 1 19
18 2 Frcd Oil &Air Fan 1 40 20
24 2 Frcd Oil &Air Fan 2 40 21
36 1 Two Stage Fan 1 60 22
23
24
25 1 Frcd Oil &Air Fan 1 42 25
402 7 1 26
16!2 Frcd Air/Oil/Air Fan 2 21 27
114 2 3 Two Stage Fan 2 190 28
29
30
532 9 1 Frcd Oil Air 6 555 31
32
33
82 34
799 35
1130 36
580 37
22 38
947 39
595 40
FERC FORM NO.1 (ED.12-96)Page 427.2
Name of Respondent This Re ort Is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)Dec.31 2002AvistaCorp.(2)A Resubmission 04/30/2003 '
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale,may be grouped according
to functional character,but the number of such substations must be shown.
4.Indicate in column (b)the functional character of each substation,designating whether transmission or distribution and whether
attended or unattended.At the end of the page,summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (in MVa)
No Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 4 subs Tran &Dist Unattnd
2 Montana:1 sub Trans.Unattended
3 1 sub Distr.Unattended
4 System:201 subs
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO.1 (ED.12-96)Page 426.3
Name of Respondent This Report Is:Date of Report Year of Report
Avista Corp.(1)X An Original (Mo,Da,Yr)Dec.31,2002
(2)A Resubmission 04/30/2003
SUBSTATIONS (Continued)
5.Show in columns (l),(j),and (k)special equipment such as rotary converters,rectifiers,condensers,etc.and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others,jointly owned with others,or operated otherwise than by
reason of sole ownership by the respondent.For any substation or equipment operated under lease,give name of lessor,date and
period of lease,and annual rent.For any substation or equipment operated other than by reason of sole ownership or lease,give name
of co-owner or other party,explain basis of sharing expenses or other accounting between the parties,and state amounts and accounts
affected in respondent's books of account.Specify in each case whether lessor,co-owner,or other party is an associated company.
Capacity of Substation Number of Number of CONVERSIONAPPARATUS AND SPECIAL EQUIPMENT Line
(in Service)(in MVa)Transfeoreers TranSsoar
ers Type of Equipment Number of Units Total CMapacity No.
(f)(g)(h)(i)(j)(k)
1131 1
533 2
5 3
5825 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO.1 (ED.12-96)Page 427.3
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
FOOTNOTE DATA
Schedule Page:103.1 Line No.:23 Column:dIndirectlycontrolledbytheRespondent owned by Pentzer Corporation,a wholly ownedAvistaCapitalSubsidiary.See Avista Capital and Pentzer Corporation listings on page
103.
Schedule Page:103.2 Line No.:7 Column:d
51%owned by Cogentrix,Inc .
Schedule Page:103.2 Line No.:10 Column:d
50%owned by Mirant Americas Development,Inc.
FERC FORM NO.1 (ED.12-87)Page 450
Name of Respondent This Report is:Date of Report Year of Report
(1)_X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubrnission 04/30/2003 Dec 31,2002
FOOTNOTE DATA
Schedule Page:216 Line No.:26 Column:b
On January 1,2003,Coyote Springs II plant was transferred from Avista Power to AvistaUtility.Amount transferred was $108,926,883.67
FERC FORM NO.1 (ED.12-87)Page 450
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
FOOTNOTE DATA
Schedule Page:219 Line No.:3 Column:c
Interest credits under sinking fund method (on Hydro plant only)is $4,889,832.48
FERC FORM NO.1 (ED.12-87)Page 450
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubrnission 04/30/2003 Dec 31,2002
FOOTNOTE DATA
Schedule Page:227 Line No.:1 Column:d
Electric
Schedule Page:227 Line No.:5 Column:d
Schedule Page:227 Line No.:7 Column:d
Schedule Page:227 Line No.:8 Column:d
Electric .
Schedule Page:227 Line No.:9 Column:d
Electric .
Schedule Page:227 Line No.:10 Column:d
Electric,gas &miscellaneous.
FERC FORM NO.1 (ED.12-87)Page 450
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
FOOTNOTE DATA
Schedule Page:310 Line No.:12 Column:b
Cogentrix DES service contract terminates January 22,2005.
Schedule Page:310.1 Line No.:7 Column:b
Enron contact terminates December 31,2016.
Schedule Page:310.2 Line No.:11 Column:b
NorthWestern Energy contract terminates October 31,2003.
Schedule Page:310.3 Line No.:1 Column:b
PacifiCorp sale terminates September 15,2003.
Schedule Page:310.3 Line No.:3 Column:b
PacifiCorp sale terminates October 31,2003.
Schedule Page:310.3 Line No.:4 Column:b
Pend Oreille County PUD terminates October 31,2004.
Schedule Page:310.3 Line No.:11 Column:b
PP&L Montana terminates October 31,2003.
Schedule Page:310.3 Line No.:14 Column:b
Puget Sound Energy sale terminates December 31,2002.
Schedule Page:310.4 Line No.:1 Column:b
Puget Sound Energy terminates October 31,2003.
Schedule Page:310.4 Line No.:8 Column:b
Sovereign DES contract terminates July 31,2004.
Schedule Page:310.4 Line No.:14 Column:b
IntraCompany Wheeling.
Schedule Page:310.5 Line No.:1 Column:b
IntraCompany Generation -Sale of Ancillary Services .
Schedule Page:310.5 Line No.:2 Column:b
Estimated revenues -true up in later periods.
FERC FORM NO.1 (ED.12-87)Page 450
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
FOOTNOTE DATA
Schedule Page:326 Line No.:6 Column:b
BPA -WNP#3 Contract terminates June 30,2017.
Schedule Page:326 Line No.:7 Column:b
BPA -CSPE &Supp/Entitlement Capacity -terminate March 31,2003.
Schedule Page:326 Line No.:8 Column:b
Other Charges -Internal Nonmonetary accrual
Schedule Page:326 Line No.:9 Column:b
Storage charges
Schedule Page:326 Line No.:13 Column:b
CSPE Capacity -terminates March 31,2003.
Schedule Page:326.1 Line No.:10 Column:b
Other charges -Buyout future delivery contracts
Schedule Page:326.2 Line No.:5 Column:b
Service to Deer Lake customers delivered from Inland Power &Light.
Schedule Page:326.3 Line No.:5 Column:b
Other Charges -Internal Nonmonetary accrual
Schedule Page:326.3 Line No.:8 Column:b
Other charges -Internal Nonmonetary accrual
Schedule Page:326.3 Line No.:9 Column:b
Other Charges -Internal Nonomonetary accrual
Schedule Page:326.4 Line No.:6 Column:b
Off System exchange of energy
Schedule Page:326.5 Line No.:3 Column:b
Other Charges -Ancillary Services
Schedule Page:326.5 Line No.:7 Column:b
Other Charges -Amortization of contract buyout
Schedule Page:326.5 Line No.:10 Column:a
Intra Company Transfers
Schedule Page:326.5 Line No.:10 Column:b
Other Charges -Ancillary Services
Schedule Page:326.5 Line No.:11 Column:b
Inadvertent energy.
FERC FORM NO.1 (ED.12-87)Page 450
Nameof Respondent ThisRepodis:DateofRepon YearofRepon
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
FOOTNOTEDATA
Schedule Page:328 Line No.:1 Column:a
Subsidiary of Avista Corp
Schedule Page:328 Line No.:2 Column:a
Subsidiary of Avista Corp.
Schedule Page:328 Line No.:3 Column:a
Subsidiary of Avista Corp.
Schedule Page:328 Line No.:4 Column:a
Subsidiary of Avista Corp.
Schedule Page:328 Line No.:5 Column:aSubsidiaryofAvistaCorp.
Schedule Page:328 Line No.:6 Column:a
Subsidiary of Avista Corp.
Other Charges -Anciliary Services
Schedule Page:328 Line No.:7 Column:a
Transfer Agreement terminates October 31,2005
Schedule Page:328 Line No.:10 Column:a
Agreement terminates Sept.30,2006
Other charges -Use of Facilities
Schedule Page:328.1 Line No.:1 Column:a
Agreement terminates on one year notice
Other Charges -Use of Facilities
Schedule Page:328.4 Line No.:9 Column:a
Agreement terminates December 31,2012
Schedule Page:328.6 Line No.:TO Column:a
Agreement terminates Feb.1,2002
Schedule Page:328.7 Line No.:12 Column:a
Agreement terminates Oct.30,2005
Schedule Page:328.8 Line No.:6 Column:a
Agreement terminates Feb.28,2011
Other Charges -Use of Facilities
Schedule Page:328.8 Line No.:7 Column:a
Agreement terminates Dec 31,2003
Schedule Page:328.8 Line No.:8 Column:a
Agreement terminates Oct 30,2005
Schedule Page:328.8 Line No.:9 Column:a
Agreement terminates Nov.11,2015
Schedule Page:328.9 Line No.:6 Column:a
Other Charges -Losses delivered
FERC FORM NO.1 (ED.12-87)Page 450
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
FOOTNOTE DATA
Schedule Page:332 Line No.:6 Column:a
Other Charges -prior period adjustment
Schedule Page:332 Line No.:10 Column:a
Delivered power to wheeler.
Othercharges -prior period adjustment
Schedule Page:332 Line No.:11 Column:a
Received power from wheeler
Other Charges -prior period adjustment
Schedule Page:332.1 Line No.:2 Column:a
Other charges -prior period adjustment
Schedule Page:332.1 Line No.:7 Column:a
Other charges -prior period adjustment
FERC FORM NO.1 (ED.12-87)Page 450
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
FOOTNOTE DATA
Schedule Page:335 Line No.:5 Column:b
Vendor Purpose 2002 Amount
ADP -PROXY SERVICES Deliveryof Proxy 34,201.78
BANKERS TRUST Common Stock 141,900.39
CAGNEY MCDOWELL INC Annual Report 87,234.26
CITIBANK NA Fees &Services 22,308.01
FITCH INC Annual Rating Fee 21,563.10
FOUR SEASONS OLYMPIC HOTEL Board of Directors Meetings 11,374.14
JP MORGAN CHASE BANK Trustee Fees 43,595.57
LAKE COUNTY PRESS INC 2001 annual Report Printing 44,421.78
LAWTON PRINTING INC 2002 Annual Report Printing 33,465.93
MOODY'S INVESTORSSERVICE Credit Monitoring 25,156.95
NEW YORK STOCK EXCHANGE INC annual Listing 27,767.52
PROCARD 9,010.80
RR DONNELLEY RECEIVABLESINC 2001 Appendix A 26,784.13
SHARMAN COMMUNICATIONS 2001 Annual Report 8,526.57
SPOKANE CLUB Directors Meetings 7,396.39
STANDARD AND POOR'S Annual Payment 7,331.45
STATE STREET BANK &TRUST CO Annual Admin Fee 8,518.54
THE BANK OF NEW YORK Stock Related Transfers &Fees 152,758.95
THELEN REID &PRIEST Legal 5,721.51
TOM MADAY PHOTOGRAPHY 2002 Annual Report 20,587.01
WILMINGTON TRUST COMPANY Services 7,259.58
FERC FORM NO.1 (ED.12-87)Page 450
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)_A Resubmission 04/30/2003 Dec 31,2002
FOOTNOTE DATA
Schedule Page:402 Line No.:-1 Column:b
Leased Plant
Schedule Page:402 Line No.:-1 Column:e
Operated by PPL Montana LLC.
Schedule Page:402 Line No.:-1 Column:f
Leased plant .
FERC FORM NO.1 (ED.12-87)Page 450
Name of Respondent This Report is:Date of Report Year of Report
(1)X An Original (Mo,Da,Yr)
Avista Corp.(2)A Resubmission 04/30/2003 Dec 31,2002
FOOTNOTE DATA
Schedule Page:406 Line No.:-2 Column:b
Schedule Page:406 Line No.:-2 Column:c
Schedule Page:406 Line No.:-2 Column:d
License period from March 1,2001 to February28,2046
Schedule Page:406 Line No.:-2 Column:e
License period from March 1,2001 to February28,2046
Schedule Page:406 Line No.:-2 Column:f
License period from August 1,1972 to July 31,2007.
Schedule Page:406.1 Line No.:-2 Column:b
Schedule Page:406.1 Line No.:-2 Column:c
Schedule Page:406.1 Line No.:-2 Column:d
Not a licensed project.
FERC FORM NO.1 (ED.12-87)Page 450