2003Annual Report.pdf

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THIS FILING IS (CHECK ONE BOX FOR EACH ITEM)
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081
FERC Form No.
ANNUAL REPORT OF MAJOR ELECTRIC
UTiliTIES, lIC-ENSEES 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 other
sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider this report to be of a confidential nature.
Exact Legal Name of Respondent (Company)
Avista Corp.
Year of Report
Dec. 31 2003
fERC FORM No.1 (REV. 12-98)
FERC FORM NO.
ANNUAL REPORT OF MAJOR ELECTRIC UTiliTIES, liCENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent
Avista Corp.
02 Year of Report
Dec. 31 2003
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 Ave, Spokane, W A 99202
05 Name of Contact Person
M. K. Malquist
06 Title of Contact Person
Senior VP & CFO
07 Address of Contact Person (Street, City, State, Zip Code)
1411 E. Mission Ave, Spokane, W A 99202
08 Telephone of Contact Person lnc/uding 09 This Report Is
Area Code (1) 00 An Original
[phone]
(2) D A Resubmission
10 Date of Report
(Mo, Da, Yr)
04/30/2004
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 and
affairs of the above named respondent in respect to each and every matter set forth therein during the period from and including January 1 to
and including December 31 of the year of the report.
01 Name
M. K. Malquist
03 Signature 04 Date Signed
(Mo, Da, Yr)
02 Title
Senior Vice President and CFO
l((,.1 /'1/
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04/30/2004
Title 18, U.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM No.1 (ED. 12-91)Page
Name of Respondent This
wort
Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) nA Resubmission 04/30/2004
LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none
" "
not applicable " or "" 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.Page No.
(a)(b)(c)
General Information 101
Control Over Respondent 102 None
Corporations Controlled by Respondent 103
Officers 104
Directors 105
Important Changes During the Year 108-109
Comparative Balance Sheet 110-113
Statement of Income for the Year 114-117
Statement of Retained Eamings for the Year 118-119
Statement of Cash Flows 120-121
Notes to Financial Statements 122-123
Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b)
Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
Nuclear Fuel Materials 202-203 None
Electric Plant in Service 204-207
Electric Plant Leased to Others 213 None
Electric Plant Held for Future Use 214 None
Construction Work in Progress-Electric 216
Accumulated Provision for Depreciation of Electric Utility Plant 219
Investment of Subsidiary Companies 224-225
Materials and Supplies 227
Allowances 228-229 None
Extraordinary Property Losses 230 None
Unrecovered Plant and Regulatory Study Costs 230 None
Other Regulatory Assets 232
Miscellaneous Deferred Debits 233
Accumulated Deferred Income Taxes 234
Capital Stock 250-251
Other Paid-in Capital 253 None
Capital Stock Expense 254
Long-Term Debit 256-257
Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 261
Taxes Accrued, Prepaid and Charged During the Year 262-263
Accumulated Deferred Investment Tax Credits 266-267
Other Deferred Credits 269
Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273 None
FERC FORM NO.1 (ED. 12-96)Page 2
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)
Dec. 31 2003(2) n A Resubmission 04/30/2004
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none,
" "
not applicable," or "" 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 RemarksNo.Page No.
(a)(b)(c)
Accumulated Deferred Income Taxes-Other Property 274-275
Accumulated Deferred Income Taxes-Other 276-277
Other Regulatory Liabilities 278
Electric Operating Revenues 300-301
Sales of Electricity by Rate Schedules 304
Sales for Resale 310-311
Electric Operation and Maintenance Expenses 320-323
Purchased Power 326-327
Transmission of Electricity for Others 328-330
Transmission of Electricity by Others 332
Miscellaneous General Expenses-Electric 335
Depreciation and Amortization of Electric Plant 336-337
Regulatory Commission Expenses 350-351
Research, Development and Demonstration Activities 352-353 None
Distribution of Salaries and Wages 354-355
Common Utility Plant and Expenses 356
Electric Energy Account 401
Monthly Peaks and Output 401
Steam Electric Generating Plant Statistics (Large Plants)402-403
Hydroelectric Generating Plant Statistics (Large Plants)406-407
Pumped Storage Generating Plant Statistics (Large Plants)408-409 None
Generating Plant Statistics (Small Plants)410-411
Transmission Line Statistics 422-423
Transmission Lines Added During Year 424-425 None
Substations 426-427
Footnote Data 450
Stockholders' Reports Check appropriate box:
(!I Four copies will be submitted
No annual report to stockholders is prepared
FERC FORM NO.1 (ED. 12-96)Page 3
Name of Respondent
Avista corp.
This Report Is:
(1 ) 00 An Original(2) D A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2004
Year of Report
Dec. 31 2003
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, Chief Financial Officer and Treasurer
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) D Yes...Enter the date when such independent accountant was initially engaged:
(2) IXI No
FERC FORM No.1 (ED. 12-87)PAGE 101
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
CORPORATIONS CONTROLLED BY R ;;SPONDENT
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, namingany 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 thevoting 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)
Avista Capital Parent company to all of the 100
Company s subsidiaries.
Avista Advantage, Inc.Provides various energy 100
services, such as Internet-
6 .based specialty billing and
information services.
Avista Communications, Inc.An Integrated Communications 100 Currently inactive
Provider (ICP) that provided
local telecommunications
solutions and designed, built
and managed metropolitan
area fiber optic networks.
Avista Development, Inc.Nonoperating company which 100
maintains a small investment
portfolio of real estate and
other investments.
Avista Energy, Inc.Wholesale electricity and 99.
natural gas trading,marketing
and resource management.
Avista laboratories, Inc.Develops proton exchange 100
membrane (PEM) fuel cell
technology and fuel cell
FERC FORM NO.1 (ED. 12-96)Page 103
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmission 04/30/2004
)RPORA TIONS 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)
components.
Avista Power, LLC Owns generation assets.100
Avista Services, Inc.Offers products/services to 100 Currently Inactive
utility customers.
Avista Turbine Power, Inc.Receives assignments of 100
purchase power agreements.
Avista Rathdrum, LLC Owns electric 100
generation assets.
Avista Ventures, Inc.Invests in emerging business 100
opportunities.
Pentzer Corporation Within Avista Capital;100
parent company of Advanced
Manufacturing and
Development.
Advanced Manufacturing and Development, Inc.Performs custom sheet metal
manufacturing of electronic
enclosures, parts and systems
for the computer, telecom and
medical industries. AM&D
FERC FORM NO.1 (ED. 12-96)Page 103.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
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)
also has a wood products
division that provides
complete fabrication and
tumkey assembly for arcade
games, kiosks, store fixtures
and displays.
Avista Receivables Corporation Acquires and sells accounts 100
receivable of Avista Corp.
Avista Energy Canada, Ltd.A wholly owned subsidiary of 100
Avista Energy, Inc. that
provides natural gas service
to approximately 400
individual customers in
British Columbia, Canada
INDIRECT CONTROL:
Rathdrum Power, LLC Developed and owns an
electric generation asset.
Coyote Springs 2, LLC Developed and owns an
electric generation asset.
WP Funding LP Owns an electric generation Avista Corp.
asset.consolidates under
FIN 46 in 2003.
Spokane Energy, LLC Marketing of energy.100
FERC FORM NO.1 (ED. 12-96)Page 103.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004
OFFICERS
1. Report below the name, title and salary for each executive officer whose salary is $50 000 or more. An "executive officer" of arespondent 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 Officer S~l.aryNo.for Year(a)(b)(c)
Chairman of the Board, President, and
Chief Executive Officer Ely 528,205
Senior Vice President and Chief Financial Officer M. K. Malquist 254 036
Senior Vice President and General Counsel D. J. Meyer 240,000
Senior Vice President (Retired 3/31/03)J. E. Eliassen 125,295
Senior Vice President S. L. Morris 261 390
Vice President (Title change effective 3/31/03)R. R. Peterson 173,315
Vice President and Assistant to the Chairman of the T. L. Syms 145,000
Board (Title change effective 3/31/03)
Vice President R. D. Woodworth 198,668
Vice President and Controller C. M. Burmeister - Smith 167,513
Vice President and Treasurer (Title change D. A. Brukardt 179,404
effective 3/31/03)
Vice President K. O. Norwood 149,000
Vice President and Corporate Secretary (Title change K. S. Feltes 176,296
effective 3/31/03)
FERC FORM NO.1 (ED. 12-96)Page 104
Name of Respondent This (!Jort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004
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.
LlrJe Name (anc;J -' me) or Ulrector PrinCipal tiUSlness AooressNo.(a)(b)
David A. Clack***325 E. Sprague Avenue, Spokane WA 99202
Lura J. Powell 2400 Stevens Dr., Suite B, Richland, WA 99352
R. John Taylor
***
111 Main Street, Lewiston ID 83501
Sarah M. R. (Sally) Jewell (Completed term 5/8/03)6750 S. 228th Street, Kent WA 98032
John F. Kelly 4915 E. Doubletree Ranch Rd., Paradise Valley, AZ 85253
Jack W. Gustavel P. O. Box J, Coeur d' Alene, ID 83816
Jessie J. Knight, Jr.Emerald Plaza, 402 W. Broadway, Suite 1000, San Diego, CA
92101
Erik J. Anderson 801 Second Ave 13th Floor, Seattle WA 98104
Kristianne Blake
***
O. Box 28338, Spokane WA 99228
Gary G. Ely 1411 E. Mission Ave, Spokane, WA 99202
(Chairman, President, & CEO)
Roy Lewis Eiguren O. Box 2720, Boise, ID 83701
FERC FORM NO.1 (ED. 12-95)Page 105
Name of Respondent
Avista Corp.
This Report Is:(1) (29 An Original(2) 0 A Resubmission 04/30/2004
IMPORTANT CHANGES DURING THE YEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them inaccordance 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 thefranchise 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 toCommission 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: Giveeffective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-termdebt 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 1 to 11 above, such notes may be included on this page.
Date of Report Year of Report
Dec. 31 2003
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) An Original (Mo, Da, Yr)
Avista Corp.(2) A Resubmission 04/30/2004 Dec 31 2003
IMPORTANT CHANGES DURING THE YEAR (Continued)
None
None
None
None
None
In September 2003, the Company issued $45.0 million of 6.125 percent First Mortgage Bonds due in 2013. This debt was
issued under a registration statement flied on Form S-3 with the Securities and Exchange Conunission for up to $150.
million of secured or unsecured debt securities. The $150.0 million registration statement was approved by the WUTC under
docket UE-031031, the IPUC under case #A VU-03-03 and the OPUC under docket UF-4198. Reference is made to Notes
, 12, 14, and 17 of Notes to Financial Statements, Page 122 of this Report.
None
Average annual wage increases were 2.9% in 2003 for non-exempt personnel. Annual average wage increases were 3.1 % for
exempt employees. Bargaining unit employees were granted increases of3.0%.
Reference is made to Note 23 of Notes to Financial Statements, Page 122 of this Report.
None.
N/A
See Page 122 of this Report.
10.
11.
12.
I FERC FORM NO.1 (ED. 12-96)Page 109.
This Report Is: Date of Report
(1 ) (ZI An Original (Mo, Da, Yr)
(2) A Resubmission 04/30/2004
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)Ref. Balance at
Page No. Beginning of Year(b) (c)
Name of Respondent
Avista corp.
Line
No.
Title of Account
(a)
UTILITY PLANT
200-201
200-201
200-201
202-203
202-203
122
224-225
228-229
227
227
227
227
227
227
202-203/227
228-229
227
Year of Report
Dec. 31,2003
Balance at
End of Year
(d)
--_.._, --,,-----"-'-"--"'-'-'---'- -'---,-,'..",-,----,..",
370,810,931
17,581 119
388,392 050
824 688,269
1 ,563,703,781
563,703,781
156,010
107 826
256,737,
46,498,833
182 354
317,467,111
10,048,633
465,146
384,217
126,777
28,898,856
238,495
688,665
137,275,
791,870
261,
449,
544 618,721
49,615 389
594,234,110
886,846 714
707,387 396
1 ,707 387 396
264,833
118,011
255,904,488
55,738,128
16,429 928
331,219,366
136,438
577,122
143,327
45,726,942
175,943
281 537
40,018,082
10,855
395,349
522,082
-496,415
176,453
640,745
068,826
961
459,233
610,557
, 14
Utility Plant (101-106,114)
Construction Work in Progress (107)
TOTAL Utility Plant (Enter Total of lines 2 and 3)
(Less) Accum. Provo for Depr. Amort. Depl. (108, 111 , 115)
Net Utility Plant (Enter Total of line 4 less 5)
Nuclear Fuel (120.120.4, 120.
(Less) Accum. Provo for Amort. of Nucl. Fuel Assemblies (120.
Net Nuclear Fuel (Enter Total of line 7 less 8)
Net Utility Plant (Enter Total of lines 6 and 9)
Utility Plant Adjustments (116)
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutility Property (121)
(Less) Accum. Provo for Depr. and Amort. (122)
Investments in Associated Companies (123)
Investment in Subsidiary Companies (123.
(For Cost of Account 123.1, See Footnote Page -224, line 42)
Noncurrent Portion of Allowances
Other Investments (124)
Special Funds (125-128)
TOTAL Other Property and Investments (Total of lines 14-17,19-21)
CURRENT AND ACCRUED ASSETS
Cash (131)
Special Deposits (132-134)
Working Fund (135)
Temporary Cash Investments (136)
Notes Receivable (141)
Customer Accounts Receivable (142)
Other Accounts Receivable (143)
(Less) Accum. Provo for Uncollectible Acct.-Credit (144)
Notes Receivable from Associated Companies (145)
Accounts Receivable from Assoc. Companies (146)
Fuel Stock (151)
Fuel Stock Expenses Undistributed (152)
Residuals (Elec) and Extracted Products (153)
Plant Materials and Operating Supplies (154)
Merchandise (155)
Other Materials and Supplies (156)
Nuclear Materials Held for Sale (157)
Allowances (158.1 and 158.
(Less) Noncurrent Portion of Allowances
Stores Expense Undistributed (163)
Gas Stored Underground - Current (164.
Liquefied Natural Gas Stored and Held for Processing (164.164.
Prepayments (165)
Advances for Gas (166-167)
Interest and Dividends Receivable (171)
Rents Receivable (172)
Accrued Utility Revenues (173)
Miscellaneous Current and Accrued Assets (174)
Derivative Instrument Assets (175)
FERC FORM NO.1 (REV. 12-03)Page 110
Name of Respondent
Avista corp.
This Report Is: Date of Report
(1 ) (ZI An Original (Mo, Da, Yr)
(2) A Resubmission 04/30/2004 Dec. 31,
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)Continued)Ref. Balance at
Page No. Beginning of Year(b) (c)
60,322,238
291,138,852
Balance at
End of Year
(d)
39,499,770
169,111 857
Year of Report
2003
Line
No.
Title of Account
(a)
Derivative Instrument Assets - Hedges (176)
TOTAL Current and Accrued Assets (Enter Total of lines 24 thru 53)
DEFERRED DEBITS
Unamortized Debt Expenses (181)
Extraordinary Property Losses (182.1)
Unrecovered Plant and Regulatory Study Costs (182.
Other Regulatory Assets (182.
Prelim. Survey and Investigation Charges (Electric) (183)
Prelim. Sur. and Invest. Charges (Gas) (183.183.
Clearing Accounts (184)
Temporary Facilities (185)
Miscellaneous Deferred Debits (186)
Oaf. Losses from Disposition of Utility PIt. (187)
Research, Devel. and Demonstration Expend. (188)
Unamortized Loss on Reaquired Debt (189)
Accumulated Deferred Income Taxes (190)
Unrecovered Purchased Gas Costs (191)
TOTAL Deferred Debits (Enter Total of lines 56 thru 69)
TOTAL Assets and Other Debits (Enter Total of lines 10,11,12,22,54,70)
--,------ ---"--'---
921,640 20,113,211
230
230
232 248,746,931 239,863,731
12,130,418 12,156,159
416,423 510,244
233 81,406,921 86,083,253
352-353
29,206,28,712,173
234 37,595,304 34,222,386
514 486 15,352 084
443,938,853 438,013,241
616,248,597 645,731,860
FERC FORM NO.1 (REV. 12-03)Page 111
This Report Is: Date of Report
(1) (XI An Original (Mo, Da, Yr)
(2) D A Resubmission 04/30/2004 Dec. 31
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)Ref. Balance at
Page No. Beginning of Year(b) (c)
Name of Respondent
Avista Corp.
Line
No.
Title of Account
(a)
PROPRIETARY CAPITAL
Common Stock Issued (201)
Preferred Stock Issued (204)
Capital Stock Subscribed (202, 205)
Stock Liability for Conversion (203, 206)
Premium on Capital Stock (207)
Other Paid-In Capital (208-211)
Installments Received on Capital Stock (212)
(Less) Discount on Capital Stock (213)
(Less) Capital Stock Expense (214)
Retained Eamings (215, 215.1, 216)
Unappropriated Undistributed Subsidiary Eamings (216.
(Less) Reaquired Capital Stock (217)
Accumulated Other Comprehensive Income (219)
TOTAL Proprietary Capital (Enter Total of lines 2 thru 14)
LONG. TERM DEBT
250-251
250-251
252
252
252
253
252
254
254
118-119
118-119
250-251
122(a)(b)
Year of Report
2003
Balance at
End of Year
(d)
623,091 721
33,250,000
11,927,830
60,386,146
65,750,804
18,809,177
751,741,664
401,300,000
051,442
703,778,874
160,866
103,969,450
626,787 347
10,949,795
854,919
64,022,832
355,089
752,360,214
431,300,000
434,151
689 935,336
994,486
120 675,001
, , ------- -----""'-""-'------"---,--- --'--'--"""""""-""'-'-
621,526
1 ,446,348
50,209,349
52,277,223
36,247,518
18,524 753
533,815
22,522,183
20,307,075
754
20,279,696
440,569
299,994
897 551
659,307
297,421
48,421 782
19,845,113
452,327
241,055
18,484,237
23,665
28,275,414
26 '
Bonds (221)
(Less) Reaquired Bonds (222)
Advances from Associated Companies (223)
Other Long-Term Debt (224)
Unamortized Premium on Long-Term Debt (225)
(Less) Unamortized Discount on Long-Term Debt-Debit (226)
TOTAL Long-Term Debt (Enter Total of lines 17 thru 22)
OTHER NONCURRENT LIABILITIES
Obligations Under Capital Leases - Noncurrent (227)
Accumulated Provision for Property Insurance (228.
Accumulated Provision for Injuries and Damages (228.
Accumulated Provision for Pensions and Benefits (228.
Accumulated Miscellaneous Operating Provisions (228.
Accumulated Provision for Rate Refunds (229)
Asset Retirement Obligations (230)
TOTAL OTHER Noncurrent Liabilities (Enter Total of lines 25 thru 31)
CURRENT AND ACCRUED LIABILITIES
Notes Payable (231)
Accounts Payable (232)
Notes Payable to Associated Companies (233)
Accounts Payable to Associated Companies (234)
Customer Deposits (235)
Taxes Accrued (236)
Interest Accrued (237)
Dividends Declared (238)
Matured Long-Term Debt (239)
Matured Interest (240)
Tax Collections Payable (241)
Miscellaneous Current and Accrued Liabilities (242)
256-257
256-257
256-257
256-257
262-263
FERC FORM NO.1 (REV. 12.Q3)Page 112
This Report Is: Date of Report
(1) An Original (Mo, Da, Yr)
(2) D A Resubmission 04/30/2004 Dec. 31
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITSXContinued)Ref. Balance at Balance at
Page No. Beginning of Year End of Year(b) (c) (d)
Name of Respondent
Avista corp.
Year of Report
2003
,-,-,-,---,---,-"--,, ----,-,,---,--,-
913,115 978,187
266-267 669,576 620,268
269 29,705,406 008,549
278 20,174 502 13,027 706
118,696,571
272-277 480,206,947 513,314,418
535,788,341 566,645,699
616,248.597 645,731,860
Line
No.
Title of Account
(a)
36.057 271
164,753.525
Obligations Under Capital Leases-Current (243)
Derivative Instrument Liabilities (244)
Derivative Instrument Liabilities - Hedges (245)
TOTAL Current & Accrued Liabilities (Enter Total of lines 34 thru 48)
DEFERRED CREDITS
Customer Advances for Construction (252)
Accumulated Deferred Investment Tax Credits (255)
Deferred Gains from Disposition of Utility Plant (256)
Other Deferred Credits (253)
Other Regulatory Liabilities (254)
Unamortized Gain on Reaquired Debt (257)
Accumulated Deferred Income Taxes (281-283)
TOTAL Deferred Credits (Enter Total of lines 51 thru 57)
50,057 633
172,471 919
TOTAL Liab and Other Credits (Enter Total of lines 15,32,49.58)
FERC FORM NO.1 (REV. 12-Q3)Page 113
Name of Respondent This 7!)ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) n A Resubmission 04/30/2004
STATEMENT OF INCOME FOR THE YEAR
1. Report amounts for accounts 412 and 413, Revenue and Expenses from Utility Plant Leased to Others, in another Utility column (i
k, m, 0) in a similar manner to a utility department. Spread the amount(s) over Lines 02 thru 24 as appropriate. Include these amountsin 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 8, 10, and 11 for Natural Gas companies using accounts 404.404.404.407.1 and 407.
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.TOTALNo.Page No.Current Year Previous Year(a)(b)(c)(d)
UTILITY OPERATING INCOME
Operating Revenues (400)300-301 929,400,226 893,963,515
Operating Expenses
Operation Expenses (401)320-323 628 688,576 606,132,796
Maintenance Expenses (402)320-323 30,395,326 23,968,182
Depreciation Expense (403)336-337 65,752,096 60,293,549
Depreciation Expense for Asset Retirement Costs (403.336-337
Amort. & Depl. of Utility Plant (404-405)336-337 151 368 430 074
Amort. of Utility Plant Acq. Adj. (406)336-337 99,048 99,048
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)693 582
Amort. of Conversion Expenses (407)
Regulatory Debits (407.218,244 253,985
(Less) Regulatory Credits (407.10,449,403 17,987,205
Taxes Other Than Income Taxes (408.262-263 60,791,111 63,597 147
Income Taxes - Federal (409.262-263 613,266 34,872,176
- Other (409.262-263 1 ,282 899 348,133
Provision for Deferred Income Taxes (410.234, 272-277 291 ,061 O69,837
(Less) Provision for Deferred Income Taxes-Cr. (411.234, 272-277 678,097 080,399
Investment Tax Credit Adj. - Net (411.266 -49,308 -49,308
(Less) Gains from Disp. of Utility Plant (411.
Losses from Disp. of Utility Plant (411.
(Less) Gains from Disposition of Allowances (411.
Losses from Disposition of Allowances (411.
Accretion Expense (411.10)
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)808,102 494 769,804,759
Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 121 297 732 124 158,756
FERC FORM NO.1 (ED. 12-96)Page 114
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) D A Resubmission 04/30/2004
STATEMENT OF INCOME FOR THE YEAR (Continued)
resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases, and a
summary of the adjustments made to balance sheet, 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 on
pages 122-123.
8. Enter on page 123 a concise explanation of only those changes in accounting methods made during the year which had an effect on
net income, including the basis of allocations and apportionments from those used in the preceding year. Also give the approximate
dollar effect of such changes.
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 26, and
report the information in the blank space on page 123 or in a footnote.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY Line
No.Current Year Previous Year Current Year Previous Year Current Year Previous Year
(e)(f)(9)(h)(i)
652,111 450 584,141,003 277 288,776 309,822,512
406,888,146 353,588,329 221 800,430 252,544,467
25,258,364 19,988,552 136,962 979,630
50,578,273 46,180,880 15,173,823 112,669
790,075 497,026 361,293 933,048
99,048 99,048
693 582
218,244 253,985
10,449,403 987 205
43,903,386 43,185,433 16,887 725 20,411 714
25,776,211 25,158,719 162 945 713,457
972,732 430,132 310,167 918,001
172,553 201,171 118,508 271,008
554,927 997,556 123,170 843
-49,308 -49,308
546,430,765 476,340,947 261 671 729 293,463,812
105,680,685 107 800,056 15,617 047 16,358,700
FERC FORM NO.1 (ED. 12-96)Page 115
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003
(2) LI A Resubmission 04/30/2004
STATEMENT OF INCOME FOR THE YEAR (Continued)
Line OTHER UTILITY OTHER UTILITY OTHER UTILITY
No.Current Year Previous Year Current Year Previous Year Current Year Previous Year
(k)(I)(m)(n)(0)
(p)....'
FERC FORM NO.1 (ED. 12-96)Page 116
Name of Respondent
Avista Corp.
Year of Report
Dec. 31 2003
Line
No.
Account
This f3!1?ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
STATEMENT OF INCOME FOR THE YEAR (Continued)
(Ref.
Page No.
(b)(a)
TOTAL
Current Year
(c)
Previous Year
(d)
27 Net Utility Operating Income (Carried forward from page 114)
28 Other Income and Deductions
29 Other Income
30 Nonutilty Operating Income
31 Revenues From Merchandising, Jobbing and Contract Work (415)
32 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
33 Revenues From Nonutility Operations (417)
34 (Less) Expenses of Nonutility Operations (417.
35 Nonoperating Rental Income (418)
36 Equity in Eamings of Subsidiary Companies (418.
37 Interest and Dividend Income (419)
38 Allowance for Other Funds Used During Construction (419.
39 Miscellaneous Nonoperating Income (421)
40 Gain on Disposition of Property (421.
41 TOTAL Other I ncome (Enter Total of lines 31 thru 40)
42 Other Income Deductions
43 Loss on Disposition of Property (421.
44 Miscellaneous Amortization (425)
45 Miscellaneous Income Deductions (426.1-426.
46 TOTAL Other Income Deductions (Total of lines 43 thru 45)
47 Taxes Applic. to Other Income and Deductions
48 Taxes Other Than Income Taxes (408.
49 Income Taxes-Federal (409.
50 Income Taxes-Other (409.
51 Provision for Deferred Inc. Taxes (410.
52 (Less) Provision for Deferred Income Taxes-Cr. (411.
53 Investment Tax Credit Adj.Net (411.
54 (Less) Investment Tax Credits (420)
55 TOTAL Taxes on Other Income and Deduct. (Total of 48 thru 54)
56 Net Other Income and Deductions (Enter Total lines 41, 46, 55)
57 Interest Charges
58 Interest on Long-Term Debt (427)
59 Amort. of Debt Disc. and Expense (428)
60 Amortization of Loss on Reaquired Debt (428.
61 (Less) Amort. of Premium on Debt-Credit (429)
62 (Less) Amortization of Gain on Reaquired Debt-Credit (429.
63 Interest on Debt to Assoc. Companies (430)
64 Other Interest Expense (431)
65 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)
66 Net Interest Charges (Enter Total of lines 58 thru 65)
67 Income Before Extraordinary Items (Total of lines 27,56 and 66)
68 Extraordinary Items
69 Extraordinary Income (434)
70 (Less) Extraordinary Deductions (435)
71 Net Extraordinary Items (Enter Total of line 69 less line 70)
72 Income Taxes-Federal and Other (409.
73 Extraordinary Items After Taxes (Enter Total of line 71 less line 72)
74 Net Income (Enter Total of lines 67 and 73)
119
340
340
262-263
262-263
262-263
234, 272-277
234, 272-277
340
340
262-263
121,297 732 124 158,756
789
014
130
609,187
-4,377
156,784
12,050,635
853,013
574,461
705,555
361,455
914 750
022
212,474
23,649,106
768,323
922,152
210,724
20,650,420
89,613
20,555 154
68,722
323,416
537,596
929,734
.....,_...,.."..,.....".......".......,
,......."..... """"m""
""""""""'~""
m....'........,_......_...,"
97,503
129,828
-481,773
968,974
66,775
38,000
329,302
-464,555
845,351
-406,167
326,645
762 173
154,265
566,421
82,501,
907,423
064,380
93,113,627
538,126
323,214
320 268
238,014
89,555,653
44,504,252
621,673
178,216
102,418,424
31,306,753
"""'--"""""""-"""""""""""""""'"""", -""-""""""""""..."....
,mm..
, . '.. ,.....
44,504 252 31,306,753
FERC FORM NO.1 (ED. 12-96)Page 117
Name of Respondent
Avista Corp.
Year of Report
Dec. 31, 2003
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
STATEMENT 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.
Ine
No.Item
(a)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Year
2 Changes
3 Adjustments to Retained Eamings (Account 439)
Allocation of Retained Earnings to Series L no longer required
Stock Options Exercised adjustment
6 ESOP and other adjustment
Dividends received from Subsidiaries
9 TOTAL Credits to Retained Earnings (Acct. 439)
15 TOTAL Debits to Retained Earnings (Acct. 439)
16 Balance Transferred from Income (Account 433 less Account 418.
17 Appropriations of Retained Earnings (Acct. 436)
22 TOTAL Appropriations of Retained Eamings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
36 TOTAL Dividends Declared-Cornmon Stock (Acct. 438)
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Year (Total 1 15,16,36.37)
APPROPRIATED RETAINED EARNINGS (Account 215)
64,104 077
144,553
170,109
990,037
54,088 484
35.347 468
......................,_...................................................,.....,'...,.............,.....,...."",..,'.'..,........,..........,
155,438
155,438
23,633,569
23,633,569
894.719
80,306,798
,. ... .,. ",..... ..,.". ...,.,.,.,.,. .. ...... .,.. .. ,.,
FERC FORM NO.1 (ED. 12-96)Page 118
Name of Respondent
Avista Corp.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
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. Followby 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 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.
Year of Report
Dec. 31, 2003
No.Item
(a)(c)
45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS -AMORT. Reserve, Federal (Account 215.1)
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.
47 TOTAL Approp. Retained Eamings (Acct. 215, 215.1) (Total 45,46)
48 TOTAL Retained Eamings (Account 215,215.216) (Total 38, 47)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account 216.
49 Balance-Beginning of Year (Debit or Credit)
50 Equity in Eamings for Year (Credit) (Account 418.1 )
51 (Less) Dividends Received (Debit)
52 Subsidiary expense in Account 417.
53 Balance-End of Year (Total lines 49 thru 52)
548.121
"_..'
~~n_'_n, n ~..'_nn..'- --""'_"__n~"n
.. ..,.., ,...." .. .,..,..., '
548,121
548,121
854,919
65,750,804
156,784
990,037
-894,719
64,022,832
FERC FORM NO.1 (ED. 12-96)Page 119
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31, 2003(2) 0 A Resubmission 04/30/2004
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 Descnption (~ee Instruction NO.5 tor Explanation of l;QQes)Amounts
No.(a)(b)
Net Cash Flow from Operating Activities:
Net Income 504,252
Noncash Charges (Credits) to Income:
Depreciation and Depletion 73,998,819
Power and natural gas deferrals 535 312
Amortization of debt expense 971,803
Amortization of investment in exchange power 450,004
Deferred Income Taxes (Net)791 ,463
Investment Tax Credit Adjustment (Net)-49,308
Net (Increase) Decrease in Receivables 18,650,796
Net (Increase) Decrease in Inventory 94,433
Net (Increase) Decrease in Allowances Inventory
Net Increase (Decrease) in Payables and Accrued Expenses 167,229
Net (Increase) Decrease in Other Regulatory Assets -630,827
Net Increase (Decrease) in Other Regulatory Liabilities 334,617
(Less) Allowance for Other Funds Used During Construction 192,697
(Less) Undistributed Earnings from Subsidiary Companies 156,784
Other current assets 803,240
ESOP dividends 167,506
Allowance for uncollectible receivables -407,128
Other non-current assets and liabilities 849,925
Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)144,510,439
Cash Flows from Investment Activities:
Construction and Acquisition of Plant (including land):
Gross Additions to Utility Plant (less nuclear fuel)105,617,593
Gross Additions to Nuclear Fuel
Gross Additions to Common Utility Plant
Gross Additions to Nonutility Plant 581,511
(Less) Allowance for Other Funds Used During Construction
Other (provide details in footnote):
Other Property and Investments 848,976
Cash Outflows for Plant (Total of lines 26 thru 33)109,048,080
Acquisition of Other Noncurrent Assets (d)
Proceeds from Disposal of Noncurrent Assets (d)482,872
Investments in and Advances to Assoc. and Subsidiary Companies 344,568
Contributions and Advances from Assoc. and Subsidiary Companies
Disposition of Investments in (and Advances to)
Associated and Subsidiary Companies
Dividends from Subsidiary Companies 990,036
Purchase of Investment Securities (a)
Proceeds from Sales of Investment Securities (a)
FERC FORM NO.1 (ED. 12-96)Page 120
Name of Respondent
Avista Corp.
This ~ort Is:(1) ~An Original(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/30/2004
Year of Report
Dec. 31 2003
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.Ine escnp on ee ns c on o. or xp ana on 0
No.(a)(b)
46 Loans Made or Purchased
47 Collections on Loans
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55)
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
70 Cash Provided by Outside Sources (Total 61 thru 69)
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83)
88 Cash and Cash Equivalents at Beginning of Year
90 Cash and Cash Equivalents at End of Year
73,000
775
Net (Increase) Decrease in Receivables
Net (Increase) Decrease in Inventory
Net (Increase) Decrease in Allowances Held for Speculation
Net Increase (Decrease) in Payables and Accrued Expenses
Other (provide details in footnote):
Cash Flows from Financing Activities:
Proceeds from Issuance of:
Long-Term Debt (b)
Preferred Stock
Common Stock
Other (provide details in footnote):
795,250
775,591
50,000,000
98,570,841
---- ,..,....--.... ..,..,..-.."----,----" -,-_..,,- - -.."..,., ,,-, --, ,......---
Payments for Retirement of:
Long-term Debt (b)
Preferred Stock
Common Stock
Other (provide details in footnote):
Premiums paid for the repurchase of long-term debt
Net Decrease in Short-Term Debt (c)
Borrowing issuance costs
Dividends on Preferred Stock
Dividends on Common Stock
Net Cash Provided by (Used in) Financing Activities
(Total of lines 70 thru 81)
124 033,279
574,266
709,769
429,756
155,438
23,633,569
19,584,011
FERC FORM NO.1 (ED. 12-96)Page 121
Name of Respondent
Avista Corp.
Date of Report
04/30/2004
Year of Report
Dec. 31. 2003
This Report Is:(1) An Original(2) D 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 Corm mission 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) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31 , 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTES TO 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 ofenergy as well as other energy-related businesses. A vista Utilities is an operating division of A vista Corp. comprising the regulated
utility operations. A vista Utilities generates, transmits and distributes electricity in parts of eastern Washington and northern Idaho.
A vista Utilities also provides natural gas distribution service in parts of eastern Washington, northern Idaho, northeast and southwest
Oregon and in the South Lake Tahoe region of California. A vista Capital, a wholly owned subsidiary of A vista Corp., is the parent
company of all of the subsidiary companies in the non-utility business segments.
The Company s operations are exposed to risks including, but not limited to, the price and supply of purchased power, fuel and natural
gas, regulatory allowance of power and natural gas costs and capital investments, streamflow and weather conditions, the effects of
changes in legislative and governmental regulations, changes in regulatory requirements, availability of generation facilities
competition, technology and availability of funding. Also, like other utilities, the Company s facilities and operations may be exposed
to terrorism risks or other malicious acts. In addition, the energy business exposes the Company to the fInancial, liquidity, credit and
commodity price risks associated with wholesale purchases and sales.
Basis of Reporting
The fInancial statements include the assets, liabilities, revenues and expenses of the Company. As required by the Federal Energy
Regulatory Commission, the Company accounts for its investment in majority-owned subsidiaries on the equity method rather than
consolidating the assets, liabilities, revenues, and expenses of these subsidiaries, as required by accounting principles generally
accepted in the United States of America. The accompanying fInancial statements include the Company s proportionate share of utility
plant and related operations resulting from its interests injointly owned plants (See Note 7).
Use of Estimates
The preparation of the fmancial statements in confonnity with accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions that affect amounts reported in the fmancial statements. Significant
estimates include determining unbilled revenues, the market value of energy commodity assets and liabilities, pension and other
postretirement benefit plan liabilities, and contingent liabilities. Changes in these estimates and assumptions are considered reasonably
possible and may have a material effect on the fmancial statements and thus actual results could differ from the amounts reported and
disclosed herein.
System of Accounts
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.
Avista Utilities Operating Revenues
Operating revenues for A vista 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
date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded. Accounts receivable
includes unbilled energy revenues of $9.0 million (net of $47.0 million of unbilled receivables sold) and $6.1 million (net of $40.
million ofunbilled receivables sold) as of December 31 2003 and 2002, respectively. See Note 3 for information with respect to the
sale of accounts receivable.
FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmisslon 04/30/2004 Dec 31 , 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
Advertising Expenses
The Company expenses advertising costs as incurred. Advertising expenses totaled $1.4 million, $1.3 million and $1.8 million in
2003 2002 and 2001, 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. Utility related taxes
collected from customers are recorded as both operating revenue and expense and totaled $31.7 million, $33.1 million and $26.
million in 2003 2002 and 2001, respectively.
Other Income-Net
Other income-net consisted of the following items for the years ended December 31 (dollars in thousands):
2003 2002 2001
Interest income 810 716 $19 049
Interest on power and natural gas deferrals 361 597 995
Impairment of non-operating assets 240)
Net gain (loss) on the disposition of assets (334)(33)884
Net gain (loss) on subsidiary investments 207)084 (180)
Minority interest (656)
Other expense 063)(6,570)(10 208)
Other income 606 4.467 4.437
Total
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 2000 return.
The Company accounts for income taxes using the liability method. Under the liability method, a deferred tax asset or liability is
detennined based on the enacted tax rates that will be in effect when the differences between the fmancial 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 SF AS 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.
I FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
If comptmsation expense for the Company s stock option plans were determined consistent with SF AS No. 123, net income and
earnings per common share would have been the following pro forma amounts for the years ended December 31
2003 2002 2001
$44 504 $31 307 $12 156
186 051 801
$0.$0.$0.
$0.$0.$0.15
$0.$0.$0.
$0.$0.$0.15
Net income (dollars in thousands):
As reported
Deduct: Total stock-based employee compensation expense
determined under the fair value method for all awards, net of tax
Pro forma
Basic earnings per common share
As reported
Pro forma
Diluted earnings per common share
As reported
Pro forma
Comprehensive Income
The Company s comprehensive income is comprised of net income and changes in the unfunded accumulated benefit obligation for
the pension plan.
Earnings Per 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 dividing income 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, contingently issuable shares and restricted stock. See Note 21 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.
Allowance for Doubtful Accounts
The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The
Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to
accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual
accounts. The following table documents the activity in the allowance for doubtful accounts during the years ended December
(dollars in thousands):
Allowance as of the beginning of the year
Additions expensed during the year
Net deductions
Allowance as of the end of the year
2003
$46 909
912
.Jbm)
2002
$50 211
469
(6.77 D
2001
$14 404
947
.JU4Q)
Inventory
Inventory consists primarily of materials and supplies, fuel stock and natural gas stored. Inventory is recorded at the lower of cost or
market, primarily using the average cost method.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original ' (Mo, Da, Yr)
Avista Corp.(2)A Resubmisslon 04/30/2004 Dec 31 , 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
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.
Allowance for Funds Used During Construction
The Allowance for Funds Used During Construction (AFUDC) represents the cost of both the debt and equity funds used to fmance
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 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 provision for
depreciation after the related utility plant is placed in service. Cash inflow related to AFUDC generally does not occur until the related
utility plant is placed in service and included in rate base.
The effective AFUDC rate was 9.72 percent for 2003 and the second half of 2002 and 9.03 percent for the fIrst half of 2002 and 2001.
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 provide for 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 2.98 percent in 2003, 2.
percent in 2002 and 2.84 percent in 2001.
The average service lives for the following broad categories of utility property are: electric thermal production - 30 years;hydroelectric production - 77 years; electric transmission - 41 years; electric distribution - 46 years; and natural gas distribution
property - 35 years.
The Company recovers certain asset retirement costs through rates charged to customers as a portion of its depreciation expense. The
Company had estimated retirement costs of $197.7 million and $185.4 million included as a regulatory liability on the Consolidated
Balance Sheet as of December 31, 2003 and 2002, respectively. These costs do not represent legal or contractual obligations.
Regulatory Deferred Charges and Credits
The Company prepares its consolidated fInancial statements in accordance with the provisions of SF AS No. 71
, "
Accounting for the
Effects of Certain Types of Regulation." The Company prepares its fInancial statements in accordance with SF AS 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
fmancial statements. SF AS 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
SF AS 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 the Company expected to recover such costs in the future.
The Company s primary regulatory assets include power and natural gas deferrals (see "Power Cost Deferrals and Recovery
Mechanisms" and "Natural Gas Cost Deferrals and Recovery Mechanisms" 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 further information), regulatory
asset for consolidation of variable interest entity (see Note 2 for further information), demand side management programs
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1 ) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
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):
2003 2002
Regulatory asset for consolidation of variable interest entity
Regulatory asset for postretirement benefit obligation
Demand side management and conservation programs
Other
Total
$16 707
255
683
736
728
23,733
1.274
$29.73~
Regulatory liabilities include utility plant retirement costs. Deferred credits include, among other items, regulatory liabilities created
when the Centralia Power Plant (Centralia) was sold, regulatory liabilities offsetting net energy commodity derivative assets (see Note
4 for further information) and the gain on the general office building sale/leaseback, 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.
Regulatory assets that are not currently included in rate base, being recovered in current rates or earning a return (accruing interest),
totaled $24.3 million as of December 31, 2003. The most significant of these assets was the $16.7 million regulatory asset for the
consolidation of a variable interest entity (WP Funding LP) and $5.3 million of demand side management programs. Avista Utilities
lease payments to WP Funding LP of $4.5 million are being recovered in current rates; the regulatory asset primarily represents the
accumulated difference between depreciation expense on the plant and the principal payments made on the debt obligation (see Note
2), which will be reversed in future periods as debt principal payments are made. The balance of the demand side management
regulatory asset will be reduced through future recoveries from customers that are more than future amounts expended on such
programs.
Investment in 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.year period, related to its investment in WNP-
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 SF AS No. 71. These costs are recovered through retail rates as a component of interest expense.
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 placed responsibility for natural gas procurement operations in 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. A vista 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 A vista Energy to retain a portion of the
benefits associated with asset optimization and the efficiencies gained in purchasing natural gas for A vista Utilities as part of a larger
portfolio. 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
I FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
Benchmark Mechanism and related Agency Agreement through January 29, 2004. In February 2004, the WUTC ordered that the
Natural Gas Benchmark Mechanism and related Agency Agreement be terminated for Washington customers and ordered Avista
Utilities to file a transition plan to move management of these functions back into A vista Utilities.
In accordance with SF AS No. 71, profits recognized by A vista Energy on natural gas sales to A vista Utilities, including gains and
losses on natural gas contracts, are not eliminated in the consolidated fInancial statements. This is due to the fact that A vista Utilities
expects to recover the costs of natural gas purchases to serve retail customers and for fuel for electric generation through future retail
rates.
Power Cost Deferrals and Recovery Mechanisms
A vista Utilities defers the recognition in the income statement of certain power supply costs as approved by the WUTC. Deferredpower 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 A vista Utilitiesand the costs included in base retail rates. This difference in power supply costs primarily results from changes in short-termwholesale 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, of8.5 percent as of December 31 2003. Total deferred power costs for Washington customers were $125.
million and $123.7 million as of December 31 2003 and 2002, respectively.
The WUTC issued an order that became effective July 1 , 2002 for restructuring of rate increases previously approved by the WUTC
totaling 31.2 percent. The July 2002 rate change increased base retail rates 19.3 percent and provided an 11.9 percent continuingsurcharge for the recovery of deferred power costs. The WUTC rate order also established an Energy Recovery Mechanism (ERM)
effective July 1 , 2002. The ERM replaced a series of temporary deferral mechanisms that had been in place in Washington sincemid-2000. The ERM allows A vista Utilities to increase or decrease electric rates periodically with 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 fITst $9.0 million inannual power supply costs above or below the amount included in base retail rates. Under the ERM, 90 percent of annual power supply
costs exceeding or below the initial $9.0 million are deferred for future surcharge or rebate to A vista Utilities' customers. Theremaining 10 percent of power supply costs are an expense of, or benefit to, the Company.
Under the ERM, A vista Utilities makes an annual filing to provide the opportunity for the WUTC and other interested parties to review
the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. Avista Utilities made its first annual
filing with the WUTC in March 2003 related to $18.4 million of deferred power costs incurred for the period July 1, 2002 through
December 31 2002. In January 2004, the WUTC approved a settlement agreement among Avista Utilities, the WUTC staff and the
Industrial Customers of Northwest Utilities, which provided for Avista Utilities to write off $2.5 million (recorded in 2003) of
previously deferred power costs related to the delay of the Coyote Springs 2 project in 2002 and 2003 and allows recovery of all other
deferred power costs incurred through December 31 , 2002.
Avista Utilities has a power cost adjustment (PCA) mechanism in Idaho that allows it to modify electric rates periodically with IPUC
approval. Under the PCA mechanism, A vista Utilities defers 90 percent of the difference between certain actual net power supply
expenses and the authorized level of net power supply expenses approved in the last Idaho general rate case. A vista Utilities accrues
interest on deferred power costs in the Idaho jurisdiction at a rate, which is adjusted annually, of 1.0 percent on current year deferrals
and 3.0 percent on carryover balances as of December 31,2003. The IPUC originally approved a 19.4 percent surcharge in October2001, which has been extended through October 2004 for recovery of previously deferred power costs. Based on IPUC staff
recommendations and IPUC orders, the prudence of $11.9 million of deferred power costs will be reviewed in the electric general rate
case that A vista Utilities filed in February 2004. Total deferred power costs for Idaho customers were $30.3 million and $31.5 million
as of December 31 2003 and 2002, respectively.
Natural Gas Cost Deferrals and Recovery Mechanisms
Under established regulatory practices in each respective state, A vista Utilities is allowed to adjust its natural gas rates periodically
(with regulatory approval) to reflect increases or decreases in the cost of natural gas purchased. Differences between actual natural gascosts and the natural gas costs already included in retail 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 $15.4 million and $11.5 million as of December 31 , 2003
and 2002, respectively.
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmisslon 04/30/2004 Dec 31, 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
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 SF AS No. 143
, "
Accounting for Asset Retirement
Obligations" which addresses fInancial accounting and reporting for legal or contractual obligations associated with the retirement of
tangible long-lived assets 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-lived asset. 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 effect on the Company s fmancial condition or results of
operations.
The Company recovers certain utility plant retirement costs through rates charged to customers as a component of depreciation
expense. To conform to SFAS No. 143, the Company has reclassified $197.7 million and $185.4 million of utility plant retirement
costs previously recorded in accumulated depreciation to regulatory liabilities as of December 31 , 2003 and 2002, respectively. These
costs do not represent legal or contractual obligations.
In June 2002, the FASB issued SF AS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" which nullifies
EITF Issue No. 94-
, "
Liability Recognition for Certain Employee Termination Benefits 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 disposalactivity is recognized when the liability is incurred. Under EITF Issue No. 94-, a liability for an exit cost was recognized at the date
of an entity's commitment to an exit plan. SF AS No. 146 also requires the initial measurement of the liability at fair value. This
statement is effective for exit or disposal activities that were initiated after December 31 , 2002. The adoption of this statement did not
have any effect on the Company s fInancial condition or results of operations.
In December 2002, the FASB issued SF AS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure" which
amends SF AS 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 (see Note 1 "Stock-based Compensation ). 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 fmancial 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 effect on the Company s fmancial condition or results of operations.
In April 2003, the FASB issued SFAS No. 149
, "
Amendment of Statement 133 on Derivative Instruments and Hedging Activities.
This statement amends SFAS No. 133 for decisions made: (1) as part of the Derivatives Implementation Group process that effectively
required amendments to SF AS No. 133; (2) in connection with other FASB projects dealing with fmancial instruments; and (3) in
connection with implementation issues raised in relation to the application of the defInition of a derivative, (in particular, the meaning
of an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar
response to changes in market factors, the meaning of underlying, and the characteristics of a derivative that contain financing
components). This statement is effective for contracts entered into or modified after June 30, 2003, except as stated below and for
hedging relationships designated after June 30, 2003. The provisions of SF AS No. 149 that relate to SF AS No. 133 implementationissues that were effective for fiscal quarters that began prior to June 15, 2003 should continue to be applied in accordance with their
respective effective dates. In addition, certain provisions relating to forward purchases or sales of "when-issued" securities or other
securities that do not yet exist, should be applied to existing contracts as well as new contracts entered into after June 30, 2003. Avista
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent
Avista Corp.
This Report is:
(1) An Original
(2) A Resubmission
NOTES TO FINANCIAL STATEMENTS (Continued)
Date of Report Year of Report
(Mo, Da, Yr)04/30/2004 Dec 31 , 2003
Utilities has entered into certain forward contracts to purchase or sell power and natural gas used for generation that no longer meet the
normal purchases and sales exception in accordance with the provisions of SFAS No. 149. This statement requires that substantially
all new forward contracts to purchase or sell power and natural gas used for generation, which were entered into on or after July 1
2003, be recorded as assets or liabilities at market value with an offsetting regulatory asset or liability as authorized by regulatory
accounting orders (see Note 4). In accordance with the provisions of SF AS No. 149, Avista Utilities recorded derivative assets of$1.5
million and derivative liabilities of$O.1 million as of December 31 2003.
In May 2003, the FASB issued SF AS No. 150
, "
Accounting for Certain Financial Instruments with Characteristics of Both Liabilities
and Equity." This statement requires the Company to classify certain financial instruments as liabilities that have historically been
classified as equity. This statement requires the Company to classify as a liability financial instruments that are subject to mandatory
redemption at a specified or detenninable date or upon an event that is certain to occur. This statement was effective for fmancial
instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the fIrst interim period
beginning after June 15, 2003. The restatement of financial statements for prior periods is not permitted. The adoption of this
statement required the Company to classify $31.5 million of preferred stock subject to mandatory redemption as liabilities on the
Consolidated Balance Sheet. The adoption of this statement also required the Company to classify preferred stock dividends of $1.
million for the period from July 1, 2003 through December 31, 2003 as interest expense in the Consolidated Statements of Income.
The adoption of this statement does not cause the Company to fail to meet any of the covenants of the Company s $245.0 million
committed line of credit, including covenants not to permit the ratio of "consolidated total debt" to "consolidated total capitalization
of A vista Corp. to be greater than 65 percent at the end of any fiscal quarter as the covenant calculations exclude the effect of changes
in accounting standards.
In December 2003, the FASB issued SF AS No. 132 (revised 2003), "Employers' Disclosures about Pensions and Other Postretirement
Benefits." This statement requires expanded disclosures with respect to pension plan assets, benefit obligations, cash flows, benefit
costs and other relevant information. However, this statement does not change the measurement and recognition provisions of
previous F ASB statements related to pensions and other postretirement benefits. The Company was required to adopt this statement
for 2003. The adoption of this statement did not have any effect on the Company s financial condition or results of operations. The
expanded disclosures required by this statement are included in Note 9.
In July 2003, the EITF reached consensus on Issue No. 03-
, "
Reporting Realized Gains and Losses on Derivative Instruments That
Are Subject to FASB Statement No. 133 and Not Held for Trading Purposes as Defmed in EITF Issue No. 02-" This EITF Issue
requires that revenues and resource costs from Avista Utilities' settled energy contracts that are "booked out" (not physically
delivered) should be reported on a net basis as part of operating revenues effective October 1 2003. The adoption of this EITF Issue
resulted in a reduction in operating revenues and resource costs of approximately $1.2 million for 2003 as compared to historical
periods for A vista Utilities. This effect on operating revenues and resource costs will be more significant in 2004 and subsequent years
as the netting of "booked out" contracts will be recorded for the entire year.
In November 2002, the FASB issued Interpretation No. 45, "Guarantor s Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others." This interpretation clarifies the requirements of SF AS 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 did not have a material effect on the
Company s fmancial condition or results of operations. The disclosure requirements of this interpretation are effective for fmancial
statements issued for periods that end after December 15, 2002. See Note 17 for disclosure of the Company s guarantees.
In January 2003, the FASB issued Interpretation No. 46
, "
Consolidation of Variable Interest Entities," which was revised in December
2003 (collectively referred to as FIN 46). In October 2003, the implementation of FIN 46 was delayed from the third quarter of 2003
to the fourth quarter of 2003. In general, a variable interest entity does not have equity investors with voting rights or it has equity
investors that do not provide sufficient fmancial resources for the entity to support its activities. Variable interest entities are
conunonly referred to as special purpose entities or off-balance sheet structures; however, FIN 46 applies to a broader group of
entities. FIN 46 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'
residual returns. FIN 46 also requires disclosure of variable interest entities that a company is not required to consolidate but in which
IFERC FORM NO.(ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1)An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
it has a significant variable interest. The consolidation requirements of FIN 46 applied immediately to variable interest entities created
after January 31 , 2003 and applied to certain existing variable interest entities for the fust fiscal year or interim period ending after
December 15 2003. Application for all other types of entities is required for periods ending after March 15 2004.
FIN 46 required the Company to consolidate WP Funding LP effective for the period ended December 31 , 2003. WP Funding LP isan entity that was formed in 1993 for the purpose of acquiring the natural gas-fued combustion turbine generating facility in Rathdrum,
Idaho (Rathdrum CT). WP Funding LP purchased the Rathdrum CT from the Company with funds provided by unrelated investors
which 97 percent represented debt and 3 percent represented equity. The Company operates the Rathdrum CT and leases it from WP
Funding LP. The total amount of WP Funding LP debt outstanding was $54.6 million as of December 31 , 2003. The lease termexpires in February 2020; however, the current debt matures in October 2005 and will need to be refinanced at that time. As of
December 31 2003, the book value of the debt and equity ofWP Funding LP exceeded the book value of the Rathdnun CT by $16.
million. In accordance with regulatory accounting practices, the Company recorded this amount as a regulatory asset upon theconsolidation of WP Funding LP. The addition of the Rathdrum CT to A vista Utilities' generation resource base , which entered
commercial operation in 1995, was reviewed in previous state regulatory filings with the WUTC and IPUC. The consolidation ofWPFunding LP increased long-tenn debt by $54.6 million, net utility property by $39.6 million, other regulatory assets by $16.7 millionand other liabilities by $1.7 million (representing minority interest) as of December 31, 2003.
FIN 46 also resulted in the Company no longer including A vista Capital I and A vista Capital II in its consolidated financial statements
for the period ended December 31 , 2003. A vista Capital I and A vista Capital II are business trusts fonned in 1997 for the purpose of
issuing a combined $110.0 million of preferred trust securities to third parties and $3.4 million of common trust securities to A vista
Corp. The sole assets of A vista Capital I and A vista Capital II are $113.4 million of junior subordinated deferrable interest debentures
of Avista Corp. Avista Capital I and Avista Capital II are considered variable interest entities under the provisions of FIN 46.
Avista COlp. is not the primary beneficiary, these entities are no longer included in Avista Corp.s consolidated financial statements.
The removal of A vista Capital I and A vista Capital II resulted in a decrease in preferred trust securities of $100.0 million, an increasein long-term debt to affiliated trusts of $113.4 million and an increase in investments in affiliated trusts of $13.4 million (representing
the $3.4 million of common trust securities and $10.0 million of preferred trust securities purchased by Avista Corp. in 2000) as
December 31 2003. Interest expense to affiliated trusts of$I.5 million in the Consolidated Statements of Income for 2003 represents
interest expense on the $113.4 million of long-term debt to affiliated trusts for the fourth quarter of2003.
The adoption FIN 46 does not cause the Company to fail to meet any of the covenants of the Company s $245.0 million committed
line of credit, including covenants not to permit the ratio of "consolidated total debt" to "consolidated total capitalization" of A vistaCorp. to be greater than 65 percent at the end of any fiscal quarter as the covenant calculations exclude the effect of changes inaccounting standards.
NOTE 3. ACCOUNTS RECEIVABLE SALE
In 1997, Avista Receivables Corp. (ARC) was fonned 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 fmancial institution entered into a three-year agreement whereby ARC can sell without
recourse, on a revolving basis, up to $100.0 million of those receivables. ARC is obligated to pay fees that approximate thepurchasers 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, 2003 and 2002, $72.0 million and $65.0 million,
respectively, in accounts receivables were sold under this revolving agreement.
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, includingcertain derivative instruments embedded in other contracts, and for hedging activities. It requires the recording of all derivatives aseither assets or liabilities on the balance sheet measured at estimated fair value and the recognition of the unrealized gains and losses.
In certain defined conditions, a derivative may 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.
FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31, 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
Avista Utilities enters into forward contracts to purchase or sell energy. Under these forward contracts, Avista Utilities commits topurchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. Certain of these forwardcontracts are considered derivative instruments. A vista 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 as
part of Avista Utilities' management of its loads and resources as discussed in Note 5. In conjunction with the issuance of SF AS No.
133, the WUTC and the IPUC issued accounting orders authorizing 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 A vista Utilities to not recognize the unrealized
gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses arerecognized in the period of settlement subject to current or future recovery in retail rates. Realized gains and losses are reflected as
adjustments through purchased gas cost adjustments, the ERM and the PCA mechanism.
Prior to the adoption of SF AS No. 149 on July 1, 2003, Avista Utilities elected the normal purchases and sales exception for
substantially all of its contracts for both capacity and energy under SFAS No. 133. As such, Avista Utilities was not required to
record these contracts as derivative commodity assets and liabilities. See Note 2 for a discussion of prospective changes that impact
the accounting for contracts when entered on or after July 1 , 2003, in accordance with SFAS No. 149. Contracts that are not
considered derivatives under SF AS No. 133 are generally accounted for at cost until they are settled or realized, unless there is a
decline in the fair value of the contract that is determined to be other than temporary.
As of December 31 , 2003, the utility derivative commodity asset balance was $39.5 million, the derivative commodity liability
balance was $36.1 million and the offsetting net regulatory liability was $3.4 million. As of December 31, 2002, the utility derivativecommodity asset balance was $60.3 million, the derivative commodity liability balance was $50.1 million and the offsetting netregulatory liability was $10.2 million. Utility derivative assets 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 offsetting net regulatory liability is included in other non-current liabilities and deferred credits on the
Consolidated Balance Sheet.
NOTE S. ENERGY COMMODITY TRADING
The Company s energy-related businesses are exposed to risks relating to, but not limited to, changes in certain conunodity prices
interest rates, foreign currency and counterparty performance. In order to manage the various risks relating to these exposures, A vista
Utilities utilizes derivative instruments, such as forwards, futures, swaps and options, and A vista Energy engages in the trading of such
instruments. A vista Utilities and A vista Energy use a variety of techniques to manage risks for their energy resources and wholesale
energy market activities. The Company has risk management policies and procedures to manage these risks, both qualitative andquantitative, for Avista Utilities and Avista Energy. The Company s Risk Management Committee, which is separate from the units
tasked with managing this risk exposure and is overseen by the Audit Committee of the Company s Board of Directors, monitors
compliance with the Company s risk management policies and procedures.
Avista Utilities
A vista Utilities engages in an ongoing process of resource optimization, which involves the pursuit of economic resources to serve load
obligations and using existing resources to capture available economic value. A vista Utilities sells and purchases wholesale electric
capacity and energy to and from utilities and other entities as part of the process of acquiring resources to serve its retail and wholesale
load obligations. These transactions range from a term as short as one hour up to long-term contracts that extend beyond one year.
A vista 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.
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31,2003
NOTES TO FINANCIAL STATEMENTS (Continued)
the basis of these continuing projections, A vista Utilities makes purchases and sales of energy on an annual, quarterly, monthly, daily
and hourly basis to match expected resources to expected energy requirements. Resource optimization also includes transactions such
as purchasing fuel to run thermal generation and, when economic, selling fuel and substituting wholesale market purchases for the
operation of A vista Utilities' own resources , as well as other wholesale transactions to capture the value of available generation and
transmission resources. This optimization process includes entering into fmancial and physical hedging transactions as a means of
managing risks.
A vista 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 load/resourceimbalances within a rolling IS-month planning horizon are managed within risk policy volumetric limits. Management also assesses
available resource decisions and actions that are appropriate for longer-term planning periods. A vista Energy is responsible for the
daily management of natural gas supplies to meet the requirements of Avista Utilities' customers in the states of Washington, Idahoand Oregon. In February 2004, the WUTC ordered that the Natural Gas Benchmark Mechanism and related Agency Agreement be
terminated for Washington customers (see description of Natural Gas Benchmark Mechanism in Note I). 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.
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.
A vista Utilities and A vista Energy manage, on a portfolio basis and on a delivery point basis, the market risks inherent in their
activities subject to parameters established by the Company s Risk Management Committee. These parameters include but are not
limited to overall portfolio and delivery point volumetric limits. 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. A vista Energy measures the risk in its portfolio on a daily basis
utilizing a V AR 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 bycounterparties of their contractual obligations to deliver energy and make fmancial settlements. Credit risk includes the risk that a
counterparty may default due to circumstances relating directly to it and 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 fmancial 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 the ability of Avista Utilities and Avista Energy toperform deliveries and settlement of energy transactions. These counterparties may seek assurance of perfonnance in the form of
letters of credit, prepayment or cash deposits and, in the case of Avista Energy, parent company (Avista Capital) perfonnance
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.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
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, changes in regulatory requirements
forced outages at generating plants and disruptions to infonnation systems and other administrative tools required for nonnal
operations. A vista Utilities also has exposure to weather conditions and natural disasters that can cause physical damage to property,
requiring repairs to restore utility service. The emergence of terrorism threats, both domestic and foreign, is a risk to the entire utility
industry, including A vista Utilities. Potential disruptions to operations or destruction of facilities from terrorism or other malicious
acts are not readily determinable. The Company has taken various steps to mitigate terrorism risks and to prepare contingency plans inthe event that its facilities are targeted.
NOTE 6. CASH DEPOSITS WITH AND FROM COUNTERP ARTIES
Cash deposits from counterparties totaled $97.8 million and $92.7 million as of December 31, 2003 and 2002, respectively, and are
disclosed as deposits from counterparties on the Consolidated Balance Sheet. These funds are held by A vista Utilities and A vistaEnergy 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 non-cash collateral.
Cash deposited with counterparties totaled $36.8 million and $35.7 million as of December 31, 2003 and 2002, respectively, and isincluded in prepayments and other current assets on the Consolidated Balance Sheet.
As is common industry practice, A vista Utilities and A vista Energy maintain margin agreements with certain counterparties. Margincalls are triggered when exposures exceed predetermined contractual limits or when there are changes in a counterparty'creditworthiness. 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 perfonnance guarantees is a common industry practice.
NOTE 7. JOINTLY OWNED ELECTRIC FACILITIES
The Company has a SO percent ownership interest in a combined cycle natural gas-fired turbine power plant, the Coyote Springs 2Generation Plant (Coyote Springs 2) located in north-central Oregon, which was placed into operation in 2003. The Companyinvestment in Coyote Springs 2 was held by A vista Power as of December 31 , 2002 and was included in non-utility properties andinvestments-net on the Consolidated Balance Sheet. In January 2003, the Company s ownership interest in the plant was transferred
from A vista Power to A vista Corp. to be operated as an asset of A vista Utilities and was included in utility plant in service on the
Consolidated Balance Sheet as of December 31 , 2003. The Company's share of related fuel costs as well as operating and maintenance
expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. The Companyshare of utility plant in service for Coyote Springs 2 was $109.0 million and accumulated depreciation was $2.2 million as of
December 31, 2003.
The Company has a IS 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 ofrelated fuel costs as well as operating and maintenance expenses for plant in service are included in the corresponding accounts in the
Consolidated Statements of Income. The Company s share of utility plant in service for Colstrip was $323.6 million and accumulateddepreciation was $167.6 million as of December 31, 2003.
I FERC FORM NO.1 (ED. 12-88 Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo. Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
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):
2003 2002
Avista Utilities:
Electric production
Electric transmission
Electric distribution
Construction work-in-progress (CWIP) and other
Electric total
Natural gas underground storage
Natural gas d~tribution
CWIP and other
Natural gas total
Common plant (including CWIP)
Total Avista Utilities
Energy Marketing and Resource Management
A vista Advantage
Other
$ 914 021
304 827
724 054
119.552
062.454
543
449 501
45.340
513.384
79.789
655,627
162
847
23.886
~2. 722.522Total
$ 740 736
295 284
698 757
85.631
820.408
285
430 273
44.675
493.233
74.751
388 392
142 428
10,183
20.611
Equipment under capital leases at Avista Utilities totaled $3.9 million and $0.7 million as of December 31, 2003 and 2002
respectively. The associated accumulated depreciation totaled $0.2 million and $0.1 million as of December 31, 2003 and 2002
respectively.
NOTE 9. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a deemed benefit pension plan covering substantially all of its regular full-time employees. Employees of A vista
Energy 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 funding policy 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 that are
currently deductible for income tax purposes. The Company made $12 million in cash contributions to the pension plan in each
2003 and 2002. The Company expects to contribute approximately $15 million to the pension plan in 2004.
Pension fund assets are invested primarily in marketable debt and equity securities. However, fund assets may also be invested in real
estate and other investments, including hedge funds and venture capital funds. In selecting an assumed long-term rate of return on plan
assets, the Company considered past performance and economic forecasts for the types of investments held by the plan. The fair value
of pension plan assets invested in debt and equity securities was based primarily on outside market prices. The fair value of pension
plan assets invested in real estate was determined based on three basic approaches: (1) current cost of reproducing a property less
deterioration and functional economic obsolescence (2) capitalization of the property's net earnings power; and (3) value indicated by
recent sales of comparable properties in the market. The fair value of plan assets was determined as of December 31 2003 and 2002.
As of December 31 2003 and 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 2003, the pension plan funding deficit was reduced as compared to the end of 2002
and as such the Company reduced the additional minimum liability for the unfunded accumulated benefit obligation by $15.5 million
and the intangible asset by $0.6 million (representing the amount of unrecognized prior service cost) related to the pension plan. This
resulted in an increase to other comprehensive income of $9.7 million, net of taxes of $5.2 million for 2003. In 2002, the Company
recorded an additional minimum liability for the unfunded accumulated benefit obligation of $33.4 million and an intangible asset
$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 for 2002.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Me, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (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 provide benefits 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. The Company recorded an additional minimum liability for the unfunded accumulated benefit obligation of $0.3
million, $0.7 million and $1.1 million related to the SERP for 2003,2002 and 2001 , respectively. This resulted in a charge to other
comprehensive income of$0.2 million, $0.5 million and $0.7 million, net of taxes, for 2003 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 Companyelected to amortize the transition obligation of$34.5 million over a period of twenty years, beginning in 1993.
The Company uses a December 31 measurement date for its pension and postretirement plans. The following table sets forth the
pension and postretirement plan disclosures as of December 31 , 2003 and 2002 and the components of net periodic benefit costs for
the years ended December 31 2003 2002 and 2001 (dollars in thousands):
Post-
Pension Benefits Retirement Benefits
2003 2002 2003 2002
$238 385 $210 510 $29 062 $36 355
806 734 482 304
705 119 477 184
530)821)
18,046 243 973 (660)
(12 648)(12 229)741)(3,091)
-LUQi)-1.Lilll (209)
$136 125 $153,705 $11 301 $13,969
33,129 (16 677)282 451)
000 000 785
(11 788)(11 441)713)008)
-LUQi)(20.21
11 67.962 UUQl
$(97 828)$( 1 02 260)$(24 598)$(17 761)
695 812 455 425
712 366
67 809 788
(22 006)(18 753)(6,334)548)aMill 01)
$210 049 $190 181
$26 073 $21 582
427 $3,297
685 183
Change in benefit obligation:
Benefit obligation as of beginning of year
Service cost
Interest cost
Plan amendment
i\cbliuialloss (gain)
Benefits paid
Expenses paid
Benefit obligation as of end of year
Change in plan assets:
Fair value of plan assets as of beginning of year
Actual return on plan assets
Employer contributions
Benefits paid
Expenses paid
Fair value of plan assets as of end of year
Funded status
Unrecognized net actuarial loss
Unrecognized prior service cost
Unrecognized net transition obligation/(asset)
Accrued benefit cost
Additional minimum liability
Accrued benefit liability
Accumulated pension benefit obligation
Accumulated postretirement benefit obligation:
For retirees
For fully eligible employees
For other participants
I FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
Pension Benefits2003 2002
Post-
Retirement Benefits2003 2002
Weighted-average asset allocations as of December Equity securities 64 %Debt securities 25%Real estate Other
Target asset allocations as of December
Equity securities
Debt securities
Real estate
Other
Assumptions as of December 31Discount rate
Expected long-term return on plan assets
Rate of compensation increase
Medical cost trend pre-age 65 - initial
Medical cost trend pre-age 65 - ultimate
Ultimate medical cost trend year pre-age 65
Medical cost trend post-age 65 - initial
Medical cost trend post-age 65 - ultimate
Ultimate medical cost trend year post-age 65
54-68%
22-28%
13%
25%
00%
00%
65%
32%
59%
41%
51%
38%
11%
58-72%
25-35%
75%
00%
00%
25%75%
00%00%
00%00%
00%00%
2007 2007
10.00%10.00%
00%00%
2007 2007
2003 2002 2001 2003 2002 2001
Components of net periodic benefit cost:
Service cost $ 7 806 $ 6 734 716 $ 482 304 $ 460
Interest cost 705 15,119 293 477 184 567
Expected return on plan assets (10 862)(12 311)(15 254)(842)(1,064)311)
Transition (asset)/ obligation recognition 086)086)086)979 256 534
Amortization of prior service cost 653 831 989
Net (gain) loss recognition 896 021 139 405 52)
Net periodic benefit cost
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 2003 by $3.0 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, 2003 by $2.6 million and the service and interest cost by $0.2 million.
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (2003 Medicare Act) was signed
into law. The 2003 Medicare Act expanded Medicare to include, for the first time, coverage for prescription drugs. The Company
expects that the 2003 Medicare Act may eventually reduce the costs of postretirement medical benefits. Because of various
uncertainties related to the Company s response to the 2003 Medicare Act and the appropriate accounting for this event, the Company
has elected to defer fmancial recognition of this legislation until the F ASB issues final accounting guidance.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmisslon 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
The Company has a salary deferral 401(k) plan (Employee Investment Plan) that is a defmed contribution plan and covers
substantially all employees. Employees can make contributions to their respective accounts in the Employee Investment 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 Employee Investment Plan. Employer matching contributions of $3.6 million, $3.4 million and $3.
million were expensed in 2003,2002 and 2001 , respectively.
NOTE 10. ACCOUNTING FOR INCOME TAXES
As of December 31, 2003 and 2002, the Company had net regulatory assets of $131.8 million and $139.1 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 fmancial reporting purposes and the
amounts used for income tax purposes and tax credit carryforwards.
The total net deferred income tax liability consisted of the following as of December 31 (dollars in thousands):
2003 2002
$ 16 201 $ 16 343
669 15,750
677 709
904 112
336 954
645 736
705 172
137 776
404 017 364 827
58,912 58,081
27,290 231
725 533
459 064
8,405 781
673 4.406
547.481 519.923
Deferred income tax assets:
Allowance for doubtful accounts
Reserves not currently deductible
Contributions in aid of construction
Deferred compensation
Centralia sale regulatory liability
Unfunded accumulated benefit obligation
Other
Total deferred income tax assets
Deferred income tax liabilities:
Differences between book and tax basis of utility plant
Power and natural gas deferrals
Umealized energy conunodity gains
Power exchange contract
Demand side management programs
Loss on reacquired debt
Other
Total deferred income tax liabilities
Net deferred income tax liability
Net current deferred income taxes were an $11.5 million asset and a $1.7 million liability as of December 31 , 2003 and 2002,
respectively. Net non-current deferred tax liabilities were $492.8 million and $452.5 million as of December 31 , 2003 and 2002
respectively.
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.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
A reconciliation of federal income taxes derived from statutory federal tax rates (35 percent in 2003 2002 and 2001) applied to pre-tax
income from continuing operations as set forth in the accompanying Consolidated Statements of Income is as follows for the years
ended December 31 (dollars in thousands):
2003 2002 2001
Federal income taxes at statutory rates $30 094 $26 958 $38,089
Increase (decrease) in tax resulting from:
Accelerated tax depreciation 046 166 849
State income tax expense 283 348 (8,870)
Prior year audit adjustments 457 (395)
Other-net 377 912
Total income tax expense
Income Tax Expense Consisted of the Following:
Federal taxes currently provided $ 6 945 $75 136 $(38 556)
Deferred federal income taxes 395 79.141
Total income tax expense
Income Tax Expense by Business Segment:
Avista Utilities $26 884 $32 137 $20 177
Energy Marketing and Resource Management 457 311 489
A vista Advantage (718)289)778)
Other .Jbllil -1Lllill (6.303)
Total income tax expense
NOTE 11. ENERGY PURCHASE CONTRACTS
Avista Utilities has contracts related to the purchase of fuel for thermal generation, natural gas and hydroelectric power. Thetermination dates of the contracts range from one month to the year 2044. Avista Utilities 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, which are included in resource costs in
the Consolidated Statements of Income, were $464.1 million, $382.4 million and $1 054.2 million in 2003, 2002 and 2001
respectively.
The following table details future contractual commitments for power resources (including transmission contracts) and natural gas
resources (including transportation contracts) (dollars in thousands):
2004
Power resources $156 729
Natural gas resources 183.207Total
2005
$ 90 379
76.593
1166.972
2006
$ 90 124
49.375
2007
$ 92 203
49.872
2008
$ 91 788
43.421
Th~eafter Total
$439 079 $ 960 302
355.856 758.324
All of the energy purchase contracts were entered into as part of A vista 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, A vista Utilities has operational agreements, settlements and other contractual obligations with respect to its generation
transmission and distribution facilities. The expenses associated with these agreements are reflected as operations and maintenance
expenses in the Consolidated Statements of Income. The following table details future contractual commitments with respect to these
agreements (dollars in thousands):
Contractual obligations
2004 2005
$lMJ 7
2006 2007
$.JM.,17
2008
Wa:4J 7
Thereafter Total$~5.955
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Me, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31,2003
NOTES TO FINANCIAL STATEMENTS (Continued)
Avista Utilities has fIXed contracts with certain Public Utility Districts (PUD) to purchase portions of the output of certain generating
facilities. Although A vista Utilities has no investment in the PUD generating facilities, the fIXed contracts obligate A vista Utilities 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. Expenses under these PUD contracts were $8.5 million, $7.8 million and $7.4 million in
2003 2002 and 2001 , respectively.
Information as of December 31 , 2003, pertaining to these PUD contracts is summarized in the following table (dollars in thousands):
any s Current Share of
Debt Expira-
Kilowatt Annual Service Bonds tion
Costs (D Costs (t)Outstanqing ate
Chelan County PUD:
Rocky Reach Project 000 222 405 $ 3 441 2011
Douglas County PUD:
Wells Project 000 168 550 966 2018
Grant County PUD:
Priest Rapids Project 000 992 798 265 2040
Wanapum Project 75.000 139 1.587 290 2040
Totals w.4Q
(1) The annual costs will change in proportion to the percentage of output allocated to Avista Utilities in a particular year. Amounts
represent the operating costs for the year 2003. Debt service costs are included in annual costs.
The estimated aggregate amounts of required minimum payments (A vista Utilities' share of existing debt service costs) under these
PUD contracts are as follows (dollars in thousands):
Minimum payments
2004 2005
tM65
2006$~5 2007 2008
W72
Thereafter
$22.75~
Total
In addition, A vista Utilities will be required to pay its proportionate share of the variable operating expenses of these projects.
I FERC FORM NO.1 (ED. 12-88)ge 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmisslon 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTE 12. LONG-TERM DEBT
The following details the interest rate and maturity dates of long-tenD debt outstanding as of December 31 (dollars in thousands):
Maturity Interest
Year Description Rate 2003 2002
2003 Secured Medium- Tenn Notes 25%$ 15,000
2005 Secured Medium- Tenn Notes 6.39%-68%500 500
2005 WP Funding LP Note 36%572 (1)
2006 Secured Medium- Tenn Notes 89%-90%000 000
2007 First Mortgage Bonds 75%150 000 150 000
2008 Secured Medium- Tenn Notes 89%-95%000 000
2010 Secured Medium- Tenn Notes 67%-90%000 000
2012 Secured Medium- Tenn Notes 37%000 000
2013 First Mortgage Bonds 13%000
2018 Secured Medium- Tenn Notes 26%-7.45%500 500
2023 Secured Medium- Tenn Notes 18%-54%500 24.500
Total secured long-tenD debt 398 072 313.500
2003 Unsecured Medium- Tenn Notes 75%-13%250
2004 Unsecured Medium- Tenn Notes 7.42%500 000
2006 Unsecured Medium- Tenn Notes 14%000 0002007Unsecured Medium- Tenn Notes 99%-94%25,850 000
2008 Senior Notes 75%317 683 341 529
2008 Unsecured Medium-Tenn Notes 06%000 000
2010 Unsecured Medium- Tenn Notes 02%000 000
2012 Unsecured Medium- Tenn Notes 05%000
2022 Unsecured Medium- Tenn Notes 15%-23%000 000
2023 Unsecured Medium- Tenn Notes 99%000 000
2023 Pollution Control Bonds 00%100 100
2028 Unsecured Medium- Tenn Notes 37%-88%000 000
2032 Pollution Control Bonds 00%66,700 700
2034 Pollution Control Bonds 13%000 17.000
Total unsecured long-tenD debt 552 833 661.579
Capital lease obligations 812 1.613
Unamortized debt discount --1.Lm) ..nJM)Total 954 723 974 531
Current portion of long-tenD debt
Totallong-tenn debt
(1)As discussed in Note 2, represents the long-tenD debt ofWP Funding LP, an entity that was consolidated in 2003 under
FIN 46.
The following table details future long-tenD debt maturities, including long-tenD debt to affiliated trusts (see Note 13) (dollars in
thousands) :
Year
Debt maturities
In addition to the required maturities documented in the table above, the Company has sinking fund requirements of $3.4 million in
each of 2004 and 2005, $3.1 million in 2006, $2.8 million in 2007 and $1.3 million in 2008. 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.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
In September 2003, the Company issued $45.0 million of6.125 percent First Mortgage Bonds due in 2013. The proceeds were used to
repay a portion of the borrowings under the $245.0 million line of credit that were used on an interim basis to fund $46.0 million of
maturing 9.125 percent Unsecured Medium-Term Notes.
In September 1999, $83.7 million of Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip 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 1999 A and 5.
percent for Series 1999B.
The following table details the Company s debt repurchases prior to scheduled maturity during 2003 (dollars in thousands):
RepurchaseDate Descri tion
January 2003 Unsecured Senior Notes
February 2003 Unsecured Senior Notes
March 2003 Unsecured Medium-Term Notes
April 2003 Unsecured Medium-Term Notes
May 2003 Unsecured Medium-Term NotesJune 2003 Unsecured Medium-Term NotesJuly 2003 Unsecured Medium-Term NotesJuly 2003 Unsecured Senior Notes
August 2003 Unsecured Senior Notes
Total debt repurchases
Interest
Rate
75%
75%
23%
88%
99%
7.42%
05%
75%
75%
Maturity
Year
2008
2008
2022
2028
2007
2004
2012
2008
2008
Principal
Amount
$10,000
505
000
000
150
500
000
000
10.330
In accordance with regulatory accounting practices, the total net premium on the repurchase of debt of $1.7 million will be amortized
over the average remaining maturity of outstanding debt.
As of December 31, 2003, the Company had remaining authorization to issue up to $176.0 million of Unsecured Medium-Term Notes.
The Company also has $105.0 million of either secured or unsecured debt remaining under a registration statement filed on Form S-
with the Securities and Exchange Commission in June 2003.
The Mortgage and Deed of Trust securing the Company s First Mortgage Bonds contains limitations on the amount of First Mortgage
Bonds, which may be issued based on, among other things, a 70 percent debt-to-collateral ratio, and/or retired First Mortgage Bonds,
and a 2.00 to 1 net earnings to First Mortgage Bond interest ratio. Under various fInancing agreements, the Company is also restricted
as to the amount of additional First Mortgage Bonds that it can issue. As of December 31, 2003, the Company could issue $93.
million of additional First Mortgage Bonds under the most restrictive of these fmancing agreements.
NOTE 13. LONG-TERM DEBT TO AFFILIATED TRUSTS
In 1997, the Company issued 7.875 percent Junior Subordinated Deferrable Interest Debentures, Series A, with a principal amount of
$61.9 million to Avista Capital I, a business trust. Avista Capital I issued $60.0 million of Preferred Trust Securities with an annual
distribution rate of7.875 percent. Concurrent with the issuance of the Preferred Trust Securities, Avista Capital I issued $1.9 million
of Common Trust Securities to the Company. These debt securities may be redeemed at the option of Avista Capital I on or after
January 15, 2002 and mature January 15, 2037; however, this is limited by an agreement under the Company s 9.75 percent Senior
Notes that mature in 2008.
In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of
$51.5 million to Avista Capital II, a business trust. Avista Capital II issued $50.0 million of Preferred Trust Securities with a floating
distribution rate of LffiOR plus 0.875 percent, calculated and reset quarterly. The annual distribution rate paid during 2003 ranged
from 2.02 percent to 2.30 percent. As of December 31, 2003, the annual distribution rate was 2.02 percent. Concurrent with the
issuance of the Preferred Trust Securities, A vista Capital II issued $1.5 million of Common Trust Securities to the Company. These
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
debt securities may be redeemed at the option of Avista Capital II on or after June 1 , 2007 and mature June 1 2037; however, this islimited by an agreement under the Company s 9.75 percent Senior Notes that mature in 2008. 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 with respect to, the
Preferred Trust Securities to the extent that A vista Capital I and A vista 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. As discussed in Note 2, FIN 46 results in the Company no longer including A vista Capital I and A vista Capital II in its
consolidated fmancial statements as of December 31 2003.
NOTE 14. SHORT-TERM BORROWINGS
On May 13, 2003, the Company amended its committed line of credit with various banks to increase the amount to $245.0 million
from $225.0 million and extend the expiration date to May 11 2004. The Company can request the issuance of up to $75.0 million in
letters of credit under the amended committed line of credit. As of December 31 , 2003 and 2002, the Company had $80.0 million and
$30.0 million, respectively, of borrowings outstanding under this committed line of credit. As of December 31 2003 and 2002, there
were $10.7 million and $14.3 million in letters of credit outstanding, respectively. The committed line of credit is secured by $245.
million of non-transferable fIrst mortgage bonds of the Company issued to the agent bank. Such fIrst mortgage bonds would only
become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed
line of credit.
The committed line of credit agreement contains customary covenants and default provisions, including covenants not to pennit theratio of "consolidated total debt" (not including preferred stock, long-term debt to affiliated trusts or WP Funding LP 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
2003, the Company was in compliance with this covenant with a ratio of 52.6 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 A vista Utilities
for the twelve-month period ending December 31, 2003 to be greater than 1.6 to 1. As of December 31 , 2003, the Company was incompliance with this covenant with a ratio of 2.3 to 1. The covenant calculations exclude the effect of changes in accounting
standards.
The Company had a commercial paper program that also provided for fiXed-term loans during 2001. None of these arrangements were
in place as of December 31 , 2003 and 2002.
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):
2003 2002 2001
000 000 55,000
$ 11 160
000 000 223 000
558
304 027 108 996
80%
5.42
Balance outstanding at end of period:
Commercial paper
Revolving credit agreement
Maximum balance outstanding during the period:
Commercial paper
Revolving credit agreement
Average balance outstanding during the period:
Commercial paper
Revolving credit agreement
Average interest rate during the period:
Commercial paper
Revolving credit agreement
Average interest rate at end of period:
Commercial paper
Revolving credit agreement
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTE IS. INTEREST RATE SWAP AGREEMENTS
On May 7, 2003, Avista Corp. terminated an interest rate swap agreement that was entered into on July 17, 2002. This interest rateswap agreement effectively changed the interest rate on $25 million of Unsecured Senior Notes from a fIXed rate of 9.75 percent to a
variable rate based on LffiOR. With the termination of the interest rate swap agreement, Avista Corp. received $1.5 million, whichwas recorded as a deferred credit (as part of long-term debt) and will be amortized over the remaining term of the original agreement
(through June 1 2008).
NOTE 16. LEASES
The Company has multiple lease arrangements involving various assets, with minimum terms ranging from one to twenty-five years,
The Company s most significant leased asset is the corporate office building. Certain lease arrangements require the Company, upon
the occurrence of specified events, to purchase the leased assets. The Company s management believes the likelihood of 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 2003 2002 and 2001 was $14.2 million, $21.7 million and $19.8 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 2003 were as follows (dollars in thousands):
Year ending December 31
Minimum payments required
The payments under the Avista Corp. capital leases are $0.8 million in each of 2004, 2005 and 2006, $0.7 million in 2007 and $0.
million in 2008.
NOTE 17. GUARANTEES
The Company has guaranteed the payment of distributions on, and redemption price and liquidation amount with respect to, the
Preferred Trust Securities issued by its affiliates, A vista Capital I and A vista Capital II, to the extent that these entities have fundsavailable for such payments from the respective debt securities.
Avista Power, through its equity investment in RP LLC, is a 49 percent owner of the Lancaster Project, which connnenced commercial
operation in September 2001. Commencing with connnercial operations, all of the output from the Lancaster Project is contracted to
A vista Energy through 2026 years under a Power Purchase Agreement. A vista Corp. has guaranteed the Power Purchase Agreement
with respect to the performance of Avista Energy.
NOTE 18. PREFERRED STOCK-CUMULATIVE
In March 2003, the Company repurchased 17 500 shares of preferred stock for $1.6 million, satisfying its redemption requirement for
2003. In September 2002, the Company made a mandatory redemption of 17 500 shares of preferred stock for $1.75 million. On
September 15, 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 2004 through 2006. The remainingshares 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; however, this right is limited by an agreement under the Company s 9.75 percent Senior Notes that
mature in 2008. Upon involuntary liquidation, all preferred stock will be entitled to $100 per share plus accrued dividends.
As discussed in Note 2, the Company adopted SFAS No. 150 effective July 1, 2003. The adoption of this statement requires the
Company to classify preferred stock subject to mandatory redemption as liabilities and preferred stock dividends as interest expense.
The restatement of prior periods was not permitted.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTE 19. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying values of cash and cash equivalents, restricted cash, accounts and notes receivable, accounts payable and short-term
borrowings are reasonable estimates of their fair values. Energy commodity assets and liabilities as well as securities held for trading
are reported at estimated fair value on the Consolidated Balance Sheet.
The fair value of the Company s long-term debt (including current-portion, but excluding capital leases) as of December 31 , 2003 and
2002 was estimated to be $1 067.3 million, or 112 percent of the carrying value of $950.9 million, and $1 001.2 million, or 103
percent of the carrying value of$975.1 million, respectively. The fair value of the Company s mandatorily redeemable preferred stock
as of December 31, 2003 and 2002 was estimated to be $29.9 million, or 95 percent of the carrying value of $31.5 million, and $29.3
million, or 88 percent of the carrying value of $33.3 million, respectively. The fair value of the Company s long-term debt to affiliated
trusts as of December 31 2003 was estimated to be $99.5 million; or 90 percent of the carrying value of$110.0 million. The carrying
value as of December 31 2003 does not include $3.4 million of debt that is considered common equity by the affiliated trusts. The fair
value of the Company s preferred trust securities as of December 31, 2002 was estimated to be $89.6 million, or 90 percent of the
carrying value of $100.0 million. These estimates were primarily based on available market information.
NOTE 20. 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 ($2.4 million as of
December 31, 2003) 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 2003, the cost recorded for the Plan was $6.9 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 was $0.3 million,
$1.7 million and $0.1 million, respectively during 2003.
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.
From March 2000 through May 2003, the Company issued 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 2003, 2002 and 2001 , a total of
299 801 408 800 and 332 861 shares of common stock were issued, respectively, to these plans.
I FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista Corp.(2) A Resubmission 04/30/2004 Dec 31 , 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTE 21. EARNINGS PER COMMON SHARE
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):
Numerator:
Income from continuing operations
Loss from discontinued operations
Net income before cumulative effect of accounting change
Cumulative effect of accounting change
Net income
Deduct: Preferred stock dividend requirements
Income available for common stock
Denominator:
Weighted-average number of common shares
outstanding-basic
Effect of dilutive securities:
Restricted stock
Contingent stock
Stock options
Weighted-average number of common shares
outstanding-diluted
Earnings per common share, basic:
Earnings per common share from continuing operations
Loss per conunon share from discontinued operations
Earnings per common share before cumulative effect
of accounting change
Loss per conunon share from cumulative effect
of accounting change
Total earnings per conunon share, basic
Earnings per common share, diluted:
Earnings per common share from continuing operations
Loss per common share from discontinued operations
Earnings per common share before cumulative effect
of accounting change
Loss per conunon share from cumulative effect
of accounting change
Total earnings per common share, diluted
NOTE 22. STOCK COMPENSATION PLANS
Avista Corp.
2003 2002 2001
$50,643 $42,174 $68 241
&1l21
694 35,455 156
ilJ2Ql
504 307 156
1.125 2.432
$ 9.724
48,232
244
154
$1.03
(QJID
(QJm
$1.
(QJ.ID
(0.03)
SM2
47,823 47,417
$0.$1.39
&ill il.ill
LQ.J!2l
SMO $0.
$0.$1.38
&ill il.ill
LQ.J!2l
$0.$0.
In 1998, the Company adopted and shareholders approved an incentive compensation plan, the Long-Tenn 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. Beginning in
2000, non-employee directors began receiving options under this plan.
In 2000, the Company adopted a Non-Officer Employee Long- Tenn 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.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
The Board of Directors has determined that it is no longer in the Company s best interest to issue stock options under the 1998 Plan
and the 2000 Plan. Other forms of compensation are in place including the issuance of performance shares to certain officers and other
key employees under the 1998 Plan and 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. SF AS No. 123
, "
Accounting for Stock-Based
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-Scholes
option-pricing model. See Note 1 for disclosure of pro forma net income and earnings per common share.
In 2003, the Company granted 162 600 performance shares to certain officers and other key employees under the 1998 Plan and the
2000 Plan. The performance shares will be payable at the Company s option in either cash or common stock three years from the date
of grant. The amount of cash paid or common stock issued will range from 0 to 150 percent of the performance shares granteddepending on the change in the value of the Company s common stock relative to an external benchmark.
Shares of common stock issued from the exercise of stock options under the 1998 Plan and the 2000 Plan are acquired by the Company
on the open market. As of December 31 , 2003, there were 2.2 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:
Options exercisable at end of year
2003 2002 2001
684 350 440 475 843 900
000 569 800 781 900
(37 439)750)
(325.925)ill 575
j,J92.775
Number of shares under stock options:
Options outstanding at beginning of year
Options granted
Options exercised
Options canceled
Options outstanding at end of year
Weighted average exercise price:
Options granted
Options exercised
Options canceled
Options outstanding at end of year
Options exercisable at end of year
$12.$10.$12.
$11.43 $17.
$17.$19.$19.
$15.57 $15.$17.49
$17.$18.$19.
$ 4.$ 3.43 $ 5.Weighted average fair value of options granted during the year
Principal assumptions used in applying the Black-Scholes model:
Risk-free interest rate
Expected life, in years
Expected volatility
Expected dividend yield
17%
37.10%
87%
25%-4.96%
47.13%
61%
05%-13%
60.80%
93%
I FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 , 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
Information with respect to options outstanding and options exercisable as of December 31 , 2003 was as follows:
Range of
Exercise Prices
$8.77-$11.68
$11.69-$14.
$14.62-$17.
$17.54-$20.45
$20.46-$23.38
$26.30-$28.4 7
Total
Number
of Shares
523,161
652 525
540,400
289 800
449 800
26.200
Non-Employee Director Stock Plan
Options ~xercisal2!
Weighted
Average
Exercise
price
$10.
11.
17.
18.
22.
27.
$17.
Options OutstanqingWeighted WeightedAverage AverageExercise Remaining
Price Lif in ears
$10.25 8.11.82 7.
17.14 6.
18.73 5.
22.56 6.27.39 6.
$15.57 7.
Number
~hares
131 605
312 825
504 900
288 750
353 975
23.400
In 1996, the Company adopted and shareholders approved the Non-Employee Director Stock Plan (1996 Director Plan). Under the1996 Director Plan, directors who are not employees of the Company receive two-thirds of their annual retainer in A vista Corp.
common stock. The Company acquires the conunon stock on the open market. The Company has available a maximum of 150 000shares of its conunon stock under the 1996 Director Plan and there were 65 553 shares available for future compensation tonon-employee directors as of December 31 2003.
NOTE 23. COMMITMENTS AND CONTINGENCIES
The Company believes, based on the information presently 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 theconsolidated fmancial 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 Federal Energy Regulatory Commission (FERC) issued an order conunencing a fact-finding investigation ofpotential manipulation of electric and natural gas prices in the California energy markets by multiple companies. On May 8, 2002, theFERC requested data and information with respect to certain trading strategies in which the companies may have engaged.
Specifically, the requests inquired as to whether or not the Company engaged in certain trading strategies that were the same or similarto those used by Enron Corporation (Enron) and its affiliates. These requests were made to all sellers of wholesale electricity and/or
ancillary services in power markets in the western United States during 2000 and 200 I , including A vista Corp. and A vista Energy.
May 22, 2002, A vista Corp. and A vista Energy filed their responses to this request indicating that both companies had engaged insound 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 knowingly engaged in these
trading strategies, or any variant of the strategies.
On June 4, 2002, the FERC issued an additional order to A vista 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 allegedthat Avista Corp. failed to respond fully and accurately to the data request made on May 8, 2002. On June 14, 2002, Avista Corp.provided additional 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 ofthe 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
I FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
governing transactions 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 provided all relevant information in response to the May 8, 2002 data
request.
In December 2002, as a result of the investigation, the FERC trial staff, A vista Corp. and A vista Energy filed a joint motion
announcing that the parties had reached an agreement in principle and requested that the procedural schedule be suspended. In the
joint motion, the FERC trial staff stated 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; and (3) Avista Utilities or Avista Energy
withheld relevant information from the FERC'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 trial 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 forward it to the FERC commissioners for acceptance following a 30-day comment period.
In February 2003, the City of Tacoma (Tacoma) and California Parties (the Office of the Attorney General, the California Public
Utilities Commission (CPUC), and the California Electricity Oversight Board, filing jointly) filed comments in opposition to the
agreement in resolution between the FERC trial staff, A vista Corp. and A vista Energy. POE 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 filed
joint reply comments in response to Tacoma, the California Parties, and PGE. The FERC trial staff filed separate reply comments
supporting the agreement in resolution and responding to Tacoma, the California Parties and PGE. The reply comments of A vista
Corp., A vista Energy and the FERC trial staff also reiterated the request that the administrative law judge certify the agreement in
resolution and forward it to the FERC commissioners for approval.
On March 26, 2003, the FERC policy staff issued its fmal report on their investigation of western energy markets. In the report, the
FERC policy staff recommended the issuance of "show cause" orders to dozens of companies to respond to allegations of possible
misconduct in the western energy markets during 2000 and 2001. Of the companies named in the March 26, 2003 report, A vista Corp.
and A vista Energy were among the few that had already been the subjects of a FERC investigation.
At an April 9, 2003 prehearing conference relating to the ongoing investigation of Avista Corp. and Avista Energy, Avista Corp.
proposed that the decision to certify the agreement between Avista Corp., Avista Energy and the FERC trial staffbe delayed to further
address certain issues and to allow for potential uncertainty to be removed with respect to the fmal resolution of the case. The FERC'
administrative law judge agreed and ordered a further preheaTing conference to clarify certain issues raised in the March 26, 2003
FERC policy staff report on western energy markets.
On May 15, 2003, the FERC's trial staff submitted supplementary information explaining its conclusions and addressing three
narrowly focused issues related to the March 26, 2003 FERC policy staff report on western energy markets. The FERC'
administrative law judge held a further preheaTing conference on May 20, 2003, at which time the FERC trial staff reviewed its
fmdings and conclusions, and reiterated their recommendation to certify the agreement in resolution as supplemented. On May 27
2003, Tacoma and the California Parties reiterated their objections to the proposed agreement in resolution. A vista Corp., A vista
Energy and the FERC trial staff each filed reply comments to Tacoma and the California Parties on June 3, 2003, reiterating their
recommendations to the FERC's administrative law judge for certification of the agreement in resolution.
On June 25, 2003, the FERC's administrative law judge issued an order denying the request to certify the agreement in resolution and
to forward it to the FERC commissioners for fmal approval. In the June 25, 2003 order, the FERC's administrative law judge
reinstated a procedural schedule that called for further testimony and hearings in the case.
On July 10 2003, Avista Corp. and Avista Energy flied an appeal to the June 25, 2003 order. In the appeal, Avista Corp. and Avista
Energy asserted that the FERC's administrative law judge did not have the opportunity to consider how other orders, which were also
issued on June 25, 2003 by the FERC with respect to western energy markets and Enron, would impact the case. Those orders
provided additional guidance with respect to defming improper trading activities with the effect of further validating the findings of the
FERC trial stairs investigation of Avista Corp. and Avista Energy. On July 10 2003, the FERC trial staff also filed a motion with the
FERC's administrative law judge asking for clarification and reconsideration of the June 25, 2003 order. The FERC's trial staff
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
requested that the agreement in resolution be certified and forwarded to the FERC commissioners for fmal approval without the need
for a further hearing. On July 17, 2003, Avista Corp. and Avista Energy filed an answer to this motion with the FERC, which
supported the FERC trial staff s position.
On July 24 2003, the FERC's administrative law judge issued an order, which granted the FERC trial staffs July 10 2003 motion for
reconsideration. In the order, the judge found that there were no unresolved issues of material fact and that the record was sufficient
for the FERC to make a determination on the merits of the settlement. The judge certified the agreement in resolution and forwarded it
to the FERC commissioners for fmal approval. In reaching this conclusion, the FERC's administrative law judge considered the July
2003 appeal by Avista Corp. and Avista Energy. However, this appeal was denied as moot in view of granting the FERC trial staff
motion for reconsideration. The certification stated that "the Chief Judge further fmds that the proposed settlement disposes of all
issues set for hearing in this proceeding, that it is just, reasonable, and in the public interest."
On August 8, 2003, the California Parties filed a motion with the FERC and the chief administrative law judge requesting that the
judge reconsider his July 24, 2003 order granting reconsideration and canceling the procedural schedule, as well as the judge
certification of the agreement in resolution. In response to the filing, the chief administrative law judge stated that he certified the
agreement in resolution and forwarded it to the FERC commissioners for their consideration. The chief administrative law judge
indicated that he would advise the Secretary of the FERC that the California Parties' motion be referred to the FERC commissioners
for consideration. On August 22, 2003, Avista Corp. and Avista Energy filed a response to the August 8, 2003 motion of the
California Parties. The response reiterated, among other things, that the agreement in resolution is strongly supported by the extensive
investigation conducted by the FERC trial staff, and should be approved by the FERC commissioners.
Final approval of the agreement in resolution has remained pending before the FERC since July 2003.
s. Commodity Futures Trading Commission (CFfC) Subpoena
Beginning in June 2002, the CFfC issued several subpoenas directing A vista Corp. and A vista Energy to produce certain materials and
make employees available to be interviewed. The inquiries related to whether electricity and natural gas trades by A vista COlp. and
Avista Energy involved "round trip trades
" "
wash trades " or "sell/buyback trades" and whether Avista Corp. and Avista Energy
properly reported trading prices to publishers of power and natural gas indices. A vista Corp. and A vista Energy cooperated with the
CFTC and provided the information requested by the CFTC. While the CFTC always reserves the right to reopen its investigation, the
CFTC provided written notification to Avista Corp. and Avista Energy on January 29, 2004 that it has detennined to close the
investigation.
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 A vista Corp., Thomas M. Matthews, the former Chairman of the Board, President and Chief Executive Officer of
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. In October and November 2002, Gail West,
Michael Atlas and Peter Arnone filed similar class action lawsuits in the same court against the same parties. 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. On August 19, 2003, the plaintiffs filed their consolidated amended class action
complaint in the same court against the same parties. In their complaint, the plaintiffs continue to 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. The plaintiffs allege that the Company did not have adequate risk management processes
procedures and controls. The plaintiffs further allege that the Company engaged in unlawful energy trading practices and allegedly
manipulated western power markets. The plaintiffs assert that alleged misstatements and omissions have occurred in the Company
filings with the Securities and Exchange Commission and other information made publicly available by the Company, including press
releases. The class action complaint asserts claims on behalf of all persons who purchased, converted, exchanged or otherwise
acquired the Company s connnon stock during the period between November 23, 1999 and August 13, 2002. The Company filed a
motion to dismiss this complaint in October 2003 and the plaintiffs filed an answer to this motion in January 2004. Arguments before
the Court on the motion are scheduled to be held on March 19 2004. The Company intends to vigorously defend against this lawsuit.
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
California Energy Markets
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 infonnation
about all of their sales and purchases at market-based rates. As a result, the California AG contends that 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
and awaits decision.
Port of Seattle Complaint
On May 21 , 2003, the Port of Seattle flied a complaint in the United States District Court for the Western District of Washington
against numerous companies, including Avista Corp., Avista Energy and Avista Power. The complaint seeks compensatory and treble
damages for alleged violations of the Shennan Act and the Racketeer Influenced and Corrupt Organization Act by transmitting, via
wire communications, false infonnation intended to increase the price of power knowing that others would rely upon such
infonnation. The complaint alleges that the defendants and others knowingly devised and attempted to devise a scheme to defraud and
to obtain money and property from electricity customers throughout the WECC, by means of false and fraudulent pretenses
representations and promises. The alleged purpose of the scheme was to artificially increase the price that the defendants received for
their electricity and ancillary services, to receive payments for services they did not provide and to manipulate the price of electricity
throughout the WECC. In August 2003, the Company flied a motion to dismiss this complaint. A transfer order has been granted
which moves this case to the United States District Court for the Southern District of California to consolidate it with other pending
actions. Arguments with respect to the motions to dismiss filed by the Company and other defendants are scheduled for March 26
2004.
State of Montana Proceedings
On June 30, 2003, the Attorney General of the State of Montana (Montana AG) filed a complaint in the Montana District Court on
behalf of the people of Montana and the Flathead Electric Cooperative, Inc. against numerous companies, including A vista Corp. The
complaint alleges that the companies illegally manipulated western electric and natural gas markets in 2000 and 2001. This case was
subsequently moved to the United States District Court for the District of Montana; however, it has since been remanded back to the
Montana District Court.
The Montana AG also petitioned the Montana Public Service Commission (MPSC) to fme public utilities $1 000 a day for each day it
fmds they engaged in alleged "deceptive, fraudulent, anticompetitive or abusive practices" and order refunds when consumers were
forced to pay more than just and reasonable rates. On February 12, 2004, the MPSC issued an order initiating investigation of the
Montana retail electricity market for the purpose of determining whether there is evidence of unlawful manipulation of that market.
Montana Public School Trust Fund Lawsuit
On October 20, 2003, Richard Dolan and Denise Hayman filed a lawsuit in the United States District Court for the District of Montana
against all private owners of hydroelectric dams in Montana, including A vista Corp. The lawsuit alleges that the hydroelectric
facilities are located on state-owned riverbeds and the owners have never paid compensation to the state s public school trust fund.
The lawsuit requests lease payments dating back to the construction of the respective dams and also requests damages for trespassing
and unjust enrichment. An Amended Complaint adding Great Falls Elementary School District No.1 and Great Falls High School
District lA was filed on January 16 2004. On February 2 2004, the Company filed its motion to dismiss this lawsuit; PacifiCorp and
PPL Montana, as the other named defendants also filed a motion to dismiss, or joined therein.
Colstrip Generating Project Complaint
In May 2003, various parties (all of which are residents or businesses of Colstrip, Montana) filed a consolidated complaint against the
owners of the Colstrip Generating Project (Colstrip) in Montana District Court. Avista Corp. owns a 15 percent interest in units 3 and
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Me, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31,2003
NOTES TO FINANCIAL STATEMENTS (Continued)
4 of Colstrip, which is located in southeastern Montana. The plaintiffs allege damages to buildings as a result of rising ground water
as well as damages from contaminated waters leaking from the lakes and ponds of Colstrip. The plaintiffs are seeking punitive
damages, an order by the court to remove the lakes and ponds and the forfeiture of all profits earned from the generation of Colstrip.
The Company intends to work with the other owners of Co Is trip in defense of this complaint.
Hamilton Street Bridge Site
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. In January 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 effective means of halting or controlling future releases of
substances from the site, 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.
The DOE, the Company and another PLP, Burlington Northern & Santa Fe Railway Co. (BNSF) signed an Agreed Order in March
2000 that provided for 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; perfonnance of a focused feasibility study; and
implementation of an interim groundwater monitoring plan. During the second quarter of 2000, the Company received conunents
from the DOE on its initial remedial investigation, and then submitted another draft of the remedial investigation, which was accepted
as fmal by the DOE. After responding to conunents from the DOE, the feasibility study was accepted by the DOE during the fourth
quarter of 2000. After receiving input from the Company and the other PLPs, the fmal Cleanup Action Plan (CAP) was issued by the
DOE in August 2001. In September 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. In September 2002, the Company, BNSF and the DOE
fmalized 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 and approved by the DOE in May 2003. Work under the CAP conunenced during the second
quarter of2003. 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' Alene Tribe 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 has
not been 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 affirmed this 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, Momoe
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 in July 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.
IFERC FORM NO.1 (ED. 12-88) ge 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmisslon 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
Clark Fork Settlement Agreement
Dissolved gas levels exceed Idaho and federal water quality standards downstream of the Cabinet Gorge Hydroelectric Generating
Project (Cabinet Gorge) during periods when excess river flows must be diverted over the spillway. Mitigation of the dissolved gas'
levels continues to be studied as agreed to in the Clark Fork Settlement Agreement. To date, intensive biological studies in the lower
Clark Fork River and Lake Pend Oreille have documented no significant 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 with the
other signatories to the agreement and submitted the plan in December 2002 for review and approval to the Idaho Department of
Environmental Quality and the U.S. Fish and Wildlife Service. In December 2003, the Idaho Department of Environmental Quality
provided modifications to the plan that have been reviewed by the Company. The modifications did not result in any significant
changes to the Company s plan. The structural alternative proposed by the Company provides for the modification of the two existing
diversion tunnels built when Cabinet Gorge was originally constructed. The costs of modifications to the fITst 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 perfonnance of the flIst tunnel and such modifications would commence no later than
10 years following the completion of the fITst 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 conunencing as
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 Project describes the approach to restore bull trout populations in the project areas. Using the
concept of adaptive management and working closely with the U.S. Fish and Wildlife Service, the Company is evaluating the
feasibility of fish passage. The results of these studies will help the Company and other parties detennme the best use of funds toward
continuing fish passage efforts or other population enhancement measures.
Other Contingencies
In the nonnal 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
conunitments 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
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 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. Claims within the Clark Fork River
basin could potentially adversely affect the energy production of the Company s Cabinet Gorge and Noxon Rapids hydroelectric
facilities. The Company is participating in this extensive adjudication 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 at the Colstrip thennal 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.
FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmisslon 04/30/2004 Dec 31, 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
As of December 31 , 2003, the Company s collective bargaining agreement with the International Brotherhood of Electrical Workers
represented approximately 48 percent of all A vista 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. A local agreement in Medford, Oregon, which covers approximately 40
employees, will expire on March 31 , 2005. Negotiations are currently ongoing with respect to two other labor agreements in Oregon
covering approximately 15 employees.
NOTE 24. 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.
During the second quarter of 2003, Avista Corp. reported Avista Labs as discontinued operations (see Note 3). Accordingly, periods
prior to the second quarter of 2003 have been restated to reflect A vista Labs as discontinued operations. Several accounting standards
have been issued and rescinded, which have changed the accounting and reporting for derivative commodity instruments. This has
resulted in the restatement of operating revenues and resource costs (operating expenses) for periods prior to the issuance or rescission
of the respective accounting standards. Such restatements have not had any impact on income from operations, income from
continuing operations, net income or income available for common stock. A summary of quarterly operations (in thousands, except
per share amounts) for 2003 and 2002 follows:
Three Months Ended
March June September December
2003
Operating revenues $338 892 $236 735 $238 750 $309 008
Operating expenses:
Resource costs 185 916 102 309 122 591 165 676
Operations and maintenance 323 459 722 554
Administrative and general 27,863 684 780 167
Depreciation and amortization 18,942 18,904 114 851
Taxes other than income taxes 17 858 15.270 13.424 15.275
Total operating expenses 283 902 192.626 210.631 264.523
Income from operations 990 44.109 28.119 44.485
Income from continuing operations 18,442 713 386 102
Loss from discontinued operations o..JW (3.74.4)-U.2)Net income before cumulative effect
of accounting change 322 969 320 083
Cumulative effect of accounting change il.J2Q)
Net income 132 969 320 083
Income available for common stock $15 554 422 320 $15 083
Outstanding common stock:
Weighted average 100 224 281 319
End of period 48,182 830 311 344
Earnings per share, diluted:
Earnings per share from continuing operations $0.$0.$0.$0.
Loss per share from discontinued operations (0.02)(MID
Earnings per share before cumulative effect
of accounting change 0.35 0.31
Cumulative effect of accounting change (0.03)
Total earnings per share, diluted $0.32 $0.$0.$0.
Dividends paid per common share $0.$0.$0.125 $0.125
Trading price range per common share:
High $12.$14.$16.$18.
Low $9.$10.49 $13.$15.
FERC FORM NO.ED. 12-88 Page 123.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 2003
NOTES TO FINANCIAL STATEMENTS (Continued)
Three Months Ended
March June September December
2002
Operating revenues $337 617 $231 082 $206 821 $287 396
Operating expenses:
Resource costs 196 734 040 944 150 996
Operations and maintenance 691 236 799 204
Administrative and general 310 33,879 795 663
Depreciation and amortization 753 737 440 18,937
Taxes other than income taxes 917 16.290 13.991 15.418
Total operating expenses 288 189.182 182.969 245.218
Income from operations 212 41.900 23.852 42.178
Income from continuing operations 976 292 864 042
Loss from discontinued operations (Lm)OMI)(2.4 79)(565)
Net income (loss) before cumulative effect
of accounting change 248 345 615)477
Cumulative effect of accounting change
Net income (loss)100 345 615)477
Income (loss) available for common stock $10,492 737 $(2 223)$10 899
Outstanding common stock:
Weighted average 671 774 866 978
End of period 737 830 47,930 044
Earnings (loss) per share, diluted:
Earnings per share from continuing operations $0.35 $0.$0.$0.
Loss per share from discontinued operations (0.041 (0.041 (QJllEarnings (loss) per share before cumulative effect
of accounting change 0.31 (0.05)
Cumulative effect of accounting change (0.09)
Total earnings (loss) per share, diluted $0.so.2.O
Dividends paid per common share $0.$0.$0.$0.
Trading price range per common share:
High $16.47 $16.$13.$12.10
Low $13.$11.00 $10.$8.
SUPPLEMENTAL CASH FLOW INFORMATION:
(QQl!ars in $ousanQs)2003 2002 2001
Cash paid for interest $84 645 $31 307 $12 156
Cash paid for income taxes 476 7,428 (35 874)
Non-cash fmancing and investing activities
Transfer of Coyote Springs 2 from subsidiary 106 766
Property and equipment acquired under capital leases 106
Intangible asset related to pension plan (654)366
Unfunded accumulated benefit obligation 198 (34 164)139)
IFERC FORM NO.1 (ED. 12-Page 123.
Name of Respondent
Avista Corp.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/30/2004
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND 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.
Year of Report
Dec. 31 2003
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.
Line
No.
Item Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Minimum Pension
Liability adjustment
(net amount)
(c)
Foreign Currency
Hedges
Other
Adjustments
(a)
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
8 Total (lines 6 and 7)
9 Balance of Account 219 at End of Current
Year
(d)(e)
18,809,177)
18,809,177)
18,809,177)
454,088
454,088
355,089)
FERC FORM NO.1 (NEW 06-02)Page 122a
Name of Respondent This ~ort Is: Date of Report Year of Report
A.
(1) ~An Original (Mo, Da, Yr) Dec. 31 2003Vista orp. (2) A Resubmission 04/30/2004
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Line
No.
Other Cash Flow
Hedges
(Specify)
Other Cash Flow
Hedges
(Specify)
Totals for each
category of items
recorded in
Account 219
(h)(f)
(g)
18,809,177)
18,809,177)
18,809,177)
454,088
454,088
355,089)
FERC FORM NO.1 (NEW 06-02)Page 122b
Net Income (Carried
Forward from
Page 117, Line 72)
Total
Comprehensive
Income
Name of Respondent
Avista Corp.
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/30/2004
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Year of Report
Dec. 31 2003
(a)_mm ,m_,m
. .
(b)
Electric
(c)
Line
No.
Classification Total
1 Utility Plant
2 In Service
3 Plant in Service (Classified)
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (3 thru 7)
9 Leased to Others
10 Held for Future Use
11 Construction Work in Progress
12 Acquisition Adjustments
13 Total Utility Plant (8 thru 12)
14 Accum Prov for Depr, Amort, & Depl
15 Net Utility Plant (13 less 14)
16 Detail of Accum Prov for Depr, Amort & Depl
17 In Service:
18 Depreciation
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utility Plant
22 Total In Service (18 thru 21)
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Others (24 & 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,32)
514,133,202
905,446
956,750,361
518,038,648 956,750,361
49.615,389
26,580,073
594,234,110
886,846,714
1 ,707,387,396
44,310,631
001,060,992
651,132,508
349,928,484
826,175,778 644,621 400-.'m
" .",."",.",."... ,..", ,.. """"""
490,249
834,666,027
511 108
651,132,508
35,857,057
35,857 057
r'-'--'_..,
__""m,_~_u'....,..".'..'m'm_m'm'm'...._m'_- __'m"... ,.,....m 'U""" uu""
- ."" "
,,.u, , ,..,
,mm u .
. ... .,.."",., .. ., ,.
, m
16,323,630
886,846,714 651 132,508
FERC FORM NO.1 (ED. 12-89)Page 200
Name of Respondent
Avista Corp.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Other (Specify) Other (Specify) Other (Specify)
Year of Report
Dec. 31 2003
Gas Common
(g)
(h)
484,721,213 72,661,628
905,446
484,721,213 76,567 074
082,565
26,580,073
513,383,851
199,857,149
313,526,702
222,193
79,789,267
35,857 057
43,932,210
"""""""""""""""""""""""""""""""""""""""""""""""" """""""""""""""""""""""""""""""""" ........, """""""""""""""""""""""""""""""""" """""""""""""""""""""""""""""""""""""""""""""'" """""""""""""""""""""""'.............."..""...,..,.,.........
181,554,378
35,857,057
35,857,057
-.....-""---" -"---'--" "---"---'-"""""""'--'-"---"""""",,, --""--""""""""-""""----""-""""""""""'
..'..n......._...'--.....,..,--__..._,...n..,..,...........,-,,-, ------'--_,
...........,.. .,. . ,
16,323,630
199,857,149 35,857 057
FERC FORM NO.1 (ED. 12-89)Page 201
Line
No.
Name of Respondent
Avista Corp.
Year of Report
Dec. 31 2003
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/30/2004
ELECTRI 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 Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of 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)Ine ccount a ance ltionsNo Beginning of Year
(b)
1. INTANGIBLE PLANT
(301) Organization
3 (302) Franchises and Consents
(303) Miscellaneous Intangible Plant
5 TOTAL Intangible Plant (Enter Total of lines 2 3, and 4)
2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights
9 (311) Structures and Improvements
10 (312) Boiler Plant Equipment
11 (313) Engines and Engine-Driven Generators
12 (314) Turbogenerator Units
13 (315) Accessory Electric Equipment
14 (316) Misc. Power Plant Equipment
15 (317) Asset Retirement Costs for Steam Production
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)
17 B. Nuclear Production Plant
18 (320) Land and Land Rights
19 (321) Structures and Improvements
20 (322) Reactor Plant Equipment
21 (323) Turbogenerator Units
22 (324) Accessory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights
28 (331) Structures and Improvements
29 (332) Reservoirs, Dams, and Waterways
30 (333) Water Wheels, Turbines, and Generators
31 (334) Accessory Electric Equipment
32 (335) Misc. Power PLant Equipment
33 (336) Roads, Railroads, and Bridges
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)
36 D. Other Production Plant
37 (340) Land and Land Rights
38 (341) Structures and Improvements
39 (342) Fuel Holders, Products, and Accessories
40 (343) Prime Movers
41 (344) Generators
42 (345) Accessory Electric Equipment
43 (346) Misc. Power Plant Equipment
--,_.._---,--- ---"-"-----
(c)
14,698
15,084,274
11,140,103
26,239,075
349,073
349,073
r '-""""'---"""""""-'
""..-.."..,....-..,.."....,.....,..,--.. ,--",-----,-......_--,.., .._" "",,,._,,,-,---,--. .,. . "' .. .. . . ,
I ,
. ,.... .. ,.. ,. .,. .... .. "
248,799
123,548,121
156,705,306
595,522
306,579
680,235
23,766,083
15,037 235
212,151
49,245
73,635
114,206
351 338365,985,779
52,693,907
36,274 058
97,179 853
95,425,341
25,623,546
110,823
991,477
689,930
68,104
276,698
566,797
113,465
22,327
315,299,005 737 237
""-"-"'--"'-""'--"-"""-----""""""""""'-'-----~-,---,_.,.. . ...,_., .., ,.,,_..
762,234
960,910
450,271
22,384,385
32,858,651
790,728
243,758
397
183,555
12,605,471
556,094
75,935,116
260,027
657 253
FERC FORM NO.1 (REV. 12-Q3)Page 204
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmission 04/30/2004
ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utility plant accounts. 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.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 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
Line
End flf Year No.(d) (e) (f)
698
15,084,274
103,328 385,848
103,328 26,484,820
583 245,216
878,644 124,264,999
46,601 158.965,284
45,892,386
72,809 23,742 519
98,802 15,209,672
114,206
119,410 783,425 371,434,282
66,592 53,317 245
64,178 36,277 984
516 98,454,035
037,350 94,954,788
110,200 26,626,811
133,150
1 ,991 ,393
214 244 -66,592 317 755,406
762,631
144 465
98,802 13,956,940
21,828,291
108,793,767
050,755
901 011
FERC FORM NO.1 (REV. 12-03)Page 205
Name of Respondent
Avista Corp.
(a)
44 (347) Asset Retirement Costs for Other Production
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)
46 TOTAL Prod. Plant (Enter Total of lines 16,25,, and 45)
47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights
49 (352) Structures and Improvements
50 (353) Station Equipment
51 (354) Towers and Fixtures
52 (355) Poles and Fixtures
53 (356) Overhead Conductors and Devices
54 (357) Underground Conduit
55 (358) Underground Conductors and Devices
56 (359) Roads and Trails
57 (359.1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights
61 (361) Structures and Improvements
62 (362) Station Equipment
63 (363) Storage Battery Equipment
64 (364) Poles, Towers, and Fixtures
65 (365) Overhead Conductors and Devices
66 (366) Underground Conduit
67 (367) Underground Conductors and Devices
68 (368) Line Transformers
69 (369) Services
70 (370) Meters
71 (371) Installations on Customer Premises
72 (372) Leased Property on Customer Premises
73 (373) Street Lighting and Signal Systems
74 (374) Asset Retirement Costs for Distribution Plant
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)
76 5. GENERAL PLANT
77 (389) Land and Land Rights
78 (390) Structures and Improvements
79 (391) Office Fumiture and Equipment
80 (392) Transportation Equipment
81 (393) Stores Equipment
82 (394) Tools, Shop and Garage Equipment
83 (395) Laboratory Equipment
84 (396) Power Operated Equipment
85 (397) Communication Equipment
86 (398) Miscellaneous Equipment
87 SUBTOTAL (Enter Total of lines 77 thru 86)
88 (399) Other Tangible Property
89 (399.1) Asset Retirement Costs for General Plant
90 TOTAL General Plant (Enter Total of lines 87 88 and 89)
91 TOTAL (Accounts 101 and 106)
92 (102) Electric Plant Purchased (See Instr. 8)
93 (Less) (102) Electric Plant Sold (See Instr. 8)
94 (103) Experimental Plant Unclassified
95 TOTAL Electric Plant in Service (Enter Total of lines 91 thru 94)
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106) (Continued)ccoun a anceBeginning of Year
(b)
Year of Report
Dec. 31 2003
Ine
No.Itlons
(c)
59,450,937
740,735,721
104,085,725
114 174,300
12,118,199
941 953
113,758,443
063,254
75,222,853
474,688
561,148
317,533
825,909
448,999
95,136
931,943
309
720,009
633,305
935
'."'--".'."'.""""'-".."-"--"-""""'-"-"-."'.'."---.'.,.",-, """ .,,.""". """.
295,283,980 10,834,636
143,173
10,039,236
66,821 357
300,344
122 460
081 591
149 124 154
101 635,238
46,422,067
491 759
117 619,456
182,558
23,731 512
180,042
842,296
559,636
297,562
788,634
847 060
901 016
19,546,890 061 412
r """"""""
"""""""'----,-"-"""""""",,, """'-- ---,_..- "'""""""""""" , ." ,,-,.., ,-
698,757,400 381 365
124,681
630,418
100,505
107 255
99,196
659,040
844,500
16,534,913
17,372,467
738
48,474,713
45,898
174 487
142 071
326
551 287
956,382
953,451
48,474 713
809,490,889
953,451
156,692,825
809 490,889 156 692,825
FERC FORM NO.1 (REV. 12.Q3)Page 206
Name of Respondent
Avista Corp.
(d)
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
ELECTRIC PLANT IN SERVICE (Account 101 102,103 and 106) (Continued)Adjustments Transfers Balance at(e) (f) End ~f Year
Year of Report
Dec. 31, 2003
Retirements
49,585
15,420
196,168
116,332 139,409
124,681
969,585
146,403
936,007
99,196
751,526
912,406
17,890,032
19,351,926
738
52,183,500
Line
No.
----'-~-,,_..,---
..___"'m..'m""__.._'mnm- "".n "" ".._n
'"
------'-"--_'_'n______m",.._..,__..,,-_.._---- ---"....- '----_"-'m_",__
_---~--,....,--,-",,-
-,- -~-~_..___..nm_'__'n_
_"_'----
1 ,333,654
98,802
948,819
163,437,860
852,627 548
908,688 170,410
12,567 198
037,089
121,611 288
17,067 563
75,846,585
64,992,153
561,148
317,533
1 ,826,844
96,277
115,840
"....... ,.." """....""'- "
'_____nmm,_n.... -""Om
"""""""""",""" -~-""-
------_'m"'~_'_"-"_m_____",--_...- m"_'--""-,
__'....
_mn~_"..n"'_-_'-,-_._"....,--- __-___n""_"..mm"....m__mm..m'.._.._"'~-
120,805 170,410 304,827,401
275
577 119
739
537
148,724
841,090
10,125,884
68,474 553
130,002
150,569
43,883
321 496
617 809
79,697
403,219
913
179,645
26,756
155,174 194
105,326,965
48,946,733
80,647,470
120,817 037
85,949,921
24,229,309
292 20,521,010
425,361 340,762 724 054,166
872 371,039
198,225 147,510
607,602 362 938
607 602
590,750
362,938
-415,529
52,183,500
960,177,435
590,750 -415,529 960,177 435
FERC FORM NO.1 (REV. 12-03)Page 207
Name of Respondent This Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmission 04/30/2004
CONSTRUCTION WORK IN PROGRESS - - ELE(, TRIC (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 prCJgress -
No.Electric (Account 107)
(a)(b)
STATE OF WASHINGTON
Post Street 115 Substation 428,059
Beacon-Rathdrum 230KV LIne 114 082
Beacon Storage Yard-Build Containment Area 292 703
Hydro Relicensing Costs-Spokane River Project 049,048
Endicott Road Move work 114 740
Trent Bridge Conduit Work 142,150
Flowery Trail Reroute 3-phase underground 253,280
Network Post Street LID 163,602
Upper Falls Control Work 432,033
11 , Boulder Park Fire Supression syst 231,550
12 i Dry Creek-Lolo 230 Kv line 681,238
Northeast 115kv substation 103,715
Benewah-Shawnee 230Kv line 517 311
Boulder construction 423,057
Scada II Add supv 128,711
minor projects (49) under $100,000 043,716
STATE OF IDAHO
Kootenai Cutoff Road Move 113,881
Adelphia Make Ready Moscow 115,044
Oden 115 sub-split FDR and SCADA FDR 360,091
Cabinet Gorge Unit #2 Turbine 495,223
Beacon-Rathdrum 313,939
Cabinet Gorge unit #4 Turbine 127,399
Pinecreek Rebuild 491,428
Clark Fork Settlement Agreement 271,267
Hwy 95/Palouse River road move 148,242
Post Falls Cap Project 182,751
North Moscow 522 Recon 147 648
OIdtown Sub Const 173,135
System replacement transmission line relays 186,823
Holbrook upgrade feeder 104,208
Minor Projects (58) under $100,000 053,305
STATE OF MONTANA
Noxon Rapids Capital Projects Upgrades 403,371
Clark Fork Settlement agreement 060,908
Minor Projects (7) under $100,000 100,765
COMMON-W A & 10
AVA/BPA Fiber Project 170,456
Minor Projects (10) $100,000 171,752
TOTAL 310,631
FERC FORM NO.1 (ED. 12-87)Page 216
Name of Respondent
Avista Corp.
Year of Report
Dec. 31 2003
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11 , column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. 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
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Ine
No.(a)
1 Balance Beginning of Year
2 Depreciation Provisions for Year. Charged to
3 (403) Depreciation Expense
4 (403.1) Depreciation Expense for Asset
Retirement Costs
5 (413) Exp. of Elec. PIt. Leas. to Others
603,295,686 603,295,686
6 Transportation Expenses-Clearing
7 Other Clearing Accounts
8 Other Accounts (Specify, details in footnote):
10 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
11 Net Charges for Plant Retired:
12 Book Cost of Plant Retired
13 Cost of Removal
46,994,882 994,882r---r--~
14 Salvage (Credit)
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
Other Debit or Cr. Items (Describe, details in
footnote):
18 Book Cost or Asset Retirement Costs Retired
484,657
381,679
197 168
669 168
484,657
381,679
197,168
669,168
Balance End of Year (Enter Totals of lines 1
10, 15, 16, and 18)
644,621 400 644 621,400
20 Steam Production
21 Nuclear Production
Section B. Balances at End of Year According to Functional Classification
199,658,428 199,658,428
22 Hydraulic Production-Conventional
23 Hydraulic Production-Pumped Storage
24 Other Production
25 Transmission
64,407 785 64,407,785
26 Distribution
27 General
15,713,873
114,648,275
220,520,780
29,672 259
644,621,400
15,713,873
114 648,275
220,520,780
29,672,259
644,621,40028 TOTAL (Enter Total oflines 20 thru 27)
FERC FORM NO.1 (REV. 12-G3)Page 219
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)
Dec. 31,2003(2) 0 A Resubmission 04/30/2004
INVESTMENTS IN SUBSIDIARY COMPANIES Account 123.
1. Report below investments in Accounts 123., 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 tocurrent 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 eamings since acquisition. The TOTAL in column (e) should equal the amount entered forAccount 418.
ILine DesCription of Investment Date Acquired Date Of Amount Of Investment at
No.(a)(b)l~ity
Beginning of Year
(d)
Avista Capital - Common Stock 1997 184,251,609
Avista Capital - Equity in Earnings 72,486,131
Dividends from Subsidiary (Avista Capital)
Total Cost of Account 123.1 $TOTAL 256,737 740
FERC FORM NO.1 (ED. 12-89)Page 224
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004
INVESTMENT!) IN SUBSIDIARY COMPANIES (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.
Equity In Subsidiary Revenues for Year Amount of Investment at Gain or Loss nom Investment Line
Eamin
~~)
of Year
(f)
End fd)Year DiSP?A)ed of No.
184,251 ,609
156,784 81,642,915
-9,990,036 -9,990,036
156,784 -9,990,036 255,904,488
FERC FORM NO.1 (ED. 12-89)Page 225
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)2003(2)0 A Resubmission 04/30/2004 Dec. 31
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 Departments which
Use Material(a)(b)(c)(d)
Fuel Stock (Account 151)261 065 395,349 (1)
Fuel Stock Expenses Undistributed (Account 152)
Residuals and Extracted Products (Account 153)
Plant Materials and Operating Supplies (Account 154)
Assigned to - Construction (Estimated)502 503 309,870 (1)
Assigned to - Operations and Maintenance
Production Plant (Estimated)460,890 201,762 (1)
Transmission Plant (Estimated)011 171 (1)
Distribution Plant (Estimated)167 171 163,574 (1)
Assigned to - Other (provide details in footnote)304 937 843,705 (1 ),(2)
TOTAL Account 154 (Enter Total oflines 5 thru 10)449,512 522,082
Merchandise (Account 155)
Other Materials and Supplies (Account 156)
Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
Stores Expense Undistributed (Account 163)494,542 -496,415
TOTAL Materials and Supplies (Per Balance Sheet)12,205,119 11,421 016
FERC FORM NO.1 (ED. 12-96)Page 227
Name of Respondent This ~rt Is:Date of Report Year of Report
A vista Corp.(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004
0 HER REGULATORY ASSETS (Account 182.
1. Report below the particulars (details) called for conc~rning 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 CREDITS Balance at
No.Other Regulatory Assets ,A.ccount Amount End of YearCharged
(a) (b)(c)(d)(e)
F AS 1 06 - Accounting for Post Retirement 926.472,752 254 768
Benefits, other than Pensions (182.30)
182.30 Amort period 1996-2012
FAS 109 - Acctng for Income Taxes Util Prop 283., 18 401,737 132,097 287
(182.31 & 182.32)
More Options Power Supply (MOPS) - WA (182.34)407.190,944
More Options Power Supply (MOPS) -ID (182.34)407.29,592
W A ERM Deferral Balance (182.35)186.391 ,600 99,774,940
WA Amortization (182.36)974,754 557.974 754
182.36 Amort period 2004-2006
Hamilton Street Bridge -- WA (182.39,028)407.263,712 125,676
Hamilton Street Bridge -- ID (182.39 038)407.107,052 105,300
BPA RES Exchange (182.45, 028)195,192 254.195,192
BPA RES Exchange AIR (182.45, 098)1 ,679,445 254.679,445
BPA RES Exchange -Int Rae (182.46, 028)30,267 419.30,267
BPA RES Exchange -Int Rae (182.46, 038)278 419.278
FAS 133 Reg Asset (182.74)
FAS 143-ARO Reg Asset (182.76)230.10, 10 436,329 436,329
Oregon DSM Long-Term Reg Asset (182.80)various 164,307 -632,736
Workers Comp (182.83)688,889 242.688,889
TOTAL 574 825 13,458,025 239,863,731
FERC FORM NO.1 (ED. 12-94)Page 232
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmission 04/30/2004
MISCELLANEOUS DEFFERED DEBITS (Account 186)
1. Report below the particulars (details) called for conc~rning 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 8ccounr Amount End of YearChar~ed(a)(b)(c)(e)(f)
Regulatory Deferrals - W A
COIStriD Common Fac.603,060 406 740 571,320
W A Accrued Power Def 164,331 974 676 139,007
W A Deferred Power Costs 18,418,548 372,824 791 372
WA ERM YTD Company Band 500,000 500,000 000,000
WA ERM YTD Contra Account 500,000 500,000 000,000
Regulatory Deferrals -
ID Deferred New Generation 921 184 184,240 736 944
COIStriD Common Fac.278,852 406 67,308 211,544
Idaho Accrued PCA Def 592,090 004,168 596,258
ID Deferred Power 960,050 24,378,033 var 82,338,083
ID Accumulated Surcharge Am 034,339 557 26,615,142 53,649,481
Payroll Accrual 597,425 311 753 var 909,178
PPP Surcharge 364,926 89,423 454 349
Misc Error Suspense 206,324 559,340 var 353,016
Joint Projects
Centralia Operating Payments
WPI-ID Terminated Elec Pur.783,989 555 391 992 391,997
Unamortized AIR Sale 357 423 116,277 241 146
Intangible Pension Asset 365,810 151 228.653,810 712,151
Bank Recon Suspense 192 192
Mark to Market Deferred Debit 254
Interest Rate Swap 368,874 1 ,368,874
Nez Perce Settlement 212,869 557 210 207 659
Centralia Mine Env Balance 567 509 815 572,324
DES Contract Amortization 238 556 866 25,372
Metro-Sunset 115KV TE 68,651 45,930 114,581
UPRR Permit Cony 184,051 147,319 331 370
CPRR Permit Conv 72,371 72,371
Ortho Business Activity 85,027 027 136,054
Misc. Work in Progress
Deferrea Regulatory COmm.
Expenses (See pages 350 - 351)
TOTAL 406,921 86,083,253
IFERC FORM NO.1 (ED. 12-94)Page 233
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) n A Resubmission 04/30/2004
MISCELLANEOUS DEFFERED DEBITS (Account 186)
1. Report below the particulars (details) called for conc~rning 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 ~ccoum Amount End of YearChar~ed(a)(b)(c)(e)(f)
Canadian GST Tax 95,404 var 82,287 13,117
Nez Perce Forest 91,876 91 ,876
Electric Network
Misc Work Orders C:$5O,000 250,788 321 292 109
Subsidiary Billings 222,737 var 255,954 966,783
Conservation
Enhanced Low Income Wzn 62,505 59,905 600
Oregon Gas Comm Consvt 150,867 26,808 177,675
Oregon Shower Head 147,726 908 40,592 107,134
Oregon Common Gas Eff 118,681 45,297 163,978
WPNG HE Wtr Htrs-Oregon 268,737 759 286 496
WPNG HE Furnaces 726,742 301,567 028 309
WPNG CA RES UI-360,736 304,670 var 56,066
WPNG OR Res Low 1 185 190 908 13,444 171 746
Regulatorv-Sched 67 230,417 908 33,067 197 350
Reg-Warer Heat Conv 185,645 908 152,358 1 ,033,287
Reg-SpacelWater Con 766,174 908 704 561 061 613
Reg-Elec Commllnd 779,792 908 116,375 663,417
Reg-Gas Wzn Res 185,869 908 153,145 032,724
Rea-UI Elee/Gas 398,209 908 738 348,471
Reg-Elec Manuf Home 333,778 908 48,984 284,794
Reg-Commllnd Gas 135,820 908 19,600 116,220
Reg-Gas Res Appl Ef 610,614 908 208,178 1 ,402,436
Reg-Gas Res Showerhead 137 611 908 55,047 82,564
Reg Elect Res Wzn 58,877 908 643 234
Reg UI Elec Wzn 95,940 908 099 841
Reg Elec Res Shwr 58,739 908 937 20,802
Reo C/I Elec Fuel 229,435 908 34,222 195,213
Reg Gas A.E. Wtr 185,284 908 130 111,154
Rea Low Income Gas Wzn 394 201 908 56,634 337 567
Care - California 36,008 19,199 55,207
Consv. & Renewable Disco 199,786 199,786
Sandpoint DSR - PPL 853,740 908 113,387 740,353
Gas Plant
Hamilton Street Bridge Site 152,520 206,213 var 53,693
Electric Plant
Post Falls No Channel Study 50,991 50,991
Easy Pay Billino CS 303,425 165,536 137 889
Lake CDA Issues 321,992 281,113 603,105
Shareholder Lawsuit 2002 39,790 171.396 211,186
Misc. Work in Progress
Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
TOTAL 406,921 86,083,253
FERC FORM NO.1 (ED. 12-94)Page 233.
Name of Respondent
Avista Corp.
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
ACCUMULATED DEFERRED INCOME T S (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.
Year of Report
Dec. 31 2003
Ine
No.
Electric
escnption an ocatlon
(a)
11,862,009 11,330 752
Other
TOTAL Electric (Enter Total of lines 2 thru 7)
Gas
11,862,009 11,330 752
907 787 832,996
Other
TOTAL Gas (Enter Total of lines 10 thru 15
Other
TOTAL (Acct 190) (Total of lines 8,16 and 17)
907,787
23,825,508
595 304
832,996
24,724,630
222,386
Notes
OCI Adjustment for 2003 related to SERP and Pension plans was booked on the General Ledger 1/31/2004. The 10-K
reflects the journal entry so various accounts, including the 190, have been adjusted to reflect this entry.
The net amount booked to the 190.10 is a debit in the amount of $1,833,120. Of this amount, a debit of$1,999,613 is related to Pension and a credit of $166,494 is related to SERP.
FERC FORM NO.1 (ED. 12-88)Page 234
This Page Intentionally Left Blank
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004
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 (Le., 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)
Account 201 - Common Stock Issued
No Par Value 200,000,000
TOTAL COM 200,000,000
Account 204 - Preferred Stock Issued 10,000,000
Cumulative
TOTAL PRE 10,000,000
FERC FORM NO.1 (ED. 12-91)Page 250
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004
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 PER BALANCE SHEET HELD BY RESPONDENT Line
(Total amount outstanding without reduction AS REACQUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
ares Arr!9unt ares 1~ft
Sh~res Amount(e)(f)(9)(i)
48,344,009 626 787,000
48,344,009 626 787 000
FERC FORM NO.1 (ED. 12-88)Page 251
Name of Respondent This (!)ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmission 04/30/2004
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 lilass ana ~enes of Stock tSalance at Ene or Year
No.(a)(b)
Common Stock - Public Issue 096,029
Shares issued under provisions of Respondant's Dividend Reinvestment and Stock Purchase Plan 442 145
Shares issued under provisions of Respondant's Employee Stock Purchase Plan 74,839
Common Stock - 401 215,137
Common Stock - Periodic Offering Program (POP)599,768
$6.95 Preferred Stock, Series K 334 005
Common Stock Split 187 872
22 TOTAL 10,949,795
FERC FORM NO.1 (ED. 12-87)Page 254b
This Page Intentionally Left Blank
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmission 04/30/2004
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)
Acet. 221 - Bonds:
Secured Medium Term Notes $800,000,000 695,000,000 785,640
(Premium)50,220
Pollution Control Revenue Bonds:
6% Series due 2023 100 000 345,385
Colstrip 1999A due 2032 66,700,000 182,462
(Premium)334,000
Colstrip 1999B due 2034 17,000,000 565,288
(Premium)340,000
SUBTOTAL 782,800,000 10,602,995
Acct. 222 - Reacquired Bonds
Acet. 223 - Advances from Associated Companies 434,151
Acet. 224 - Other Long-term Debt
Series K Preferred Stock 35,000,000 089,391
Notes Payable - Banks (local) $225,000,000 844,500
Commercial Paper
Unsecured Senior Notes 400,000,000 128,000
(Discount)716,000
Medium Term Notes $1 000,000,000 683,000,000 197 873
(Premium)70,000
Long Term Curent
Notes Payable to Various Parties
Preferred Trust Securities 61,855,675 960,160
Preferred Trust Securities 51,547 000 633,783
TOTAL 015,636,826 43,242,702
FERC FORM NO.1 (ED. 12-96)Page 256
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
LONG-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 u~tstan9ln LineNominal Date Date of (Total amount outs18n ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount(d)(e)(f)
(g)
reSP?~dent)
(i)
343,500,000 23,245,436
12/18/1984 12/01/2014 12/18/1984 12/01/2014 100,000 246 000
9/01/1999 10/01/2032 9/01/1999 10/01/2032 66,700,000 335,000
9/01/1999 3/01/2034 9/01/1999 3/01/2034 000,000 871,250
431 300,000 697,686
434 151
9/15/1992 9/15/2007 9/15/2 9/15/2007 500,000 926,148
000,000 1 ,875,425
4/03/2001 6/01/2008 4/03/2001 6/01/2008 317,682 661 32,278,503
147 350,000 086,472
01/23/1997 01/15/2037 01/31/1997 12/31/2036 61,855,675 871 134
06/03/1997 06/01/2037 06/30/1997 05/31/2037 547,000 120,911
122,669,487 856 279
fERC FORM NO.1 (ED. 12-96)Page 257
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) D A Resubmission 04/30/2004
RECONCILIATION OF REP( RTED 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 (uetans)Amount
No.(a)(b)
Net Income for the Year (Page 117)44,504,252
Taxable Income Not Reported on Books
948,277
Deductions Recorded on Books Not Deducted for Retum
81,079,648
Federal Income Tax 22,001 665
Deferred Income Tax 648,713
Investment Tax Credit 49,308
Income Recorded on Books Not Included in Return
677 ,099
Equity in Sub Earnings (Income) / Loss 156,784
Deductions on Retum Not Charged Against Book Income
88,791,664
Federal Tax Net Income 861,898
Show Computation of Tax:22,001,665
861 ,898 x .35 = 22,001 664.
FERC FORM NO.1 (ED. 12-96)Page 261
This Page Intentionally Left Blank
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004
TAXES ACCRUED, PREPAID AND CHARGED 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 theactual, 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.
rLine Kind of Tax BALANCE AT BEGINNING OF YEAR c1~xes d ~:m'Adjust-argeNo.(See instruction 5)Taxes Accru~9 -P-repaid Taxes ~nng
~~?g
ments(Account 236)(Include In Account 165)ear(a)(b)(c)(d)(e)(f)FEDERAL:
Income Tax (1989-1996)587,439
Income Tax (1997)
Income Tax (1998)37,912
Income Tax (1999)938,867 657 038 738,061
Income Tax (2000)097,901 977,090
Income Tax (2001)53,215,684
Income Tax (2002)943,426 902 269
Income Tax (2003)22,001 666 13,036,920 -40,703,033
Unemployment Ins 2003
FICA (2002)594 594
FICA (2003)165,370 167,363 594
Retained Earnings-ESOP
Retained Eamings-ESOP
Retained Earnings-ESOP 885,066 738,061
Retained Earnings-ESOP -419,065
Retained Eamings-ESOP 141 026
Retained 139,205
Retained 221 742
Total Federal 679,657 30,945,294 352 764 -40,703,033
STATE OF WASHINGTON:
Property Tax (2000 & Prior)485,660 19,484
Property Tax (2001)614
Property Tax (2002)964,632 247,137 717,350
Property Tax (2003)948,000
Excise Tax (2001)329,416
Excise Tax (2002)645,877
Excise Tax (2003)021,404 16,849,875
Gas Surcharge 737 8,434
Unemployment Ins. (2001)
Unemployment Ins. (2002)
Motor Vehicle (2002)
Motor Vehicle (2003)671 671
Total Washington 12,367 971 25,706,191 25,577 330
STATE OF IDAHO:
Income Tax (1997-2000)855,431 125,707
Income Tax (2001)085,967
Income Tax (2002)749,501
TOTAL 522,183 93,152 431 65,754,732 -40,678,826
FERC FORM NO.1 (ED. 12-96)Page 262
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmission 04/30/2004
TAXES ACCF UED, PREPAID AND CHARGED DURING 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
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through pa~oll 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 (I) only the amounts charged to Accounts 408.1 and 409.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 Re!.Other No.Acco~nt 236)(Incl. in Account 165)(Account 408., 409.(Account 409.Earnings (Account 439)(h)(i)(k)(I)
587,439
37,912
19,890
120 811
53,215,684
49,041,157
664 448 23,284,564 282,898
601 165,370
147 005
-419,065
141 026
139 205
221 742 221 742
430 847 23,284 564 660,730
466 176 128,213 147 697
614
143 142 637 104 500
948,000 778,000 170,000
329,416
645,877
171,529 11 ,659,421 361 983
697 737
671
12,496 830 18,422,997 283,194
981,138
085,967
749,501
241 055 187 950 25,964 481
FERC FORM NO.1 (ED. 12-96)Page 263
Name of Respondent This
wort
Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmission 04/30/2004
TAXES ACCRUED, PREPAID AND CHARGED 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.
r.,Kind of Tax BALANCE AT BEGINNING OF YEAR c1~xes d
~~~
Adjust-argeNo.(See instruction 5)1axes Accru~~Prepai.d Taxes ~e"a
~~?g
ments(Account 236)(Include In Account 165)(a)(b)(c)(d)(e)(f)
1 Income Tax (2003)705 593 428,090
Property Tax (2000 & Prior)383 251 173
Property Tax (2001)
Property Tax (2002)565,970 574 037
5 Property Tax (2003)5,427 496 724,004
Excise Tax (2000)056
Excise Tax (2001)54,473
Excise Tax (2002)135 616
Excise Tax (2003)86,203 76,340
Unemployment Ins. (2003)
Motor Vehicle Ins. (2003)048 048
Irrigation Credits (2002)751
KWH Tax (2002)41,502 955 26,547
KWH Tax (2003)398,793 332 789
Franchise Tax (2002)632,882 426,254 141,721
Franchise Tax (2003)345,440 615,046
Totalldaho 689,319 125,720 801,282
STATE OF MONTANA:
Income Tax (1996-2000)615,757
Income Tax (2001)186,912
Income Tax (2002)69,988
Income Tax (2003)384,870 378,554
Property Tax (1999)93,657 86,571
Property Tax (2000)-46,114
Property Tax (2001)454
Property Tax (2002)984,500 978,986
Property Tax (2003)139,704 075,236
Unemployment Ins (2002)
KWH Tax (2002)204 574 428 206,002
KWH Tax (2003)072,536 837,363
Motor Vehicle (2003)461 461
Consumer Council Tax 649 101
Public Commission Tax 869 875
Total Montana 549,590 688,088 480,578
STATE OF OREGON:
Income Tax (1995)207 24,207
Income Tax (1999)214 635
Income Tax (2000)158,916
TOTAL 22,522,183 93,152,431 65,754,732 -40,678,826
FERC FORM NO.1 (ED. 12-96)Page 262.
Name of Respondent This
wort
Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmission 04/30/2004
TAXES ACCRUED, PREPAID AND CHARGED DURING 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 adjustmentsby 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 (I) only the amounts charged to Accounts 408.1 and 409.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 Re!.Other No.Acco~nt 236)(Incl. in Account 165)(Account 408.1 , 409.(Account 409.Eamlngs (Account 439)
(h)(i)(k)(I)
277,503 705,593
251 556 18,155 233,018
067
703,492 558,200 869 296
056
54,473
751
863 118 085
048
730
955
66,004 398 793
585 299,306 126 948
730,394 564,806 780,634
013,757 792 134 333,586
615,757
186,912
69,988
316 384 870
086 86,571
-46,114
454
514
064,468 139,704
428
235,173 1 ,072 536
1 ,461
452 649
869
757 100 301 757 386,331
214,635
158,916
241,055 67,187 950 I 25,964,481
FERC FORM NO.1 (ED. 12-96)Page 263.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
TAXES ACCRUED, PREPAID AND CHARGED 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.
...
Ine Kind of Tax BALANCE AT BEGINNING OF YEAR c1~xes d
~~~
Adjust-No.(See instruction 5)arge1axes Accru~~~repai~ Taxes ~nng
~~?g
ments(Account 236)(Include In Account 165)ear(a)(b)(c)(d)(e)(f)
1 Income Tax (2001)854 485
Income Tax (2002)216,117
Income Tax (2003)160,362 140 209
Property Tax (1999-2000)55,143
Property Tax (2001)20,499
Proprty Tax (2002)-471 442 411 387
Property Tax (2003)1 ,288,345 542,695
Unemployment Ins. (2003)
Motor Vehicle (2003)277 277
Busn Energy Tax Credit -414 235
Busn Energy Tax Credit 34,243
Busn Energy Tax Credit 55,790
Busn Energy Tax Credit 63,885
Franchise Tax (2002)221,428 277,290 614 682
Franchise Tax (2003)1 ,793,430 578,524
Total Oregon 285,496 868,206 877,387 207
STATE OF CALIFORNIA:
Income Tax (1996-2000)158,423
Income Tax (2001)142 429
Income Tax 2002 26,863
Income Tax 2003 32,074 49,132
Property Tax (1999)128,479
Property Tax (2000-2001)906 358
Property Tax (2002)53,986 336
Property Tax (2003)268 114 533
Excise Tax (1999-2000)163
Excise Tax (2001)
Franchise Tax (2002)557 747
Franchise Tax (2003)329,878 390,726
California PUC Tax 137
California Gas Surcharge
California Use Tax 516 516
Total Califomia 676,806 474 713 554,769
STATE OF ARIZONA:
Income Tax (2001)-4,226 901
Total Arizona 226 901
TOTAL 22,522,183 93,152,431 65,754,732 -40,678 826
FERC FORM NO.1 (ED. 12-96)Page 262;2
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003
(2) Ei A Resubmission 04/30/2004
TAXES ACCRUED, PREPAID AND CHARGED DURING 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
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 (I) only the amounts charged to Accounts 408.1 and 409.
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 AoJustments to Ket.Other No.
ACCO
~BJ 236)
(Incl. in Account 165)(Account 408.409.(Account 409.Eamlngs (Account 439)
(h)(i)
(j)
(k)(I)
854,485
216,117
20,153 160,362
55,143
20,499
-60,055 411 387
254,350 695,082 593,263
277
-414 235
34,244
55,790
63,885 63,885
115,964 277,290
214 906 1 ,793,430
270,471 695,082 173,124
158,423
142,429
26,863
058 32,074
128,479
452 358
350 60,336
265 57,268
163
557 747
60,847 329,878
137
516
596,751 474,713
127
127
241,055 67,187 950 25,964,481
FERC FORM NO.1 (ED. 12-96)Page 263.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1 ) An Original (Mo, Da, Yr)
Dec. 31 2003(2) D A Resubmission 04/30/2004
TAXES ACCRUED, PREPAID AND CHARGED 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.
ILine Kind of Tax BALANCE AT BEGINNING OF YEAR ;haxes
~:~
Adjust-C argedNo.(See instruction 5)Taxes Accru~~Prepai~ Taxes
~~g
~ring ments(Account 236)(Include In Account 165)ear(a)(b)(c)(d)(e)(f)STATE OF TEXAS
Unemployment Ins (2003)
Total Texas
STATE OF KENTUCKY
Unemployment Ins (2003)
Total Kentucky
STATE OF VIRGINIA
Unemployment Ins (2003)
Total Virginia
STATE OF WYOMING
Unemployment Ins (2003)
Total Wyoming
STATE OF FLORIDA
Unemployment Ins (2003)
Total Florida
STATE OF NEW YORK
Unemployment Ins (2003)
Total New York
COUNTY & MUNICIPAL
Occupation 848,569 15,414 218 15,070,666
Forrest Fire Protection
Greenacres Irrigation
City of Spokane PBIA 858
WA Dept of Natural
Spokane Utility Tax 970 17,765
Misc.969 16,432
Total County 848,562 15,344 219 15,105,721
STATE OF ILLINOIS
Unemployment Ins. 2003
Total Illinois
STATE OF UTAH
Unemployment Ins. 2003
Total Utah
TOTAL 522,183 93,152,431 65,754 732 -40,678,
FERC FORM NO.1 (ED. 12-96)Page 262.
Name of Respondent This
wort
Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
TAXES ACCRUED, PREPAID AND CHARGED DURING 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
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 (I) only the amounts charged to Accounts 408.1 and 409.
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 AOJustmentS to Ke!.Other No.
ACCO
~SJ 236)
(Incl. in Account 165)(Account 408., 409.(Account 409.Earnings (Account 439)
(h)(i)
(j)
(k)(I)
192 123 10,712,460 701 758
858
205 970
104,408 39,014 -48,955
087,062 10,691 416 652,803
241,055 187 950 25,964,481
FERC FORM NO.1 (ED. 12-96)Page 263.
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
ACCUMULA ED DEFERRED INVESTMENT TAX I REDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and
non utility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i)
the average period over which the tax credits are amortized.
Line Account tSalance at Beginning Deferred for Year AI!ocatJons to
No.SUbd
l~~sions
of Year Current Year's Income Adjustments(c) (d) (e) (f)
Electric Utility
10%
TOTAL
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
Gas Propertry (10%)669,576 1411.49,30a
TOTAL PROPERTY 669,576 49,30f
FERC FORM NO.1 (ED. 12-89)Page 266
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
ACCUMULATED DEFERRED INVESTMENT TAX CRED TS (Account 255) (continued)
Balance at End Avera~e penOd ADJUSTMENT EXPLANATION Line
of Year of AI ocation No.to Income
620,268
620,268
FERC FORM NO.1 (ED. 12-89)Page 267
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
0 HER DEFFERED CREDITS (Account 253)
1. Report below the particulars (details) called for concerning C?ther 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
(a)(b)Account
(f)(c)(d)(e)
Uneamed Interest - Customer
wiring & conversions 253.059 419 938 231 352
Deferred revenue prepayment -
Pacific Walla Walla/Enterprise
Amort = 19 yrs 253.60,918 456 372 546
CIT Oper Lease 253.09, 9/2006 931 19,638 127,649 108,011
BPA C&RD Receipts 253.65,700 394,200 394,380 65,880
Trust Fund - Centralia 253.890,418 186 553 224 893,089
Rathdrum Refund 253.577 798 550 33,822 543,976
Amort =25 years, through 1/2020
Supplemental Executive 12,541 ,399 426, 228 363,362 023,358 201 395
Retirement Plan 253.
Gain on Sale and leaseback 353,104 985 261 456 091 648
, of Building (Amortization period
is 25 years) 253.85 & 253.
ID Clark Fork Relicensing 253.391 ,349 419 538,018 511,824 -417 543
Deferred Camp. 253.90,91,11,647 780 131 930 322,499 881 508 206,789
FAS5 Mark to Market 253.951 579 186,557 34,975,345 38,285,172 261 406
TOTAL 29,705 406 38,934,203 43,237 346 008,549
FERC FORM NO.1 (ED. 12-94)Page 269
This Page Intentionally Left Blank
Name of Respondent
Avista Corp.
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
ACCUMULATED DEFFERED INCOME TAXES - OTHER 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.
Year of Report
Dec. 31 2003
Line
No.
CHANGES DURING YEAR
Account Balance at
Beginning of Year
(a)(b)
Amounts Debited
to Account 410.
(c)
Amounts Credited
to Account 411.
(d)
1 Account 282
2 Electric
3 Gas
4 General Common
5 TOTAL (Enter Total of lines 2 thru 4)
6 Non-operating
9 TOTAL Account 282 (Enter Total of lines 5 thru
10 Classification of TOTAL
11 Federal Income Tax
12 State Income Tax
166 886,421
36,997 495
713,914
215,597 830
391 875
786,348
097,793
819,604
064 537
299
217,989,705 067 836
211,443,459
546,246
248,540
819,297
13 Local Income Tax
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
Name of Respondent
Avista Corp.
Year of Report
Dec. 31 2003
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.(e) (f)
ADJUSTMENTS
(h)
Credits Balance at Line
Account Amount End of Year No.
Debited
(j)
(k)(i)
26,184,198,857
807 47,903,
971,15,865,
38,963,262,626,
395,
Debits
Account
Credited
(g)
Amount
NOTES (Continued)
fERC FORM NO.1 (ED. 12-96)Page 275
Name of Respondent
Avista Corp.
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
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.
Year of Report
Dec. 31 2003
1 Account 283
2 Electric
Electric
, , , , "- '
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
. mounts re.,te.
to ACCOltflt 411.
Line
No.
Account
(a)
. mounts Ie., e.
to Acco
fc~t 410.
123,350,947 650,797 508,356
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
11 Gas
123,350,947 650,797 508,356
507 178 096,825
17 TOTAL Gas (Total of lines 11 thru 16)
18 Other
19 TOTAL (Acet 283) (Enter Total oflines 9, 17 and 18)
20 Classification of TOTAL
507 178
133,359,117
262,217 242
096,825
-49,452
797 074 508,356
21 Federal Income Tax
22 State Income Tax
23 Local Income Tax
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
Name of Respondent
Avista Corp.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
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.
Year of Report
Dec. 31 2003
ADJUSTMENTS
Balance at Line
End of Year No.
(k)
703,177 182.719,868 118,175,103
182.737,254 737,254
703,177 1,457,122 117 437 849
79,869 490,222
79,869 490,222
182.681 869 182.737 254 127 365,050
783,046 138,991 737,254 248,293,121
" "'. ." "....,.
201
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 277
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) nA Resubmission 04/30/2004
0 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
(d)(e)(a)(b\(c)
Centralia Sale 254.11, 028 & 038 407.763,806 674 973
FAS 109 - Accounting for Income Taxes 254.190.26,556 334 020
Nez Perce - Regulatory liability 254.186.80/557.22,008 880,436
BPA Residential Exchange 254.45,028 407.145,930
BPA Residential Exchange 254.45, 038 407.45,835 16,333
BPA Residential Exchange 254.45, 098 182.1 ,679,445 679,445
Mark to Market FAS133 - Reg Liab 254.176.74/245.83,976,277 154,171 442,499
TOTAL 85,980,412 78,833,616 13,027 706
FERC FORM NO.1 (ED. 12-94)Page 278
This Page Intentionally Left Blank
Name of Respondent
Avista Corp.
Year of Report
Dec. 31 2003
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
ELECTRIC OPERATING REVENUES (Account 400)
1. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
2. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that
where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The
-average number of customers means the average of twelve figures at the close of each month.
3. If increases or decreases from previous year (columns (c),(e), and (g)), are not derived from previously reported figures, explain any
inconsistencies in a footnote.
(a)
OPERA TI NG REVENUES
Amount for Year Amount for Previous Year(b) (c)
Line
No.
Title of Account
1 Sales of Electricity
(440) Residential Sales
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)
5 Large (or Ind.) (See Instr. 4)
6 (444) Public Street and Highway Lighting
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers
11 (447) Sales for Resale
12 TOTAL Sales of Electricity
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Provo for Refunds
201 339,021
78,276,186
769,419
194 732,477
68,096 108
682 491
864,929
490,032,903
652 692
564,685,595
900,386
464,567,616
64,082,272
528,649,888
564,685,595 528 649,888
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Property
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues
523,157
453,494
259,685
532,286
58,862
992,663
84,189,519 52,907 304
26 TOTAL Other Operating Revenues
27 TOTAL Electric Operating Revenues
87,425,855
652 111,450
55,491,115
584,141,003
FERC FORM NO.1 (ED. 12-96)Page 300
Name of Respondent
Avista Corp.
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
ELECTRIC OPERATING 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,and 6, see Page 304 for amounts relating to un billed revenue by accounts.
7. Include unmetered sales. Provide details of such Sales in a footnote.
Year of Report
Dec. 31, 2003
Amount for Year
(d)
MEGAWATT HOURS SOLD
Amount for Previous Year
(e)
AVG.NO. CUSTOMERS PER MONTH
Number for Year Number for Previous Year
919,430
785,093
25,281
836,717
519,104
25,163
36,279
414
422
35,910
420
413
13,503 097
041,166 598,029 321 678 317,548
075,245 215,545
10,116,411 813,574 321,725 317 594
10,116,411 813,574 321 725 317,594
Line 12, column (b) includes $
Line 12, column (d) includes
019,461
43,407
of unbilled revenues.
MWH relating to unbilled revenues
FERC FORM NO.1 (ED. 12-96)Page 301
Line
No.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) II A Resubmission 04/30/2004
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 percustomer, 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," Page300-301. 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 un billed revenue as of end of year for each applicable revenue account subheading.
Line NumDer anOTItle oTRate scneaule Mvvn ~ola Revenue Average Wumcer ~vvn oT5"'aTes ~WR~efcterNo.(a)(b)(c)of Cus~omers Per cr~stomer
(f)RESIDENTIAL SALES (440)
1 Residential Service 183,786 189,699,823 272,406 688 0596
2 Residential Service
3 Residential Service
12 Res. & Farm Gen. Service 49,698 620 257 615 169 0930
15 MOPS II Residential
22 Res. & Farm Lg. Gen. Service 879 707 201 398,271 0612
30 Pumping-Special
32 Res. & Farm Pumping Service 10,858 716,839 406 723 0660
48 Res. & Farm Area Lighting 300 901 495 1701
49 Area Lighting-High-Press.266 56,93~2141
56 Centralia Refund
95 Wind Power 090
72 Residential Service
73 Residential Service
74 Residential Service
76 Residential Service
77 Residential Service
58A Tax Adjustment 34,247
58 Tax Adjustment 234 05~
SubTotal 277 787 202,999 460 283,497 562 0619
Residential-Unbilled 20,072 783,888 0889
Total Residential Sales 297 ,85~204,783,348 283,497 633 0621
COMMERCIAL SALES (442)
2 General Service
3 General Service
11 General Service 555,93S 48,220,711 30,728 18,092 0867
13 MOPS II Commercial
16 MOPS II Commercial
19 Contract-General Service
21 Large General Service 945,717 125,649 679 725 411,792 0646
25 Extra Lg. Gen. Service 325,900 13,865,111 29,627,273 0425
28 Contract-Extra Large Serv 195 144 195,000 0403
31 Pumping Service 58,198 416,069 814 496 0587
47 Area Lighting-Sod. Vap 442 111 370 1493
49 Area Lighting-High-Press.113 351 200 1662
56 Centralia Refune
95 Wind Power 14,760
74 Large General Service
TOTAL Billed 10,073,0Q41 560,666,134 321,0557Total Unbilled Rev.(See Instr. 6)43,401 019,461 092
TOTAL 10,116,411 564,685,595 321,72E 44-:1 0558
FERC FORM NO.1 (ED. 12-95)Page 304
Name of Respondent This (!)ort Is:Date of Report Year of Report
Avista Corp.(1 ) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
SALES OF ELECTRICITY BY RATE SC HEDULES
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 un billed revenue as of end of year for each applicable revenue account subheading.
Line NumDer ana IlIIe or Kate scneoUie Mvvn :)ola Kevenue Average NumDer ISwl1..or ~ales ~WW~olderNo.(a)(b)(c)of c~~)omers Per ~~stomer
(f)
1 75 Large General Service
76 Large General Service
77 General Service
58A Tax Adjustment 23,552
58 Tax Adjustment 645,983
SubTotal 896,504 199,299,479 36,279 79,840 0688
7 Commercial-Unbilled 22,926 039,542 0890
8 Total Commercial 919,430 201,339,021 36,279 80,472 0690
INDUSTRIAL SALES (442)
2 General Service
3 General Service
8 Lg Gen Time of Use
11 General Service 955 540,282 255 23,353 0907
16 MOPS II Industrial
21 Large General Service 205,359 12,961 142 215 955,158 0631
25 Extra Lg. Gen. Service 439,814 58,765,053 59,992,250 0408
28 Contract - Extra Large Service 803 406,888 1070
29 Contract Lg. Gen. Service 42,946 42,946,000
30 Pumping Service - Special 25,185 255 879 599,643 0499
31 Pumping Service 56,184 364,353 718 78,251 0599
32 Pumping Svc Res & Firm 131 299,306 159 32,270 0583
47 Area Lighting-Sod. Yap.258 33,587 1302
49 Area Lighting - High-Press 398 1510
56 Centralia Refund.
72 General Service
73 General Service
74 Large General Service
75 Large General Service
76 Pumping Service
77 General Service
58A Tax Adjustment 861
58 Tax Adjustment 447,128
SubTotal 784,684 78,080,155 414 262,153 0438
Industrial-Unbilled 409 196,031 4793
Total Industrial 785,093 78,276,186 414 262,442 0438
STREET AND HWY LIGHTING (444)
6 Mercury Vapor St. Ltg.
7 HP Sodium Vap. St. Ltg
TOTAL Billed 10,073,004 560,666,134 321,725 306 055
Total Unbilled Rev.(See Instr. 6)43,407 019,461 092
TOTAL 10,116,411 564,685,595 321 725 444 055S
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmission 04/30/2004
SALES OF ELECTRICITY BY RATE SC HEDULES
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 reportedcustomers.
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.
I Line Numcer ana I IDe Of Kate scneaule Mvvn ~ola Kevenue Average Numcer ~vvn. Of ~ales ~W~~olderNo.(a)(b)(c)of C~~\omers Per ~~stomer
(f)
11 General Service 158 440 320 0914
41 Co-Owned St. Lt. Service 320 48,124 18,824 1504
42 Co-Owned St. Lt. Service 18,215 120,860 292 62,380 2262
High-Press. Sod. Vap.
43 Cust-Owned St. Lt. Energy 127 708 42,333 0922
and Maint. Service
44 Cust-Owned St. Lt. Energy 738 79,607 24,600 1079
and Maint. Svce - High-Pres
Sodium Vapor
45 Cust. Owned St. Lt. Energy Svc 927 135,009 146,350 0461
46 Cust. Owned St. Lt. Energy Svc 796 194,037 79,886 0694
56 Centralia Refund
58 Tax Adjustment 165,634
SubTotal 25,281 769,419 422 59,908 1887
Street & Hwy Lighting-Unbilled
Total Street & Hwy Lighting 25,281 769,419 422 59,908 1887
OTHER SALES TO PUBLIC
(445)
None
INTERDEPARTMENTAL SALES 13,503 864,929 204,591 0641
58 Tax Adjustment
Totallnterdepartrnental 13,503 864,929 204,591 0641
SALES FOR RESALE (447)
61 Sales to Other Utilities (WA)908,420 68,625,588 50,221,579 0360
61 Sales to Other Utilities (ID)763 656,601 29,254,333 0303
61 Sales to Other Utilities (MT)79,062 370,503 13,177,000 0426
Total Sales for Resale 075,24E 74,652,692 154,149 0360
TOTAL Billed 10,073,560,666,134 321 31,055
Total Unbilled Rev.(See Instr. 6)43,40,019,461 092
TOTAL 10,116,411 564 685,595 321 725 444 055S
FERC FORM NO.1 (ED. 12-95)Page 304.
This Page Intentionally Left Blank
Name of Respondent ThiS iOrt Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2)A Resubmission 04/30/2004
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other thanpower exchanges during the year. Do not report exchanges of electricity (Le., transactions involving a balancing of debits and creditsfor energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on thePurchased 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 anyownership 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 (Le., thesupplier 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energyfrom third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets thedefinition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as theearliest 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 Lessthan 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" meansLonger than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing !,\vera AveracationTariff Number Demand (MW)Monthly NC Deman.Monthly CP emand
(a)(b)(c)(d)(e)(f)American Electric Power WSPP
BP Energy Company WSPP
Arizona Public Service WSPP
Benton County Public Utility District WSPP
Black Hills Power, Inc.WSPP
Bonneville Power Administration WSPP
Burbank, City of WSPP
Calpine Corporation WSPP
Cargill Power Markets, LLC WSPP
Chelan County PUD No.WSPP
Chelan County PUD No.Tariff 10
Clatskanie Peoples PUD WSPP
Cogentrix Energy Power Marketing, Inc.Tariff 9
Cogentrix Energy Power Marketing, Inc.Tariff 10
Subtotal RQ
Subtotal non-
Totai
FERC FORM NO.1 (ED. 12-90)Page 310
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmlssion 04/30/2004
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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the natureof 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 RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" 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.
5. For requirements RO 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximummetered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-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-RO grouping (see instruction 4), and then totaled onthe Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" 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)
39,600 319,100 319,100
600 340,950 340,950
280 194,410 194,410
318 85,405 85,405
210 83,655 83,655
941 591 990 591,990
800 000 32,000
360 133,700 133,700
390 188,365 188,365
650 650
612 669 12,669
13,616 542 914 542 914
418 51,418
075,245 115,124 64,785 647 751,921 652,692
075,245 115,124 64,785,647 751,921 74,652,692
FERC FORM NO.1 (ED. 12-90)Page 311
Name of Respondent This
mort
Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)
Dec. 31, 2003(2) 0 A Resubmission 04/30/2004
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 thanpower 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 anyownership 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 mustbe 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 lessthan 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 ofservice, 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" meansLonger than one year but less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing ~vera AveracationTariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
Conoco Phillips WSPP
Conoco Phillips Tariff 10
Constellation Power Source WSPP
Coral Power, LLC WSPP
Douglas County PUD No.WSPP
Dynegy Power Marketing Inc.WSPP
EI Paso Merchant Energy LP WSPP
Enmax Energy Marketing, Inc.WSPP
Enron Power Marketing Tariff 9
EPCOR Merchant & Capital US WSpp
Eugene Water & Electric Board WSPP
Franklin County PUD No.WSPP
Grant County PUD No.WSpp
Grant County PUD No.Tariff 10
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This Re IOrt Is:Date of Report Year of Report
Avista Corp.(1) ~ An Original (Mo, Da, Yr)Dec. 31 2003(2) A Resubmission 04/30/2004
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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the natureof 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 RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. EnterTotal" 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 underwhich service, as identified in column (b), is provided.
5. For requirements RO 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) 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 m. Explain in a footnote all components of the amount shown in column m. 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-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page401,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)
19,357 835,340 835,340
34,170 34,170
056 185,732 185,732
050 99,350 99,350
30,800 723,800 723,800
20,400 555,900 555,900
525 99,985 99,98~
419,094 419,094
143 73,944 73,944
655 124 720 124,720
646 19,090 19,090
887 308,456 308,456
250 250
075,245 115,124 64,785,647 751 921 652,692
075,245 115,124 64,785,647 751 921 74,652,692
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., 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 ( Le., transactions involving a balancing of debits and creditsfor 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 anyownership 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., thesupplier 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energyfrom third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets thedefinition 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 Lessthan 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" meansLonger than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing t\vera AveracationTariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
Grays Harbor County PUD No.WSPP
Hinson Power Company WSpp
IdaCorp Energy LP WSPP
Idaho Power Company WSPP
Idaho Power Company Tariff 10
J. Aron and Company WSPP
MIECO WSPP
Mirant Americas Energy Marketing LP WSPP
Mirant Americas Energy Marketing LP Tariff 9
Mirant Americas Energy Marketing LP Tariff 10
Modesto Irrigation District WSPP
Morgan Stanley WSPP
Northpoint Energy Solutions WSPP
NorthWestern Energy LLC WSPP
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31, 2003(2) 0 A Resubmission 04/30/2004
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 natureof 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 reportingyears. 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. EnterTotal" 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 RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter theaverage 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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-minuteintegration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) 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 0). Explain in a footnote all components of the amount shown in column 0). 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 onthe 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 Page401,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)
866 23,255 23,255
800 62,100 62,100
36,434 842,836 842,836
30,057 062,867 1 ,062,867
300 300
68,200 881,200 881,200
15,375 682 700 682,700
400 98,000 98,000
653 783 24,783
275,172 275,172
30,904 316,194 316,194
136 680 447 713 447,713
255 065 065
40,156 377 952 377,952
075,245 115,124 785,647 751,921 652 692
075,245 115,124 64,785,647 I 751,921 74,652,692
FERC FORM NO.1 (ED. 12-90)Page 311.
This Re ort Is:
(1) (X An Original
(2) r: A Resubmission
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 creditsfor energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on thePurchased 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 anyownership 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., thesupplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service mustbe 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energyfrom third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets thedefinition 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 Lessthan 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 isone 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.
I U - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" meansLonger than one year but Less than five years.
Name of Respondent
Avista Corp.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 NorthWestern Energy LLC
2 NorthWestem Energy LLC
3 Okanogan County PUD
Pacific Northwest Generating Coop
PacifiCorp
PacifiCorp
PacifiCorp
PacifiCorp
9 Peaker LLC
10 Pend Oreille Public Utility District
11 Pend Oreille Public Utility District
12 Pacific Gas & Electric Trading
13 Portland General Electric Company
14 Portland General Electric Company
Line
No.
Subtotal RQ
Subtotal non-
Total
IFERC FORM NO.1 (ED. 12-90)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Tariff 10
Tariff 9
Tariff 9
WSPP
194
WSPP
Tariff 10
Tariff 9
Tariff 9
Tariff 10
Tariff 9
WSPP
WSPP
Tariff 10
Page 310.
Date of Report
(Mo, Da, Yr)
04/30/2004
Year of Report
Dec. 31, 2003
AverageMonthly Billing
Demand (MW)
(d)
Actual Demand (MW)t'verage Avera~Monthly NCP Demanc Monthly CPLJemand(e) (f)
150 150
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) r1 A Resubmission 04/30/2004
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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the natureof 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-RO" 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 RO 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (50-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) 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 - RO" 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 ($)lineSoldDemand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)
(j)
(k)
384,721 384,721
672 294,755 294,755
300 300
810 005 005
800 128,500 915,232 043,732
32,626 295,527 1 ,295,527
23,840 23,840
883 187 571 187 571
284,482 284,482
307 248 307,248
810 139,923 83,033 222 956
84,975 275,544 275,544
149,834 540,703 540,703
12,100 12,100
075,245 115 124 64,785,647 751,921 652 692
075,245 115,124 64,785,647 751,921 74,652,692
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This or! Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31,2003(2) A Resubmission 04/30/2004
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., 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 ( Le., transactions involving a balancing of debits and creditsfor 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., thesupplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service mustbe 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 economicreasons 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 thedefinition 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 Lessthan 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 Actual Demand (MW)
Classifi-Schedule or Monthly illing Avera AveraNo.(Footnote Affiliations)cation Tariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
Powerex WSPP
P P L Montana WSPP
P P L Montana Tariff 10
P P L Montana Tariff 9
PPM Energy, Inc.WSPP
Public Service of Colorado WSPP
Puget Sound Energy WSPP
Puget Sound Energy Tariff 10
Puget Sound Energy Tariff 9
Rainbow Energy Marketing WSPP
Redding, City of WSPP
Sacramento Municipal Utility District WSPP
San Diego Gas and Electric WSPP
Seattle City Light WSPP
Subtotal RQ
Subtotal non-
Total
fERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This
wort
Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmission 04/30/2004
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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the natureof 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 RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. EnterTotal" 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 underwhich service, as identified in column (b), is provided.
6. For requirements RO 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (t) 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 0). Explain in a footnote all components of the amount shown in column 0). 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-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page401,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)(k)
126,930 692 952 692,952
13,804 472 182 472,182
172 435 172,435
430 669,897 669,897
15,996 539,324 539,324
101,173 662 728 662,728
106,520 858 137 858,137
10,600 10,600
315 857 469 857,46g
607 607
25,621 010,046 010,046
185,672 695,852 695,852
096 75,866 75,866
15,838 514,622 514,622
075,245 115,124 64,785,647 751,921 652 692
075,245 115,124 64,785,647 751,921 74,652,692
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004
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 thanpower exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and creditsfor energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on thePurchased 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 anyownership 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 (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service mustbe 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 economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energyfrom third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets thedefinition 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 Lessthan 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 isone 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" meansLonger than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Avera AveracationTariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(1)
Seattle City Light Tariff 10
Sempra WSPP
Sierra Pacific Power Company WSPP
Snohomish County PUD WSPP
Sovereign Power Tariff 10
Tacoma Power WSPP
Tacoma Power Tariff 10
TransAlta Energy Marketing WSPP
TransCanada Power, LP WSPP
Turlock Irrigation District WSPP
Williams Energy Services Company WSPP
IntraCompany Wheeling
IntraCompany Generation
Revenue Adjustment
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the natureof 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 RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. EnterTotal" 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 underwhich service, as identified in column (b), is provided.
5. For requirements RO 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximummetered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) 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 0). Explain in a footnote all components of the amount shown in column 0). 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-RO grouping (see instruction 4), and then totaled onthe Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" 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)
825 825
400 173,850 173,850
271 724 924 724 924
575 27,200 200
252 252
477 738 11,738
250 250
128,693 183,099 183,099
200 200
29,624 182 924 182,924
210,350 963,669 963,669
704,012 704,012
47,909 909
308 308
075,245 115,124 785,647 751 921 652 692
075,245 115,124 64,785,647 751,921 74,652,692
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
line Account ~mour~or Am.ount
-?/
No.urren ear PrevIous ear(a)(b)(c)
1. POWER PRODUCTION EXPENSES
A. Steam Power Generation
Operation
(500) Operation Supervision and Engineering 315,045 214 537
(501) Fuel 18,022,235 15,531 714
(502) Steam Expenses 530,452 815,779
(503) Steam from Other Sources 329 878
(less) (504) Steam Transferred-Cr.
(505) Electric Expenses 692,696 590 407
(506) Miscellaneous Steam Power Expenses 518,455 984,404
(507) Rents 15,952 042
(509) Allowances
TOTAL Operation (Enter Total of lines 4 thru 12)22,099,164 20,201,761
Maintenance
(510) Maintenance Supervision and Engineering 324,679 215,172
(511) Maintenance of Structures 457,588 328,872
(512) Maintenance of Boiler Plant 622,932 155 081
(513) Maintenance of Electric Plant 918,003 039,473
(514) Maintenance of Miscellaneous Steam Plant 645,474 419,137
TOTAL Maintenance (Enter Total of lines 15 thru 19)968,676 157 735
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)28,067,840 25,359,496
B. Nuclear Power Generation
Operation
(517) Operation Supervision and Engineering
(518) Fuel
(519) Coolants and Water
(520) Steam Expenses
(521) Steam from Other Sources
(less) (522) Steam Transferred-Cr.
(523) Electric Expenses
(524) Miscellaneous Nuclear Power Expenses
(525) Rents
TOTAL Operation (Enter Total of lines 24 thru 32)
Maintenance
(528) Maintenance Supervision and Engineering
(529) Maintenance of Structures
(530) Maintenance of Reactor Plant Equipment
(531) Maintenance of Electric Plant
(532) Maintenance of Miscellaneous Nuclear Plant
TOTAL Maintenance (Enter Total of lines 35 thru 39)
TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
C. Hydraulic Power Generation
Operation
(535) Operation Supervision and Engineering 186,028 232,213
(536) Water for Power 875,283 703,155
(537) Hydraulic Expenses 116 854 1 ,349,496
(538) Electric Expenses 538,901 090,333
(539) Miscellaneous Hydraulic Power Generation Expenses 543,939 472 905
(540) Rents 645,415 555,722
TOTAL Operation (Enter Total of lines 44 thru 49)906,420 403,824
FERC FORM NO.1 (ED. 12-93)Page 320
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) D A Resubmission 04/30/2004
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account &moun~or Am,ount for
No.urrent ear PrevIous Year(a)(b)(c)
C. HYdraulic Power Generation (Continued)
Maintenance
(541) Mainentance Supervision and Engineering 337 450 228,252
(542) Maintenance of Structures 343,717 169,868
(543) Maintenance of Reservoirs, Dams, and Waterways 118 240 735 000
(544) Maintenance of Electric Plant 165,789 829,645
(545) Maintenance of Miscellaneous Hydraulic Plant 125,567 23,460
TOTAL Maintenance (Enter Total of lines 53 thru 57)090 763 986,225
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)12,997,183 10,390,049
D. Other Power Generation
Operation
(546) Operation Supervision and Engineering 285,602 22,354
(547) Fuel 18,763,019 967,063
(548) Generation Expenses 522,242 28,531
(549) Miscellaneous Other Power Generation Expenses 264,491 276,750
(550) Rents 710,748 399,833
TOTAL Operation (Enter Total of lines 62 thru 66)546,102 13,694,531
Maintenance
(551) Maintenance Supervision and Engineering 222 940 173,413
(552) Maintenance of Structures 927 40,742
(553) Maintenance of Generating and Electric Plant 660 608 569,648
(554) Maintenance of Miscellaneous Other Power Generation Plant 137 168 93,323
TOTAL Maintenance (Enter Total of lines 69 thru 72)078,643 877 126
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)26,624 745 571,657
E. Other Power Supply Expenses
(555) Purchased Power 148,932 685 115,282,088
(556) System Control and Load Dispatchina 995,177 004,616
(557) Other Expenses 112,065,294 109,507,405
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)261 ,993,156 225,794,109
TOTAL Power Production Expenses (Total of lines 21, 41 , 59, 74 & 79)329,682 924 276,115,311
2. TRANSMISSION EXPENSES
Operation
(560) Operation Supervision and Engineering 785,068 054,685
(561) Load Dispatching 167,554 966,064
(562) Station Expenses 156,830 130,269
(563) Overhead Lines Expenses 108,887 112 411
(564) Underground Lines Expenses
(565) Transmission of Electricity by Others 079,188 441 228
(566) Miscellaneous Transmission Expenses 426,368 301,663
(567) Rents 115,042 115,440
TOTAL Operation (Enter Total of lines 83 thru 90)12,838 937 121 760
Maintenance
(568) Maintenance Supervision and Enaineering 254,349 138,292
(569) Maintenance of Structures 744 18,435
(570) Maintenance of Station Equipment 197,871 187 787
(571) Maintenance of Overhead Lines 695,328 114 217
(572) Maintenance of Underground Lines 235 929
(573) Maintenance of Miscellaneous Transmission Plant 882
TOTAL Maintenance (Enter Total of lines 93 thru 98)150,527 470,542
100 TOTAL Transmission Expenses (Enter Total of lines 91 and 99)14,989 464 13,592,302
101 3. DISTRIBUTION EXPENSES
102 Operation
103 (580) Operation Supervision and Engineering 640,714 675,982
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) Fi A Resubmission 04/30/2004
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account
&"riounVtor AfT\ount-?l
No.urrent ear PreVIous ear(a)(b)(c)
104 3. DISTRIBUTION Expenses (Continued)
105 (581) Load Dispatching 460
106 (582) Station Expenses 311,926 239,401
107 (583) Overhead Line Expenses 567 783 231,203
108 (584) Underground Line Expenses 300,982 312,694
109 (585) Street Lighting and Signal System Expenses 176,492 167,527
110 (586) Meter Expenses 164,956 135,102
111 (587) Customer Installations Expenses 320,525 274,263
112 (588) Miscellaneous Expenses 050,024 433,201
113 (589) Rents 256,605 363,061
114 TOTAL Operation (Enter Total of lines 103 thru 113)790,007 833,894
115 Maintenance
116 (590) Maintenance Supervision and Enaineering 578,690 443,722
117 (591) Maintenance of Structures 627 28,958
118 (592) Maintenance of Station Equipment 622,015 937,398
119 (593) Maintenance of Overhead Lines 770,736 338,769
120 (594) Maintenance of Underground Lines 850,600 733,271
121 (595) Maintenance of Line Transformers 557,428 552,653
122 (596) Maintenance of Street Lighting and Signal Systems 242,798 278,844
123 (597) Maintenance of Meters 38,467 25,643
124 (598) Maintenance of Miscellaneous Distribution Plant 748 147,033
125 TOTAL Maintenance (Enter Total of lines 116 thru 124)749,109 486,291
126 TOTAL Distribution Exp (Enter Total of lines 114 and 125)16,539,116 14,320,185
127 4. CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901) Supervision 76,029 113,629
130 (902) Meter Reading Expenses 493,943 320,981
131 (903) Customer Records and Collection Expenses 390,852 186,516
132 (904) Uncollectible Accounts 008,501 644,870
133 (905) Miscellaneous Customer Accounts Expenses 595,009 832,003
134 TOTAL Customer Accounts Expenses (Total of lines 129 thru 133)11 ,564,334 097 999
135 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation
137 I (907) Supervision
138 I (908) Customer Assistance Expenses 10,581,231 985,270
139 (909) Informational and InsUuctional Expenses 152,553 108,098
140 (910) Miscellaneous Customer Service and ,Informational ~xpenses 80,270 181,542
141 TOTAL Cust. Service and Information. Exp. (Total lines 137 thru 140)10,814,054 10,274,910
142 6. SALES EXPENSES
143 Operation
144 (911) Supervision 40,633 19,824
145 (912) Demonstrating and Selling Expenses 899,670 710,061
146 (913) Advertising Expenses 171,242 183,047
147 (916) Miscellaneous Sales Expenses 65,817 89,905
148 TOTAL Sales Expenses (Enter Total of lines 144 thru 147)177 362 002,837
149 7. ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920) Administrative and General Salaries 15,309,467 13,607 995
152 (921) Office Supplies and Expenses 503,451 494,412
153 I (Less) (922) Administrative Expenses Transferred-Credit 220 27,200
FERC FORM NO.1 (ED. 12-93)Page 322
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
ELECTRIC OPERATION AND MAINTENANCE E PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amou tforCurren Year
(b)
Name of Respondent
Avista Corp.
FERC FORM NO.1 (ED. 12-93)Page 323
Year of Report
Dec. 31 2003
AlT\ountJorPrevIous Year
(c)
501 ,442
175,457
217,511
754,944
975
700,522
529,025
846,203
624 746
770,878
250
043,080
595,763
417,298
44,158,610
683
646,755
614,878
43,162,705
220,646
379,256
432,146,510
010,632
46,173,337
373,576,881
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31, 2003(2) 0 A Resubmission 04/30/2004
~C~A~ED POWERJ.Accou~t 555)n u Ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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 (Le., 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 suppliers 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., 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 Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
American Electric Power WSPP
Arizona Public Service WSPP
Benton County PUD No.WSPP
Black Creek Hydro FERC #1
Black Hills Power WSPP
Bonneville Power Administration WNP#3 Agr.
Bonneville Power Administration SuplEntit Cap. 97
Bonneville Power Administration WSPP
Bonneville Power Administration NWPP
Bonneville Power Administration NWPP
Bonneville Power Administration WSPP
BP Energy Company WSPP
Calpine Corporation WSPP
Cargill Power Markets, LLC WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) :J A Resubmission 04/30/2004
....
nc udlng" powe~~~~8g~) (l;OntinUea)
. .., """. (
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (t)
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 0), 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
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.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.
Received Delivered
($)
~t~
($)
of Settlement ($)
(g)
(h)(i)
(j)
(I)(m)
34,60C 1,455, 16G 455,160
76C 190,56G 190,560
347 463,35G 463,350
794 231,00E 231 006
25E 21C 87,210
395,81-4 10,697,582 10,697 582
310 270 16E 166
13,562 13,562
68,915 68,840 20,165 20,165
372,898 372,898
93,09S 942 091 942 091
54.64S 12,480 279,492 291,972
80C 927, 10G 927 100
26,68~075,817 075,817
719.608 651,796 608,076 757,667 145 731 019 443,999 148,932,68E
FERC FORM NO.1 (ED. 12-90)Page 327
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmission 04/30/2004
PU~CHA~ED POWER ~Accou~t 555)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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 Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman!Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Chelan County PUD No.Rocky Reach
Chelan County PUD No.WSPP
Clatskanie Peoples PUD WSPP
Columbia Storage Power Exchange
Constellation Power Source WSPP
Douglas County PUD No.Wells
Douglas County PUD No.WSPP
Douglas County PUD No.297
EI Paso Merchant Energy LP WSPP
Enmax Energy Marketing, Inc.WSPP
EPCOR Merchant & Capital US WSPP
Eugene Water & Electric Board WSPP
Ford Hydro Limited Partnership PURPA Agmt
Franklin County PUD No.WSPP
Total
IFERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) D A Resubmission 04/30/2004
PU ~\,;t '
l1i
I-'r CCO
gR~~8g~J' (\,;ontinued)udmg' power ex ange)
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (t)
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 0), 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.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)
\t~
($)
of Settlement ($)
(g)
(h)(i)(I)(m)
148,53C 222,03~222,033
11 ,OO~444,80E 444,805
76f 101 81f 101,815
49~
11~1,471 ,35C 471 350
115,161 167,69E 167 698
40,94~789,267 789,267
188,065 187,988 727 500 727 500
60C 427 20CJ 427,200
12f 8,47CJ 470
01E 280,19~280 193
35C 173,28f 173,288
46E 213,31E 213,315
89f 329,26C 329,260
719,608 651 796 608,076 757,667 145,731,019 443,999 148,932,68f
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) D A Resubmission 04/30/2004
~C~A~ED POWERJ.Accou~t 555)
nc u 109 power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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 (Le., 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., 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 Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Grant County PUD No.Wanapum
Grant County PUD No.Priest Rapids
Grant County PUD No.WSPP
Grays Harbor County PUD No.WSPP
Haleywest LLC PURPA Agmt
Hydro Technology Systems PURPA Agmt
IdaCorp Energy LP WSPP
Inland Power & Light Company Mkt Tariff
J Aron and Company WSPP
Jim White PURPA Agmt
John Day Hydro PURPA Agmt
Klamath Falls, City of WSPP
Minnesota Methane PURPA Agmt
Mirant Americas Energy Marketing LP WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This 'OOort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)
Dec. 31 2003(2) 0 A Resubmission 04/30/2004~I cco
~8g~~, (l;ontinued)
. - .-. '
l1iiCfudmg' power ex ange)
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. 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 0), 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.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
275,04~139,54C 139,540
235,820 991,599 991 599
731 661,727 661,727
11,62S 483,88C 483,880
35,046 1 ,506,44~506,443
71C 255,20E 255,205
50C 49,01 E 49,015
40~403
66,80C 851 ,20C 851,200
1441 95,32./95,324
96~647 74,647
501 25,815 25,815
52~75,38~75,383
56C 519,69~519,693
719,608 651,796 608,076 757 667 145,731 019 443,999 148,932,68f
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31,2003(2) D A Resubmission 04/30/2004
~ED POWER rccou~t 555)n u '"g power exc anges
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., 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 tran~actions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - 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 Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Demanl Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Mirant Americas Energy Marketing LP 294
Mirant Americas Energy Marketing LP 294
Modesto Irrigation District WSPP
Morgan Stanley Capital Group WSPP
NorthWestern Energy LLC WSPP
Okanogan County PUD No.Okanogan PUD
Pacific Northwest Generating Co-op WSPP
PacifiCorp WSPP
PacifiCorp WSPP
PacifiCorp 160
PacifiCorp Power Marketing WSPP
Pend Oreme County PUD No.Pend Oreme PUD
Pend Oreme County PUD No.Generation Imbal
Pend Oreme County PUD No.NWPP
Total
fERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) r: A Resubmission 04/30/2004
PI ccou
~8g~:,
(continued)
~ ""
One udlng power exc ange )
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (t)
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 0), 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.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER 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)
(I)(m)
231 67C 670
555 968
17~95C 950
239,57~801,60C 801 600
79~974,67f 974 678
35,987 330,807 330,807
65CJ 353,57CJ 353,570
55,923 152,241 152,241
375 375
28,150 600 308,516 308,516
42,80f 1 ,655,36~655,365
73,92~614 123 614 123
543 012 21,622 21,622
14,060 11 ,523 85,352 85,352
719,608 651,796 608,076 757,667 145,731 019 443,999 148,932,68~
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
~C~A~ED POWERJ.Accou~t 555)nc u Ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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 useacronyms. 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 (Le., 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., 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.
as - 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 Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman!Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Phillips Ranch PURPA Agmt
Plummer Forest Products Generation Imbalan
Portland General Electric Company 304
Portland General Electric Company 178
Portland General Electric Company WSPP
Potlatch Corporation PURPA Agmt
Powerex WSPP
PPL Montana WSPP
Public Service of Colorado WSPP
Puget Sound Energy WSPP
Puget Sound Energy WSPP
Puget Sound Energy WSPP
Rainbow Energy Marketing WSPP
Seattle City Light WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31,2003(2) r: A Resubmission 04/30/2004
PU ,(l,;t CCOU
~\~8g~j' (l;ontinued)71"( udmgW power exc ange )
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. 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 0), 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.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No,Received Delivered \f/of Settlement ($)
(g)
(h)(i)(m)
40~402
071 759
293,105 294,905
183,83C 356,811 356,811
239,42S 1 0,344,48~10,344,482
62,65~661,86f 661 868
368,00S 13,106,430 13,106,430
15,11E 611 50E 611,506
69,14-:1 769,80~769,805
334 419 334 418
725 725
8,40C 292,50C 292,500
13,00~494,20~494,203
719,608 651 796 608,076 757,667 145,731,019 443,999 148,932,68~
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This Re ort Is:Date of Report Year of Report
Avista Corp.(1) ~ An Original (Mo, Da, Yr)Dec. 31 2003(2) A Resubmission 04/30/2004
~C~~ED POWERJ.Accou~t 555)n u '"g power ex anges
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., 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.
Une Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman!Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Seattle City Light WSPP
Sempra Energy Trading WSPP
Sheep Creek Hydro PURPA Agmt
Sierra Pacific Power Company WSPP
Snohomish County PUD No.WSPP
Sovereign Power Sovereign
Spokane, City of - Upriver Project PURPA Agmt
Tacoma Power WSPP
Tacoma Power WSPP
TransAita Energy Marketing WSPP
TransAita Energy Marketing WSPP
TransCanada Power LP WSPP
Turlock Irrigation District WSPP
Williams Energy Services Company WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
I-'U ~v, '
1inaJdMgYp~~~~.R8g~) (Gontinueo)
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, enterthe 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. 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 0), 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.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER 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)
(I)(m)
200 200
80C 046,70C 046,700
58C 482 651 482,651
80C 95,35C 95,350
10,454 377 16(377,160
66, 17~722,97i 722,977
26,99~1 ,056,53~1 ,056,533
825 825
48,71C 021,63E 021 638
285,281 787 261 478,158 38,265,419
24~242
30C 65C 650
23,57E 884,68C 884,680
719,608 651,796 608,076 757 667 145,731 019 443,999 148 932,68E
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent
Avista Corp.
This ~ort Is:(1) ~An Original(2) 0 A Resubmission
PUR ASED POWER IAccouot 555)line uding power excl'langes)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
Date of Report
(Mo, Da, Yr)
04/30/2004
Year of Report
Dec. 31 2003
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., 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
No.
Name of Company or Publie Authority
(Footnote Affiliations)
(a)
1 Wood Power Incorporated
2 IntraCompany Generation
3 IntraCompany Transfers
4 Other - Inadvertent Interchange
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
PURPA Agmt
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)Average Average
Monthly NCP Deman! Monthly CP Demand(e) (f)
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This (8Jort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
pt., '~I -
Ui ~I
~~.. -
)WE .
cco
~8g~) (Continued)nc u Ing po er ex ange
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (GO-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (GO-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
G. 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 0), 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.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Received Delivered
($)
of Settlement ($)
(g)
(h)(i)(I)(m)
391 ,992 391,992
47,909 909
43,022
158
719,608 651,796 608 076 757 667 145,731 OHJ 443,999 148,932,68E
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmission 04/30/2004
T . - .. ..oF ~I ....., t\1~11 T t:'YK U" r,1: t'\~ t~ccount 456)(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, i. eo, wheeling, provided for other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers.
20 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
, 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)
Avista Energy Northwestem Energy Chelan PUD
Avista Energy Bonneville Power Administration Chelan PUD
Avista Energy Northwestem Energy Bonneville Power Administration
Avista Energy Chelan PUD Idaho Power Company
Avista Energy Chelan PUD Northwestern Energy
Avista Energy Avista Corp Chelan PUD
Avista Energy Avista Corp Chelan PUD
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
Bonneville Power Administration Bonneville Power Administration Idaho Power Company
Bonneville Power Administration Bonneville Power Administration Idaho Power Company
Cargill Power Mkt Northwestern Energy Bonneville Power Administration
Cargill Power Mkt Northwestem Energy Pacificorp
Cargill Power Mkt Northwestern Energy Portland General Electric
Cargill Power Mkt Bonneville Power Administration Idaho Power Company
Cargill Power Mkt Northwestern Energy Puget Sound Energy
Consolidated Irrigation Bonneville Power Administration Consolidated Irrigation
Eugene Water Electric Northwestern Energy Bonneville Power Administration
TOTAl
FERC FORM NO.1 (ED. 12-90)Page 328
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) DA Resubmission 04/30/2004
OF j;;1 j;;CTRICITY FOR lJ I, '~I ,v .(JJ ccount ontinued)(Including transactions reffered to as 'wtieelinai
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 ofthe 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.Demandreported 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 LineSchedule of (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 Tn 570 57(J
FERC Elc Tn 199 19~
FERC Elc Tn
FERC Elc Tn 100 10C
FERC Elc Tn
FERC Elc Tn,359 35~
FERC Elc Tn,
FERC No.Various Various 610 508 610,50S
FERC Elc Tn 087 087
FERC Elc Tn 600 60C
FERC Elc Tn 024 0201
FERC Elc Tn,536 53E
FERC Elc Tri 800 80(
FERC Elc Tn,552 55~
FERC Elc Tn,164 164
FERC Elc Tn Bell Substation Consolidated 622 622
FERC Elc Tn,
216 040,560 040,56(
FERC FORM NO.1 (ED. 12-90)Page 329
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004
r EI,.EC' y ~~K ~ I .-. ,l~CCOUl1t 4:)0) (Gontlnueo)(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 0) 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)
11,540 11 ,540
512 512
101 101
200 200
203 203
023 023
814,010 814 010
752 752
690 690
139 139
132 132
600 600
104 104
377 377
32,582 376 89,958
11,177,097 26,100 124,914 11,328,111
FERC FORM NO.1 (ED. 12-90)Page 330
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
. 11\!.oF t:Ll;:,li I t'm.11 T t(,JK U J..-
. ~.
~ccount 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
, 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)
Grant County Public Utility District Grant County Public Utility Dist Grant County Public Utility Dist
Idaho Power Company Portland General Electric Idaho Power Company
Idaho Power Company Puget Sound Energy Idaho Power Company
Idaho Power Company Grant County PUD Idaho Power Company
Idaho Power Company Pacificorp Idaho Power Company
Idaho Power Company Idaho Power Company Bonneville Power Administration
Idaho Power Company Idaho Power Company Puget Sound Energy
Idaho Power Company Idaho Power Company Pacificorp
Idaho Power Company Idaho Power Company Portland General Electric
Idaho Power Company Bonneville Power Administration Idaho Power Company
Idaho Power Company Douglas PUD Idaho Power Company
Idaho Power Company Chelan PUD Idaho Power Company
Idaho Power Company Tacoma Idaho Power Company
Idaho Power Company Seattle City Light Idaho Power Company
Idaho Power Company Idaho Power Company Grant PUD
Idaho Power Company Bonneville Power Administration Idaho Power Company
Morgan Stanley Capital Group Northwestem Energy Portland General Electric
TOTAl
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)
Dec. 31 2003(2) 0 A Resubmission 04/30/2004
~r 8=1 t(~~11 y !-!JK \.!!'
.-. '- .
(/J ccount ontlnueo)(Including transactions reffered to as 'wfieeling
as - 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 LineSchedule of (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 No.Larson Substation Round Lk Coulee City 98,743 98,74~
FERC Elc Trf 32,009 32,005
FERC Elc Trf 15,831 15,831
FERC Elc Trf 22,295 22,29f
FERC Elc Trf,11,182 11,18~
FERC Elc Trf 520 52C
FERC Elc Trf,200 1 ,20G
FERC Elc Trf 200 20C
FERC Elc Trf,185 18E
FERC Elc Trf,231 467 231 467
FERC Elc Trf,13,655 13,65E
FERC Elc Trf 53,544 53,S4i1
FERC Elc Trf 280 28(
FERC Elc Trf,30,229 30,22~
FERC Elc Trf 450 45(
FERC Elc Trf 73,200 73,20G
FERC Elc Trf,762 762
216 040,560 O40,56CJ
fERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004t" FIl-l Y fgK '-? I, Mt:K~ l~ccoUr'!t 4bo) (l;ontinued)(Including transactions reffered to as 'wtieeling
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 ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
31,434 434
68,268 68,268
33,017 33,017
46,336 46,336
23,397 23,397
590 590
616 616
472 472
391 391
486,745 486,745
29,144 29,144
113,687 113,687
561 561
64,548 64,548
900 900
140 000 140,000
15,803 15,803
11,177,097 26,100 124,914 11,328,111
FERC fORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo. Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004I.-.. .oF~1 ~I,It(I~IIT t\,JKU..r:II=t(?J~ccount4~6)(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
, 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)
Morgan Stanley Capital Group Puget Sound Energy Idaho Power Company
Morgan Stanley Capital Group Bonneville Power Administration Idaho Power Company
Morgan Stanley Capital Group Northwestern Energy Chelan PUD
Morgan Stanley Capital Group Portland General Electric Idaho Power Company
Morgan Stanley Capital Group Grant PUD Idaho Power Company
Morgan Stanley Capital Group Northwestern Energy Idaho Power Company
Morgan Stanley Capital Group Northwestern Energy Puget Sound Energy
Morgan Stanley Capital Group Northwestem Energy Pacificorp
Morgan Stanley Capital Group Northwestern Energy Bonneville Power Administration
Morgan Stanley Capital Group Chelan PUD Idaho Power Company
Northwestern Energy Northwestern Energy Bonneville Power Adminstration
Northwestem Energy Northwestem Energy Portland General Electric
Northwestern Energy Northwestem Energy Chelan PUD
Northwestern Energy Northwestern Energy Puget Sound Energy
PacifiCorp PacifiCorp PacifiCorp
PacifiCorp Northwestem Energy PacifiCorp
PacifiCorp PacifiCorp Northwestern Energy
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004II OF J;;I I-f . I KIl,;l I Y FOR U I """(/J, ccourif ontinuec:1)(Including transactions reffered to as 'wtleeling
as - 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 ofthe 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 thedesignation 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.Demandreported 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 LineSchedule of (Subsatation or Other (Substation or Other Demand Yegawatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(i)
(j)
FERC Elc Trf,
FERC Elc Trf 220 22C
FERC Elc Trf,400 40C
FERC Elc Trf 400 40C
FERC Elc Trf,972 97~
FERC Elc Trf 144
FERC Elc Trf'256 25E
FERC Elc Trf 869 866
FERC Elc Trf 22,952 95~
FERC Elc Trf,498 49f
FERC Elc Trf,511 511
FERC Elc Trf 150 15c
FERC Elc Trf 441 441
FERC Elc Trf,520 52C
FERC No. 182 Lola-Walla Walla Dry Gulch 115/60 71,249 71,24g
FERC Elc Trf,124 60,12.4
FERC Elc Trf,10,317 10,317
216 040,560 O40,56(
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This fg)ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004JI ur 1"'1 1-1 ,I KI ;II Y FgR '-!
" .-. ':-"
l~ccount , ,- ontlnueo)(Including transactions reffered to as 'wIieeling
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 ($)Line
($)($)($)
(k+l+m)No.(k)(I)(m)(n)
163 163
12,024 12,024
815 815
663 663
036 036
325 325
16,869 16,869
11 ,805 805
074 074
096 096
111 111
321 321
735 735
105 105
295,926 295,926
131,651 131 651
22,135 22,135
11,177,097 26,100 124,914 11,328,111
IFERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004IN .oF ELI;.C- T ~9R u.. 1 1'" 'l~ccount 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
. 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)
Pacific Power Mkt Northwestem Energy Bonneville Power Adminstration
PPL Montana Grant County PUD Idaho Power Company
PPL Montana Northwestern Energy PacifiCorp
PPL Montana Northwestern Energy Portland General Electric
PPL Montana Northwestern Energy Chelan PUD
PPL Montana Northwestern Energy Grant County PUD OS '
PPL Montana PacifiCorp Northwestem Energy
PPL Montana Northwestern Energy Idaho Power Company
PPL Montana Northwestem Energy Puget Sound Energy
PPL Montana Northwestem Energy Bonneville Power Adminstration
PPL Montana Grant County PUD Northwestern Energy
PPL Montana Northwestern Energy Chelan PUD
PPL Montana Northwestern Energy PacifiCorp
PPL Montana Northwestern Energy Portland General Electric
PPL Montana Northwestern Energy Puget Sound Energy
Portland General Electric Northwestem Energy Portland General Electric
Portland General Electric Idaho Power Company Portland General Electric
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31,2003(2) D A Resubmission 04/30/2004
I -JI l.!r E~EC-I~~~II T t"!:JK \.!!
,....
'-1 ,(fJ CCOUl')t ontinuea)(Including transactions reffered to as 'wtleeling
as - 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 LineSchedule of (Subsatation or Other (Substation or Other Demand Megawan Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(i)
(j)
FERC Elc Trf 080 08C
FERC Elc Trf,140 14C
FERC Elc Trf,29,123 29, 12~
FERC Elc Trf 63,695 63,69E
FERC Elc Trf 706 70E
FERC Elc Trf,575 57E
FERC Elc Trf
FERC Elc Trf 611 611
FERC Elc Trf,32,118 11S
FERC Elc Trf,78,999 78,996
FERC Elc Trf 315 31E
FERC Elc Trf 312 31~
FERC Elc Trf,
FERC Elc Trf 072 11 ,07~
FERC Elc Trf,733 73~
FERC Elc Trf,984 984
FERC Elc Trf,4:2
216 040,560 O40,56~
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
11 . Ur .-.~,. iKICITY FQR
- "! ,
, "-"!'o' !ACCOunt 456) (Continued)(Including transactions reffered to as 'wtieeling
8. Report in column (i) and 0) 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 amountsin columns (i) and 0) 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 ($)TIne
($)($)($)
(k+l+m)No.(k)(I)(m)(n)
160 160
280 280
58,263 58,263
127 065 127 065
15,346 15,346
205 205
101 101
49,341 49,341
004 004
159,441 159,441
631 631
850 850
136 136
30,16S 30,168
997 997
980 980
11,177,097 26,100 124 914 11,328,111
FERC FORM NO.1 (leD. 12-90)Page 330.
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) r:; A Resubmission 04/30/2004
,OF FI 1-. . I ~I~II T ~9K u
, , ..-. '
t~ccount 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
, 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)
Powerex Northwestern Energy Bonneville Power Administration
Powerex Idaho Power Company Bonneville Power Administration
Powerex Bonneville Power Administration Idaho Power Company
Puget Sound Energy Northwestem Energy Puget Sound Energy
Rainbow Energy Mkt Grant PUD Northwestern Energy
Rainbow Energy Mkt Northwestem Energy Grant PUD
Seattle City Light Bonneville Power Administration Bonneville Power Administration
Seattle City Light Seattle City Light Seattle City Light
Sierra Pacific Power Bonneville Power Administration Idaho Power Company
Sierra Pacific Power Douglas PUD Idaho Power Company
Sierra Pacific Power Chelan PUD Idaho Power Company
Sierra Pacific Power Grant PUD Idaho Power Company
Sierra Pacific Power Portland General Electric Idaho Power Company
Sierra Pacific Power Seattle City Light Idaho Power Company
Sierra Pacific Power Tacoma Power Idaho Power Company
Sierra Pacific Power Northwestem Energy Idaho Power Company
Sierra Pacific Power Pacificorp Idaho Power Company
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
QF ~~~(;. . ":-' . T f9K
\.! ! ' ,...,
OJ ,(I~ c~unt ". ontinued)(Including transactions reffered to as 'wtleehng
as - 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 LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(i)
FERC Elc Trf 35,844 35,
FERC Elc Tn 100 10C
FERC Elc Trf,599 599
FERC Elc Trf 852 852
FERC Elc Trf 443 44J
FERC Elc Trf,400 40(J
FERCElc Trf,590 59(J
FERC No.Main CanallSmmrFalis Bell Substation 219,080 219,08(J
FERC Elc Trf,335,464 335,464
FERC Elc Trf,000 00(J
FERC Elc Trf 180,297 180,297
FERC Elc Trf,31,858 31,85S
FERC Elc Trf,15,224 15,224
FERC Elc Trf 19,397 19,397
FERC Elc Trf,10,896 10,89E
FERC Elc Trf,246 24E
FERC Elc Trf,17,850 17,85C
216 040,560 040,56(1
FERC FORM NO.1 (ED. 12.90)Page 329.
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
OF EI:,EC-I KI\,;II Y FOR ~ I Ht:K;:i !A ccoul1T 456) (Continued)(Including transactions reffered to as 'wtieeling
8. Report in column (i) and 0) 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, includingout of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the totalcharge 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 servicerendered.
10. Provide total amounts in column (i) through (n) as the last Line. Enter "TOTAL" in column (a) as the Last Line. The total amountsin columns (i) and m 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)
76,776 776
223 223
57B 578
14,714 714
946 946
800 800
811 865
102,780 102,780
758,355 758,355
16,192 16,192
399,876 399,876
71,576 576
33,97~33,975
46,457 46,457
25,383 25,383
12,208 12,208
39,714 39,714
11,177,097 26,100 124,914 11,328,111
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) D A Resubmission 04/30/2004
. -
. IN OF ELI;C-. t'm.~,'1 T ,:,YK ""
' '"" '
':" t~ccount 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
, 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)
Sierra Pacific Power Puget Sound Energy Idaho Power Company
City of Spokane City of Spokane Puget Sound Energy
Spokane Tribe of Indians Bonneville Power Administration Spokane Indian Tribes
Tacoma City Light Tacoma City Light Tacoma City Light
US Bureau of Reclamation Bonneville Power Administration East Greenacres
Xcel Energy Northwestern Energy Bonneville Power Administration
Xcel Energy Northwestem Energy Idaho Power Company
Xcel Energy Northwestern Energy Pacificorp
Xcel Energy Northwestern Energy Portland General Electric
Xcel Energy Northwestem Energy Puget Sound Energy
Xcel Energy Northwestem Energy Grant County PUD
Xcel Energy Bonneville Power Administration Northwestem Energy
Vaagen Brothers lumber Company Vaagen Brothers lumber Company Idaho Power Company
Various Various Various
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
l..!r ~I t-I .. I T t"YK '-! ! . .-. OJ ,(fJ ccount ontlnuea)(Including transactions reffered to as 'wIieeling
as - 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 ofthe 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.Demandreported 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 LineSchedule of (Subsatation or Other (Substation or Other Demand Megawan Hours MegaWan Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(i)
FERC Elc Trf 25,432 25,43~
FERC No.Sunset Trans. Line Westside Substation 125,698 125 69f
FERC No.Westside Substation Little Falls Substa.065 06f
FERC No.Main CanallSmmrFalis Bell Substation 219,080 219,08C
FERC No. 90.Bell Substation E Greenacres Irr 026 02E
FERC Elc Trf,30,212 30,21~
FERC Elc Trf,401 401
FERC Elc Trf,052 052
FERC Elc Trf,16,752 16,752
FERC Elc Trf,926 92E
FERC Elc Trf 200 20C
FERC Elc Trf,800 80C
FERC No.Colville Substation LoLo-Oxbow 230kv 26,100 26,10C
FERC Elc Trf,
216 040,560 O40,56~
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
If ,t" J::I t(1\,.I11 Y r-gK -: '
' .-. '
:- !ACCOUl1t 456) (l,;ontlnueo)
(Including transactions reffered to as 'wheeling
8. Report in column (i) and 0) 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, includingout 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 0) 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)
53,980 53,980
127,506 32,088 159,594
22,995 995
102,780 102,780
21,07f 157 29,235
61,976 61,976
080 080
12,331 12,331
34,616 34,616
10,043 10,043
411 411
600 600
488 26,100 23,216 116,804
11,177,097 26,100 124,914 11,328,111
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) n A Resubmission 04/30/2004
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le., 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 (t), 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 (t). Report in column (9) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero (") 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-~mana ~nergy ~mer Total Cost oftiourstioursCharresCharresCharresTrans~ssionReceivedDelivered(a)(b)(c)(d)(e)(f)
Bonneville Power Admin 705 705
Bonneville Power Admin 172,808 172,808
Bonneville Power Admin 134,710 134,710
Bonneville Power Admin 679,134 679,134
Bonneville Power Admin 132 132
Bonneville Power Admin 130,826 130,826
Bonneville Power Admin 536 536
Bonneville Power Admin 327 327 175 225
Bonneville Power Admin 10,839 10,839 38,800 310 490
Benton County PUD 296 296 582 573 991
Grant County PUD 10,129 129
Grant County PUD 529 529 157 157
Kootenai Electric Coop 32,112 32,112
NorthWestern Energy 27,232 232 99,062 126,901 225,963
Portland General Elec 142 142 703 323 026
Portland General Elec 585,368 585,368
TOTAL 59,128 59,12E 847,986 233,247 046 079,187
FERC FORM NO.1 (ED. 12-90)Page 332
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
TRANSMISSION OF ELECTRICITY BY OTHE ~S (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le., wheeling of electricity provided to respondent by other electric utilities, cooperatives, municipalities, orother 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 toWheeler" 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), providedemand charges. In column (e), provide energy charges related to the amount of energy transferred. In column (t), 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 allcomponents of the amount shown in column (t). Report in column (9) the total charge shown on bills rendered to the respondent. If nomonetary settlement was made, enter zero (") 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 bythe 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 OthersLosses, 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-Magawan-I)emana .t:;nergy ~tner Total Cost oftiourstioursCharresCharresCharresTranS~SSionReceIvedDelivered(a)(b)(c)(d)(e)(f)Puget Sound Energy 794 794 764 40,764
Seattle City Light 272 272
Snohomish PUD 800 800 13,200 13,200
Sierra Pacific 600 600 146 146
Tacoma Power 705 705 947 947
Tacoma Power 800 800 600 600
TOTAL 59,128 59,128 847 986 233,247 046 079 187
TOTAL 59,128 59,12f 847,986 233,247 046 079,187
FERC FORM NO.1 (ED. 12-90)Page 332.
Name of Respondent This tjort Is:Date of Rep'ort Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)
Dec. 31 2003(2) A Resubmission 04/30/2004
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line DeSCri~tion AmountNo.(b)
Industry Association Dues 223,218
Nuclear Power Research Expenses
Other Experimental and General Research Expenses
Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 90,691
Oth Expn ~=5,000 show purpose, recipient, amount. Group if c:: $5,000 777,895
Directors Fees and Expenses 220,059
Miscellaneous General Expenses (930.20)468,689
Community Relations (930.22)595,495
Educational-Informational (930.23)123,454
Other Miscellaneous General Expenses (930.29)230
Other Miscellaneous Labor (930.27 & 930.28)92,032
TOTAL 595.763
fERC FORM NO.1 (ED. 12-94)Page 335
Name of Respondent This '(!Jort Is:Date of Report Year of Report
Avista Corp.(1 ) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
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: (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other ElectricPlant (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 changesto 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.
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 Depreciation and Amortization Charges
Depreciation Amortization ofLineygreCiationExpense for Asset Limited Term Amortization of
No.Functional Classification xpense Retirement Costs Electric Plant Other Electric Total(Account 403)(Account 403.(Account 404)Plant (Ace 405)(a)(b)(c)(d)(e)(f)1 Intangible Plant 408,010 2,408,010
Steam Production Plant 435,683 11 ,435,683
Nuclear Production Plant
Hydraulic Production Plant-Conventional 386,128 386,128
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 462 767 450,004 912,771
7 Transmission Plant 311 668 311,668
8 Distribution Plant 15,636,268 15,636,268
9 General Plant 349 186 349,186
Common Plant-Electric 996,573 932,061 928,634
TOTAL 578,273 340 071 450,004 368,348
B. Basis for Amortization Charges
1. Amortization of Limited - Term Electric Plant - Account 404 includes:
(a) $8,050 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) $323,335 amortization of Noxon and Cabinet Relicense over 45 years.
(c) $12 189 amortization of contribution for construction of Sandcreek Substation.
(d) $18 446 amortization of Misc. Intangible Electric Plant pursuant to FERC order dated 6/16/1986, Docket #EC86-17-000 relating to Company's
contribution to the construction of the Sand Dunes - Taunton 115kv Transmission line in Grant County, WAin 1986.
(e) $3,430,668 amortization of software.
(f) $547,383 allocated portion of Amortization Leasehold Improvements from common plant.
2. Account 405 - Reflects amortization of the investment in settlement exchange power for WNP #3.
3. Plant balances listed in Section C, Column B are derived at by taking the beginning plant balance plus the ending plant balance divided by two.
4. "Applied Depreciation Rates (%)" listed in column e of Section C are an average of our Idaho and Washington rates.
5. A 9% Sinking Fund is in affect for our Hydro Plant Accounts that are broken out in Section C.
6. Cost of Removal is included in calculating the "Remaining Life" in Section C, column g.
FERC FORM NO.1 (REV. 12-03)Page 336
Name of Respondent This (!)ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31, 2003(2) D A Resubmission 04/30/2004
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclacle t:stlmatea Net Appllea Monallty Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(In Th
~~fandS)
Life (Perwnt)(per;rnt)r8e 1~~(a)(c)
STEAM PLANT
Colstrip No.
311 50,503 35.14.
312 73,061 35.14.
314 16,967 34.16.
315 070 35.-6.14.
316 643 34.15.
Subtotal 157,244
Colstrip No.
311 49,145 33.15.
312 45,127 34.-6.16.
314 921 31.17.
315 411 34.16.
316 036 32.16.
Subtotal 118,640
Kettle Falls
310 148 35.
311 258 33.14.
312 39,648 33.-4.17.
314 13,399 33.15.
315 10,274 34.-4.15.
316 444 33.16.
Subtotal 171
HYDRO PLANT
Cabinet Gorge
330 241 100.94.
331 467 75.48.
332 18,871 100.76.
333 27,178 60.51.
334 117 45.56.23.
335 396 45.
336 099 75.38.
Subtotal 71,369
Noxon Rapids
330 29,974 100.96.
IFERC fORM NO.1 (REV. 12-03)Page 337
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaole I:stlmatea Net Appllea MOrtality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining(In Th
~~fandS)~gr (Percent)(per;rnt)Y8e
~g~
(a)Cd)
331 11 ,095 75.60.
332 220 100.64.83.
333 042 60.54.
334 10,795 45.16.43.
335 611 45.21.
336 217 65.49.
Subtotal 116,954
Post Falls
330 732 100.84.
331 611 65.
332 055 90.85.
333 215 60.
334 846 40.11.
335 214 55.49.
Subtotal 10,673
Long Lake
330 418 100.74.
331 588 75.110.
332 16,506 95.43.
333 792 60.28.27.
334 616 45.122.13.
335 355 45.27.25.
Subtotal 275
Little Falls
330 217 100.82.
331 903 75.13.
332 990 95.63.
333 959 60.-4.12.
334 666 40.18.14.
335 137 55.27.
Subtotal 872
Upper Falls
330 100.66.
331 492 75.
332 287 95.14.50.
FERC FORM NO.1 (REV. 12-D3)Page 337.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
line uepreCiaDle ~stlmatea !'leI Appllea MOrtality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining(In Th
?~randS)
~~~
(Percent)(Per;rnt)r8e
~~~
fa)(d)
333 090 60.201.20.
334 776 45.30.
335 107 35.30.
Subtotal 816
Nine Mile
330 100.62.
331 922 75.12.62.
332 841 95.12.77.
333 9,461 60.18.58.
334 603 45.24.35.
335 282 55.44.
336 625 65.63.
Subtotal 28,745
Centralia-Skookumchuck
331 35.19.
332 35.27.
333 434 35.21.
334 35.18.
Subtotal 579
Monroe Street
331 147 65.31.65.
332 045 75.34.75.
333 01 a 60.32.61.
334 615 45.31.46.
335 45.35.46.
336 65.13.66.
Subtotal 28,899
OTHER PRODUCTION
Northeast Turbine
341 257 29.
342 146 29.
343 376 29.
344 595 29.
345 334 16.
346 241 29.
FERC FORM NO.1 (REV. 12-Q3)Page 337.
Name of Respondent This f!Jort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclalJfe t:stlmaTea Net ~pllea Mortality Average
No.Account No.Plant Base Avg. Service Salvage
~r
rates Curve Remaining
la\(In Th~~~andS)
~~~
(Perdfnt)r;rnt)r~e
~~~
Subtotal 13,952
Rathdrum
341
343 652
344 603
345 204
Subtotal 462
Kettle Falls CT
342
343 071
344
345
Subtotal 168
Boulder Park
341 714 , 5.
342 116
343
344 29,693
345 255
346
Subtotal 30,785
Coyote Springs 2
341 157
342 12,605
344 75,863
345 246
346 656
Subtotal 104,527
TRANSMISSION PLANT
350 703
352 990 50.34.
353 117,685 50.25.31.
354 065 75.00'52.
355 75,535 45.33.24.
FERC FORM NO.1 (REV. 12'()3)Page 337.
Name of Respondent This
wort
Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle I:stJmatea Nel Appllea MOnall1)'Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining(In Thousands)
~g~
(Percent)(per~nt)Y8e
~g~
(a)(b)(d)
356 64,733 55.36.
357 561 60.34.
358 318 60.34.
359 826 75.56.
Subtotal 297 416
DISTRIBUTION PLANT
361 10,083 50.10.32.
362 648 40.R1.27.
364 152,14g 45.31.
365 103,481 50.20.35.
366 47,685 60.10.49.
367 79,070 40.17.35.
368 119,218 40.10.23.
369 84,066 48.10.30.
370 23,980 35.10.21.
373 10,638 25.10.
373.4 Hi Press Sodium 396 20.10.13.
Subtotal 707,414
GENERAL PLANT
390.10 Struc & Improve 796 50.LO.37.
391.1 Camp Hardware 123 28.S1.12.
393 40.25.
394 705 20.10.12.
395 878 28.17.
397 18,362 12.10.
398 25.
Subtotal 25,965
MISC POWER
392 111
396 434
Subtotal 545
TOTAL COMPANY 870,472
FERC FORM NO.1 (REV. 12-Q3)Page 337.
This Page Intentionally Left Blank
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004
REGULA TORY COMMISSION EXPEN~ ES
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 years expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Line Description Assessed by Expenses Total . D~ferred
No.(Fumish name of regulatory commission or body the Regulatory Expense for In Account
Commission Current Year 182.docket or case number and a description of the case)Utility (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
FEDERAL ENERGY REGULATORY COMMISSION
FERC Cases Doc #s:CPO1-141 & 438 CP02-4,
CP03-31 & 32 RM96-1 RP99-518,RPO0-414 RP02-365
&455,RP03-7 ,41,70,95,272,403,404,436,483,501
556,573,574 577,597 & 600, RP 04-
16,23,28,31,51,82,85 & 86 150,208 425 157 633
WASHINGTON UTILITIES & TRANSPORTATION
Misc. Electric-Docket Is: 31914 31905,31797
31734,31619,31553,31408,31247,31176,31096,
31095,31031 ,30938,30937,30762,30751 ,30706,
30631 30608,30598,30596,30583 30449,30431
& 30348 578 571 331 472 910,043
Misc. Gas - Docket Is: 32148,31798,31735,31620
31590,31554,31631,31303,31253,31252,30829,
30763,30672,30632,30609,30599,30584,30432,
30349,30192,21639,21584,20575,20226 & 20218 287,300 228,802 516,102
IDAHO PUBLIC UTILITIES COMMISSION
Misc. Electric- Docket #s:AVU-03-AVUE-02-
A VU-03-1 ,A VU-03-2 ,A VU-03-4,A VU-03-
AVU-E-Q3-6, 8 & 9Advice Is: 03-01-E, & 03-02-
General Docket #: GNR-E-Q3-367,85S 264,988 632,846
Misc. Gas - Docket #s:AVU-03-1 & AVU-03-
Advice Is: 03-01-G & 03-02-143,493 99,303 242,796
OREGON PUBLIC UTILITIES COMMISSION
Docket Is: UM-734,UM-903,UM-1099,UM-1115,UG153
1154,AR-357 ,AR-452,AR-427 ,AR-428,UF-4198,
UF-4079, LC-35, UCR-35 Misc Advice #s: 03-
03-G (Suppl) & 03-4-214 606 265,172 479,778
CALIFORNIA PUBLIC UTILITIES COMMISSION
Rulemaking: 02.10.01.08.027 01.05.047
03.03.017 03.09.006,Resolutions: G3342,G3329,
G3303,Decisions: 02.01.040,02.07.033,01.06.010
O1.08.065,Advice #s: C-51-52-C-53-
54-C-55-G,56-G,57-G & C-58-G 47,022 79,882 126 904
TOTAL 789,058 277 044 066,102
FERC FORM NO.1 (ED. 12-96)Page 350
Name of Respondent
Avista Corp.
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
REGULATORY COMMISSION EXPENSES (Continued)
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (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.
Year of Report
Dec. 31 2003
EXPENSES INCURRED DURING YEAR
CURRENTLY CHARGED TOpartmen No.(f)
( )
(h)
AMORTIZED DURING YEAR
Deferred to
Account 182.
(i)
Contra
Account Amount
(k)
Deferred inAccount 182.
End of Year
(I)
Line
No.
Electric 0928 910,043
Electric 0928 157 633
Gas 1928 516,102
Electric 0928 632,846
Gas 1928 242,796
Gas 2928 479,778
Gas 2928 126,904
,..--..-......-.-......, -,..--...., _...."..",--,_.."_..,,..-
066,102
"""---'-"-""
FERC FORM NO.1 (ED. 12-96)Page 351
Name of Respondent
Avista Corp.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
DISTRIBUTION OF SALARIES AND AGES
Report below the distribution of total salaries and wage~ 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.
Year of Report
Dec. 31, 2003
(a)
Direct Payroll
Distribution
(b)
Total
(d)
Line
No.
Classification
Electric
Operation
Production
Transmission
Distribution
6 Customer Accounts
7 Customer Service and Informational
Sales
Administrative and General
10 TOTAL Operation (Enter Total of lines 3 thru 9)
11 Maintenance
12 Production
13 Transmission
14 Distribution
15 Administrative and General
16 TOTAL Maint. (Total of lines 12 thru 15)
17 Total Operation and Maintenance
18 Production (Enter Total of lines 3 and 12)
19 Transmission (Enter Total of lines 4 and 13)
20 Distribution (Enter Total of lines 5 and 14)
21 Customer Accounts (Transcribe from line 6)
22 Customer Service and Informational (Transcribe from line 7)
23 Sales (Transcribe from line 8)
24 Administrative and General (Enter Total of lines 9 and 15)
25 TOTAL Oper. and Maint. (Total of lines 18 thru 24)
26 Gas
27 Operation
28 Production-Manufactured Gas
29 Production-Nat. Gas (Including Expl. and Dev.
30 Other Gas Supply
31 Storage, LNG Terminaling and Processing
32 Transmission
33 Distribution
34 Customer Accounts
35 Customer Service and Informational
36 Sales
37 Administrative and General
38 TOTAL Operation (Enter Total of lines 28 thru 37)
39 Maintenance
40 Production-Manufactured Gas
41 Production-Natural Gas
42 Other Gas Supply
43 Storage, LNG Terminating and Processing
44 Transmission
45 Distribution
46 Administrative and General
47 TOTAL Maint. (Enter Total of tines 40 thru 46)
873,170
756,699
240,483
614 178
65,546
637,433
10,042,360
30,229,869
785,485
693,991
049,693
767,388
296,557
10,658,655
450,690
290,176
614,178
65,546
637,433
10,809,748
38,526,426
278,436
916,985
113,621
426,769
211,354
14,309,826
760,860
209,317
970,177
FERC FORM NO.1 (ED. 12-88)Page 354
Name of Respondent
Avista Corp.
This f3!eort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Year of Report
Dec. 31, 2003
Line
No.
Classification Direct PayrollDistribution
(b)
Total
(a)
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)
52 Storage, LNG Terminaling and Processing (Total of lines 31 thru
53 Transmission (Lines 32 and 44)
54 Distribution (Lines 33 and 45)
55 Customer Accounts (Line 34)
56 Customer Service and Informational (Line 35)
57 Sales (Line 36)
58 Administrative and General (Lines 37 and 46)
59 TOTAL Operation and Maint. (Total of lines 49 thru 58)
60 Other Utility Departments
61 Operation and Maintenance
62 TOTAL All Utility Dept. (Total of lines 25, 59, and 61)
63 Utility Plant
64 Construction (By Utility Departments)
65 Electric Plant
66 Gas Plant
67 Other (provide details in footnote):
68 TOTAL Construction (Total of lines 65 thru 67)
69 Plant Removal (By Utility Departments)
70 Electric Plant
71 Gas Plant
72 Other (provide details in footnote):
73 TOTAL Plant Removal (Total of lines 70 thru 72)
74 Other Accounts (Specify, provide details in footnote):
75 Stores Expense (163)
76 Preliminary Survey and Investigation (183)
77 Small Tool Expense (184)
78 Miscellaneous Deferred Debits (186)
79 Merchandising Expenses (416)
80 Non-operating expense (417)
81 Expenditures for Certain Civic, Political and Related Activit
82 Purchase and Stores Expense (980)
83 Transportation Expense (981)
84 Spokane Central Operating Facility Expense (985)
85 Clark Fork Relicensing (987)
95 TOTAL Other Accounts
96 TOTAL SALARIES AND WAGES
039,296
916,985
113,621
426,769
420,671
16,280,003 522,360 16,802,363
~--- ------- -'-,-~-,,-,_..,-,,---~---,.., .. ", '. ,. .... ,
54,806,429 995,916 56,802 345
19,329,103
884,317
414,368
402,353
20,743,471
286,670
~-----
25,213,420 816,721 27,030,141
770,753 20,467 750,286
61,430 944 374
832 183 19,523 812,660
194 194
62,990 11,092 898
29,320,078 32,244 29,352,322
571 571
700,514 148 741 662
185,648 575 186,223
311,920 294,532 17 ,388
1 ,374 834 355,150 19,684
768,951 764,030 921
442 298 -442,286
34,167 856
115,019 888
793,114 30,374 742
115,019,888
FERC FORM NO.1 (ED. 12-88)Page 355
Name of Respondent
Avista Corp.
This Report Is:
(1) IX) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2004
Year of Report
Dec. 31 2003
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 amortization for common utility plant classified by accounts asprovided 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.
1 & 2. Common Plant 1n Service and accumulated prov1s1on for depreciation
Acct. No.303 Intangible389 Land and Land Rights390 Structures and Improvements391 Office Furniture and Equipment392 Transportation Equipment393 Stores Equipment394 Tools, Shop and Garage Equipment395 Laboratory Equipment396 Power Operated Equipment397 Communications Equipment398 Miscellaneous Equipment
Total Common Plant
Const. work in Progress
Total Utility Plant
Acc.prov.for Dep. & Amort.
Net Utility Plant
Common Expenses allocated to Electric and Gas Departments:
Acct
901
902
903
903.90-99
904
905
907
908
909
910
911
$ 8,451,029
$ 1,562,682
$23,480,000
$26,256,101
$ 1,559,791
$ 855,103
$ 606,410
$ 769,932
$ 1,384,046
$11,350,264
$ 291,715
-------------
$76,567,074
$ 3,222,193
-------------
$79,789,267
$35,857,057
------------
$43,932,210
Description Total
Allocation To Allocation to
Gas Dept
Cust acct/collect supervision
Meter reading expenses
Cust reo & collectn expenses
AIR misc fees
Uncollectible Accounts
Misc oust acct expenses
Cust svc & info exp-supervision
Cust Assistance expenses
Info & instruct adver expenses
Misc oust serv & info expenses
Sales expense-supervis1on
144,925
916,000
11,294,294
311,870
607 087
1, 023, 125
90,167
193,128
127 284
64,431
FERC FORM NO.1 (ED. 12-87)Page 356
Elect Dept
76,029
469,586
153, 715
053,589
008,501
595,010
56,863
121,794
80,270
40,633
$68,896
446,414
140,579
258,281
598,586
428,115
33,304
71, 334
47,014
23,798
Basis of Allocation
# of oust ~ yr end
# of oust ~ yr end
# of oust ~ yr end
net direct plant
# of oust ~ yr end
# of oust ~ yr end
# of oust ~ yr end
# of oust ~ yr end
# of oust ~ yr end
# of oust ~ yr end
# of oust ~ yr end
Name of Respondent
Avista Corp.
This Report Is:
(1) (XI An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/30/2004
Year of Report
Dec. 31 2003
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 amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
912
913
916
920
921
922
923
924
925
926
927
928
929
930.
930.
931
935
403
404
Demo and selling expenses
Advertising expenses
Misc sales expenses
Admin & gen salaries
Office supplies & expenses
Admin expenses tranf-credit
Outside services employed
Property Insurance
InJuries and damages
Employee pensions & benefits
Franchise Requirement
Regulatory comm1ssion expenses
Duplicate charges-credit
General Advertising expenses
Misc general expenses
Rents
Maint of general plant
Depreciation
Amort of LTD term plant
426,598
271,537
118,070
20,959,682
650,068
(27,948)
10,295,497
241,083
275,113
33,220,536
23,699
293,009
591,710
714,814
477, 733
710,067
899,670
171,242
65,817
14,991,927
460,688
(22,221)
342,411
884,793
142,157
23,753,020
17,696
423,340
416, 944
768,998
996,573
932,061
526,928
100,295
253
967 755
189,380
(5,727)
953,086
356,290
132,956
467,516
6, 003
869,669
174,766
945,816
481,160
778,006
# of cust ~ yr end
# of cust ~ yr end
# of cust ~ yr end
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
Note 1:The four factor allocator is made up of 25% each-customer count, direct labor, direct O&M and
Net Direct Plant
Letters of approval received from staffs of State Regulatory Commiss1ons 1n 1993.
FERC FORM NO.1 (ED. 12-87)Page 356.
Name of Respondent
Avista Corp.
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2004
ELECTRIC ENERGY ACCOUNT
Report below the information called for conceming the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line
No.
Item
(a)
1 SOURCES OF ENERGY
2 Generation (Excluding Station Use):
3 Steam
4 Nuclear
5 Hydro-Conventional
6 Hydro-Pumped Storage
7 Other
8 Less Energy for Pumping
9 Net Generation (Enter Total of lines 3
through 8)
1 0 Purchases
11 Power Exchanges:
12 Received
13 Delivered
14 Net Exchanges (Line 12 minus line 13)
15 Transmission For Other (Wheeling)
16 Received
17 Delivered
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
FERC FORM NO.1 (ED. 12-90)
MegaWatt Hours
(b)
959,341
539,611
438,651
10,700,931
Page 401a
Line
No.
Item
(a)
21 DISPOSITION OF ENERGY
22 Sales to Ultimate Consumers (Including
Interdepartmental Sales)
23 Requirements Sales for Resale (See
instruction 4, page 311.
24 Non-Requirements Sales for Resale (See
instruction 4, page 311.
25 Energy Fumished Without Charge
26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
27 Total Energy Losses
28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
Year of Report
Dec. 31, 2003
MegaWatt Hours
(b)
041 166
075,245
664
576,856
10,700,931
This ~ort Is:(1) ~An Original(2) A Resubmission
MONTHLY PEAKS AND OUTPUT
1. If the respondent has two or more power systems which are not physically integrated, fumish 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 Respondent
Avista Corp.
Date of Report(Mo, Da, Yr)
04/30/2004
Year of Report
Dec. 31 2003
NAME OF SYSTEM:
Line Monthly Non-Requirments MONTHLY PEAKSales for Resale &No.Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(a)(b)(c)(d)(e)(f)
29 January 880,282 116,947 331 1800
30 February 845,163,094 345 0800
31 March 834,920 143,944 196 1900
32 April 884 722 262,507 159 2000
33 May 971 472 339,506 123 1700
34 June 038,509 384,175 256 1500
35 July 939,944 153,648 487 1700
36 August 860,590 118,265 400 1600
37 September 730,833 427 332 1700
38 October 799 440 85,874 323 1900
November 892,751 423 432 0800
40 December 021,883 157 435 509 1800
TOTAL 10,700,931 075,245
FERC FORM NO.1 (ED. 12-90)Page 401 b
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)2003(2) 0 A Resubmission 04/30/2004 Dec. 31
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 inthis page gas-turbine and internal combustion plants of 10,000 Kwor 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 attendmore 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 bumed (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than onefuel is bumed in a plant fumish only the composite heat rate for all fuels burned.
Line Item Plant Plant
No.Name: Coyote Springs Name: Spokane N.
(a)(b)(c)
Kind of Plant (Intemal Comb, Gas Turb, Nuclear Gas Turbine Gas Turbine
Type of Constr (Conventional, Outdoor, Boiler, etc)Not Applicable Not Applicable
Year Originally Constructed 2003 1978
Year Last Unit was Installed 2003 1978
Total Installed Cap (Max Gen Name Plate Ratings-MW)143.61.
Net Peak Demand on Plant - MW (60 minutes)269
Plant Hours Connected to Load 3202
Net Continuous Plant Capability (Megawatts)154
When Not Limited by Condenser Water
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh 396591000 996000
Cost of Plant: Land and Land Rights 129664
Structures and Improvements 7157487 256673
Equipment Costs 97370847 13406292
Asset Retirement Costs
Total Cost 104528334 13792629
Cost per KW of Installed Capacity (line 17/5) Including 728.4204 223.1817
Production Expenses: Oper, Supv, & Engr 260558 432
Fuel 15495035 68614
Coolants and Water (Nuclear Plants Only)
Steam Expenses
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 204358 112640
Misc Steam (or Nuclear) Power Expenses 447
Rents 28755
Allowances
Maintenance Supervision and Engineering 2244 95942
Maintenance of Structures 1055
Maintenance of Boiler (or reactor) Plant
Maintenance of Electric Plant 1013870 269751
Maintenance of Misc Steam (or Nuclear) Plant
Total Production Expenses 17004820 548881
Expenses per Net KWh 0429 5511
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas Gas
Unit (Coal-tons/Oil-barreIlGas-met/Nuclear -indicate)Met Met
Quantity (Units) of Fuel Bumed 2665217 10930
Avg Heat Cont - Fuel Burned (btuflndicate if nuclear)1019000 1019000
Avg Cost of Fuellunit, as Delvd f.b. during year 810 000 000 280 000 000
Average Cost of Fuel per Unit Burned 810 000 000 280 000 000
Average Cost of Fuel Burned per Million BTU 710 000 000 160 000 000
Average Cost of Fuel Burned per KWh Net Gen 039 000 000 069 000 000
Average BTU per KWh Net Generation 6848.000 000 000 11182.000 000 000
FERC FORM NO.1 (REV. 12.03)Page 402
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)2003(2) 0 A Resubmission 04/30/2004 Dec. 31
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant" Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclearsteam, hydro, intemal 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.
Cd)(e)(f)
Steam Steam Gas Turbine
Conventional Conventional Not Applicable
1983 1984 1995
1983 1985 1995
50.233.166.
224 140
8045 8594 252
222
366204000 1593135000 19436000
941300 1303915 484415
24538808 99726192 5643
65950674 177859188 4465084
1114206
92544988 278889295 4955142
1825.3449 1194.8984 29.7606
117231 58596
7016106 10959960 1842060
479564 1055217
640859 51895 284298
362586 1137676
15952 4681993
95544 227825 23965
91961 365816
928224 2694708
173173 744792 198290
219018 426457
10124266 17738894 7030608
0276 0111 3617
Wood Gas Coal Oil Gas
Tons Met Tons Bbl Met
539133 7486 1001532 3621 240847
8700000 1019000 17154000 140000 1019000
12.920 510 000 10.750 53.920 000 650 000 000
12.920 510 000 10.750 53.920 000 650 000 000
490 390 000 626 100 000 510 000 000
019 072 000 007 000 000 095 000 000
12832.000 12832.000 000 10806.000 10806.000 000 12627.000 000 000
FERC FORM NO.1 (REV. 12-03)Page 403
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)2003(2)0 A Resubmission 04/30/2004 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 bumed converted to Mct.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel bumed (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant fumish only the composite heat rate for all fuels bumed.
Line Item Plant Plant
No.Name: Boulder Park Name:
(a)(b)(c)
Kind of Plant (Internal Comb, Gas Turb, Nuclear Internal Comb
Type of Constr (Conventional, Outdoor, Boiler, etc)Conventional
Year Originally Constructed 2002
Year Last Unit was Installed 2002
Total Installed Cap (Max Gen Name Plate Ratings-MW)24.
Net Peak Demand on Plant - MW (60 minutes)
Plant Hours Connected to Load 958
Net Continuous Plant Capability (Megawatts)
When Not Limited by Condenser Water
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh 15237000
Cost of Plant: Land and Land Rights 144733
Structures and Improvements 724602
Equipment Costs 30119263
Asset Retirement Costs
Total Cost 30988598
Cost per KW of Installed Capacity (line 17/5) Including 1259.6991 0000
Production Expenses: Oper, Supv, & Engr 162
Fuel 903864
Coolants and Water (Nuclear Plants Only)
Steam Expenses
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 127344
Misc Steam (or Nuclear) Power Expenses
Rents
Allowances
Maintenance Supervision and Engineering 79310
Maintenance of Structures 39163
Maintenance of Boiler (or reactor) Plant
Maintenance of Electric Plant 205788
Maintenance of Misc Steam (or Nuclear) Plant
Total Production Expenses 1355631
Expenses per Net KWh 0890 0000
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas
Unit (Coal-tons/Oil-barreI/Gas-met/Nuciear-indicate)Met
Quantity (Units) of Fuel Bumed 146305
Avg Heat Cont - Fuel Burned (btulindicate if nuclear)1019000
Avg Cost of Fuel/unit, as Delvd f.b. during year 180 000 000 000 000 000
Average Cost of Fuel per Unit Bumed 180 000 000 000 000 000
Average Cost of Fuel Burned per Million BTU 060 000 000 000 000 000
Average Cost of Fuel Burned per KWh Net Gen 059 000 000 000 000 000
Average BTU per KWh Net Generation 9784.000 000 000 000 000 000
FERC FORM NO.1 (REV. 12-G3)Page 402.
Name of Respondent This ~rt Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)2003(2) 0 A Resubmission 04/30/2004 Dec. 31
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32
, "
Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data conceming 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)
0000 0000 0000
0000 0000 0000
000 000 000 000 000 000 000 000 000
000 000 000 000 000 000 000 000 000
000 000 000 000 000 000 000 000 000
000 000 000 000 000 000 000 000 000
000 000 000 000 000 000 000 000 000
FERC FORM NO.1 (REV. 12'()3)Page 403.
Name of Respondent
Avista Corp.
Year of Report
Dec. 31 2003
This f3!eort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/30/2004
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 plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 2545
Plant Name: Monroe Street
(b)
FERC Licensed Project No. 2545
Plant Name: Upper Falls
(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)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use ~ Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thN 19)
21 Cost per KW of Installed Capacity (line 20
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thN 33)
35 Expenses per net KWh
- "-"""""" "-"'-""""-----"---""""""""-,-,...,..,.....,.".............."..., """""-""""""'....--"...,...-..-....,..............,....,.,.., -..,.......".... "'--"""'-"-
Run-of-River
Conventional
1890
1992
14.
718
Run-of-River
Conventional
1922
1922
10.
677
98,517,000 66,569,000
146,667
045,079
12,662,096
50,448
28,904,290
952.9926
081 854
491 ,800
469,707
972,999
016,360
601.6360
16,030
872
207,274
46,690
985
180
27,154
676
311 891
0032
21,030
872
200,883
41,563
589
11,468
18,946
136
084
326,571
0049
FERC FORM NO.1 (REV. 12-03)Page 406
Name of Respondent
Avista Corp.
Year of Report
Dec. 31 2003
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/30/2004
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, intemal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2058
Plant Name: Cabinet Gorge
(d)
FERC Licensed Project No. 2058
Plant Name: Noxon Rapids
(e)
2545FERC Licensed Project No.
Plant Name: Long Lake
Storage
Outdoor
1952
1953
245.
250
760
Storage
Conventional
1915
1924
10.
197
Storage
Outdoor
1959
1977
466.
545
333
..~""".._, ,..---,-...,..."..---,.."..-..",--.....".... ,,".._, "",,.."",... ,..-..""..""'....""""""'..'" "",,- "",-,,,' ,..." ".. - ." ..., '" .' ". ,.". ....., .._,--...."....."..,_..""--" ---""'-"""""""-"'--"""""~"""""""""-""" ,
246
176
974,485,000
527
274
542,705,000 465,248,000
400,190
984,796
17,580,769
34,260,821
1 ,098,564
69,325,140
282.8443
30,923 726
11,090,542
31,673,879
45,109,027
217,199
119,014 373
255.2861
598,139
558,947
16,400,520
763,212
31,320,818
447.4403
80,596
730,363
717,085
39,489
14,395
124 317
122,711
449,145
23,658
301,759
0024
73,077
539
549,939
95,529
069
24,492
16,872
170,002
920
944,439
0020
162,209
50,471
739,349
753,785
45,387
36,047
157 802
452,121
772,629
63,166
232,966
0021
fERC FORM NO.1 (REV. 12..Q3)Page 401
Line
No.
Name of Respondent
Avista Corp.
Year of Report
Dec. 31, 2003
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/30/2004
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 plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 2545
Plant Name: Nine Mile Falls
(b)
FERC Licensed Project No. 2545
Plant Name: Post Falls
(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)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
1 0 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
....,.....-...,..,.."".."", ......,.. ,....,........-....--......, ......,...... --................-..--..,.......... ......,..-....--,......,-."....,........--,,---..,....-..-
Run-of-River
Conventional
1908
1994
26.
750
Storage
Conventional
1906
1980
14.
760
122,429,000 80,447,OQO
33,429
922 073
840,543
12,363,796
625,181
28,785,022
090.3417
076,554
611,288
054,643
275,383
11,017,868
744.4505
807
16,344
326,878
52,355
620
083
98,252
227,246
18,107
777,692
0064
17 ,967
13,285
867
337,197
38,505
123,866
606
248,691
227 090
370
1 ,025,444
0127
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent
Avista Corp.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/30/2004
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.
Year of Report
Dec. 31 2003
FERC Licensed Project No.
Plant Name: Little Falls
(d)
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
(e)
Run-of-River
Conventional
1910
1911
32.
092
,...,,---, """"""""""-""", -" ," "-,,--,, ,..." """""." ..- ., ,.. - ".." "".. ."" """""""" ",' '......",...",-"--,,-,,,,"" ,,,- ",...""""",.",..."" ..., """""""""""---""""""""-""....-...",...""""""",..."",.""",,""""""-.. ,...",-
189,211 000
0000 0000
0000 0000
325,371
902,086
989 819
725,381
15,942,657
498.2080
29,393
883
411 673
23,370
583,234
819
763
955
672
782
119,544
0059
FERC FORM NO.1 (REV. 12-Q3)Page 407.
Line
No.
Name of Respondent
Avista Corp.
Year of Report
Dec. 31, 2003
This l3!eort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/30/2004
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 plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
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)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
""----""""""""""""""""""""""'-"',..,..." ,.. ..... ,........_-_..,..,...."..,....,..,..-,........,-,-,......_..,..,..'...., , ,
0000 0000
0000 0000
FERC FORM NO.1 (REV. 12"()3)Page 406.
Name of Respondent
Avista Corp.
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) D A Resubmission 04/30/2004
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, intemal combustion engine. or gas turbine equipment.
Year of Report
Dec. 31, 2003
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
(d)(e)
_h"".."""",..""".",..."" """""
'-'-",-""",,-,........, ,"'--,..., " "-- "",-- ,.., -,- """""'_.
___"n"
_""""'-"""""-
",n_"" """"", " " """
"'-"'-"
"""h"""" .
, """"---"--"""""---""""""'--","--"""
""" -""""""""h"-"'_""'_h""'" ",
0000 0000 0000
0000 0000 0000
FERC FORM NO.1 (REV. 12-03)Page 407.
Line
No.
Name of Respondent This
wort
Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) D A Resubmission 04/30/2004
GENERATING PLANT STATISTICS (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.
Line Year Installed ca~aclty ~et pea~Net GenerationName of Plant Orig.Name Plate atinc Demand Excluding Cost of Plant
No.Const.(In MW)(6~a1n.Plant Use
(a)(b)(c)(e)(f)
Kettle Falls CT 2002 391,000 169,338
FERC FORM NO.1 (REV. 12-Q3)Page 410
Name of Respondent This
Mort
Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
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 withcombinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gasturbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset Operation PrOduction Expenses Fuel Costs (in cents LineRetire. Costs) Per MW Exc l. Fuel Fuel Maintenance Kind of Fuel (per Million Btu)
(g)
(h)(i)(k)(I)No.
334 693 321 453,446 111 752 Nat Gas 597
FERC FORM NO.1 (REV. 12-G3)Page 411
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.
(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) n A Resubmission 04/30/2004
TRANSMISSION LINE STATISTICS
1. Report information conceming transmission lines, cost of IiQes, 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.
.."
IIUN
X~~
~K\~)~~~~ ~gle JPileS)Line Type ofn lca e ere u dergroun~hnes NumberNo.other than
60 cYcle, 3 Dhase)Supporting report circuit miles)
From Operating Designed \)11 ~tJVcture f~C(mres CircuitsStructureot Lln 0 (Desl
8)a ed(a)(b)(c)(d)(e)
(g)
(h)
Group Sum 60.60.1.00
Group Sum 115.115.536.
Beacon Sub #4 BPA Bell Sub 230.230.Steel Tower 1.00
Beacon Sub BPA Bell Sub 230.230.H Type
Beacon Sub #5 BPA Bell Sub 230.230.H Type
Beacon Cabinet Gorge Plant 230.230.Steel Tower 1.00
Beacon Cabinet Gorge Plant 230.230.H Type 77.
Beacon Sub Lolo Sub 230.230.Steel Tower 1.00
Beacon Sub Lolo Sub 230.230.H Type 108.
Noxon Plant Pine Creek Sub 230.230.H Type 43.
Cabinet Gorge Plant Noxon 230.230.H Type 19.
Benewah Sw. Station Pine Creek Sub 230.230.Steel Tower
Benewah Sw. Station Pine Creek Sub 230.230.H Type 43.
Divide Creek Lolo Sub 230.230.Steel Tower
Divide Creek Lolo Sub 23O.230.H Type 63.
N. Lewiston Walla Walla 230.230.Steel Tower
N. Lewiston Walla Walla 230.230.H Type 32.
N. Lewiston Shawnee 230.230.Steel Tower
N. Lewiston Shawnee 230.230.H Type 27.
Walla Walla Wanapum 230.230.Alum.
Walla Walla Wanapum 230.230.H Type 78.
BPA (Libby)Noxon Plant 230.230.Steel Tower 1.00
BPA/Hot Springs #1 Noxon Plant 230.230.Steel Tower 1.00
BPA/Hot Springs #2 Noxon Plant (dead)230.230.Steel Tower
BPA/Hot Springs #2 Noxon Plant 230.230.H Type 68.
BPA Line West Side Sub 230.230.Steel Pole
Hatwai N. Lewiston Sub 230.230.H Type
Divide Creek Imnaha 230.230.H Type 20.
Colstrip Plant Broadview 500 . 500.
TOTAL 152.
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. ~eport 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)
8. 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, fumish 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 howdetermined. 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.
l;U~ I ' OF LINE (InClude In Column (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 LineOther Costs Expenses Expenses (0)Expenses No.(i)
(j)
(k)(I)(m)(n)
(p)
136,03f 70,092 206,130 664 664
087,36f 72,105,432 78,192,800 181,774 326,686 13,031 521 491
tT95 McMACSR
1272 McMACSR 17,91:309,929 327,841
1272 McMAL 30,32~392,837 423,160
1795 McMACSR
795 McMACSR 260,601 001,771 14,262,378 694 90,879 639 100,21~
795 McMACSR
1272 McMAL 456, 16~290,837 746,999 504 24,432 26,93E
954 McMAL 105,647 14,749,695 14,855,342 436 245,546 415 268,397
~54 McMAL 49,045 066,610 115,659 197 191 594 98~
~54 McMAL
~54 McMAL 157,19~323,709 480,902 856 807 103 76E
1272 McMAL
1272 McMAL 86,22f 548,205 634,433 892 680 57~
1272 McMAL
1272 McMAL 620,17~646,402 266,577 890 839 725
1272 McMAL
1272 McMAL 872,15C 550,203 8.422,353 550 55C
1272 McMAL
1272 McMAL 70,781 201 213 271,994 303 18,247 20,55C
1272 McMAL
1272 McMAL 18,143 18,143
1272 McMAL
1272 McMAL 144,63f 283,337 427,975 20,058 648 23,70E
1272 McMAL 36.461 587,224 623,685
1272 McMACSR 106,581 549,898 656,479
1272McMAL 60,284,858 345,160
595,785 28,260,542 28,856,331
893.404 161,240,937 171,134,341 205,546 739,899 39,110 984,55!
FERC FORM NO.1 (ED. 12-87)Page 423
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004
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 (0), it is permissible to report in these columns the
Line LINE IUN Lm~SL..
... . ~
IINu ~TRUCTURE r~n-lr:1 I~T~ ~ER STKUCTUK
No.From Leflgth
Type I\Vt:Ii:i~t:Present UltimateNumber perMilesMiles(a)(b)(c)(d)(e)(f)
(g)
TOTAL
FERC FORM NO.1 (REV. 12'()3)" Page 424
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) An Original (Mo, Da, Yr)Dec. 31 2003(2) 0 A Resubmission 04/30/2004
TRANi MISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are r~ported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, 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,
indicate such other characteristic.
J~o)LINE \"UO) I LineVoltageSizeSpecificationConf~Uration Land and Poles, Towers Conductors Asset Total No.and pacing (Operating)Land Rights and Fixtures and Devices Retire. Costs(h)(i)(k)(I)(m)(n)(0)
(p)
FERC FORM NO.1 (REV. 12.Q3)Page 425
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) CiA Resubmission 04/30/2004
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 (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
STATE OF WASHINGTON
Airway Heights Distr. Unattended 115.13.
Barker Road Distr. Unattended 110.13.
Beacon Tmsm & Dist Unattd 230.115.13.
Chester Distr. Unattended 115.13.
Chewelah 115Kv Distr. Unattended 115.13.
Colbert Distr. Unattended 115.13.
College & Walnut Distr. Unattended 115.13.
Colville 115Kv Distr. Unattended 115.13.
Dry Gulch Distr. Unattended 115.13.
East Colfax Distr. Unattended 115.13.
East Farms Distr. Unattended 115.13.
Fort Wright Distr. Unattended 115.13.
Francis and Cedar Distr. Unattended 115.13.
Gifford Distr. Unattended 115.34.
Glenrose Distr. Unattended 115.13.
, 18 Greenwood Distr. Unattended 115.13.
Industrial Park Distr. Unattended 115.13.
KetUe Falls Distr. Unattended 115.13.
Lee & Reynolds Distr. Unattended 115.13.
Liberty Lake Distr. Unattended 115.13.
Little Falls 115/34Kv Distr. Unattended 115.34.
Lyons & Standard Distr. Unattended 115.13.
Mead Distr. Unattended 115.13.
Metro Distr. Unattended 115.13.
Milan Distr. Unattended 115.13.
Millwood Tmsm & Dist Unattd 115.60.13.
Ninth & Central Distr. Unattended 115.13.
Northeast Distr. Unattended 115.13.
Northwest Distr. Unattended 115.13.
Opportunity Dist & Whrs Unattnd 115.13.
Othello Distr. Unattended 115.13.
Post Street Distr. Unattended 115.13.
Pound Lane Distr. Unattended 115.13.
Pullman Dist Unattended 115.13.
Ross Park Distr. Unattended 115.13.
Roxboro Distr. Unattended 115.24.
Shawnee Trans. Unattended 230.115.
Silver Lake Distr. Unattended 115.13.
FERC FORM NO.1 (ED. 12-96)Page 426
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) D A Resubmission 04/30/2004
SUBSTATIONS (Continued)
5. Show in columns (I), 0), 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)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)
(g)
(h)(i)(k)
Fred Oil & Air Fan
Two Stage Fan
536 Fred Oil & Air Fan 560
Fred Oil & Air Fan
Fred Air
Fred Oil & Air Fan
Two Stage Fan
Fred Oil & Air Fan
Fred Oil & Air Fan
FrOil/Air Fan
Two Stage Fan
Fr Oil/Air/2StgFan
Fred Air Fan
Fred Oil & Air Fan
FrOil/AirlTwo Stage
Two Stg/PtlFred Oil
Fred Oil & Air Fan
Two Stage Fan
Two Stage Fan
Two Stage Fan
Two Stage Fan
Two Stage Fan
Fred Oil & Air Fan
FrcAir/FrcOil/AirFan
Fred & Two Stage Fan
Two Stage Fan
Two Stage Fan
Two Stage Fan
FrOill AirFan
Fred Oil & Wt Fan
Two Stage Fan
Fred Oil & Air Fan
Two Stage Fan
Two Stage Fan
250
Fred Oil & Air Fan
FERC FORM NO.1 (ED. 12-96)Page 427
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31 2003(2) i:i A Resubmission 04/30/2004
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 (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
Southeast Distr. Unattended 115.13.
South Othello Distr. Unattended 115.13.
South Pullman Distr. Unattended 115.13.
Sunset Distr. Unattended 115.13.
Third & Hatch Distr. Unattended 115.13.
Waikiki Distr. Unattended 115.13.
West Side Trans. Unattended 230.115.13.
Other: 74 substa less than 10MVA Distr. Unattended
STATE OF IDAHO
Appleway Dist & Trfr Unattnd 115.13.
Benewah Trans. Unattended 230.115.13.
Big Creek Distr. Unattended 115.13.
Blue Creek Distr. Unattended 115.13.
Bunker Hill Distr. Unattended 115.13.
Clark Fork Distr. Unattended 115.21.
Coeur d'Alene 15th Ave Distr. Unattended 115.13.
Cottonwood Distr. Unattended 115.24.
Dalton Distr. Unattended 115.13.
Grangeville Dist & Trfr Unattnd 115.13.
Holbrook Distr. Unattended 115.13.
Huetter Distr. Unattended 115.13.
Juliaetta Distr. Unattended 115.13.
Kamiah Dist & Trfr Unattnd 115.13.
Kooskia Distr. Unattended 115.13.
Lolo Tran & Dist Unattnd 230.115.13.
Moscow Distr. Unattended 115.13.
Moscow 230Kv Tran & Dist Unattnd 230.115.13.
North Moscow Distr. Unattended 115.13.
North Lewiston Trans Unattended 230.115.13.
North Lewiston Distr. Unattended 115.13.
Oden Distr. Unattended 115.21.
Oldtown Distr. Unattended 115.21.
Orofino Distr. Unattended 115.13.
Osburn Distr. Unattended 115.13.
Pine Creek Tran & Dist Unattnd 230.110.13.
Pleasant View Distr. Unattended 115.13.
Post Falls Distr. Unattended 115.13.
Potlatch Dist & Trfr Unattnd 115.13.
Prarie Distr. Unattended 115.13.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This Re ort Is:Date of Report Year of Report
Avista Corp.(1) ~ An Original (Mo, Da, Yr)Dec. 31 2003(2) A Resubmission 04/30/2004
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters , rectifiers, condensers, etc.and auxiliary equipment forincreasing 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)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)
(j)
(k)
Two Stage Fan
Two Stage Fan
Two Stage Fan 240
Pt. & Two Stage Fan
Two Stg Fan & Cap 103
Two Stage Fan
250
197 144
Two Stage Fan
125
Portable Fan
Fred Air Fan
Fred Air Fan
Two Stage Fan
Two Stage Fan
FrcOil/Air2StgFan
FredOil/Air/Pt Fan
Two Stage Fan
Two Stage Fan
Fred Oil & Air Fan
Two Stage Fan
Fred Air Fan
270 Fred Oil/Airrrwo Stg 262
FrOil/Air/2Stg Fan
137 Capacitors 182
Two Stage Fan
250 Fred Oil/Air&Cptrs 295
Fred Air Fan
Fred Air Fan
Fred Oil & Air Fan
Portable Fan
262 Capacitors 307
Two Stage Fan
Two Stage Fan
Portable Fan
Fred Oil & Air Fan
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31,2003
(2) r; A Resubmission 04/30/2004
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 (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
Priest River Distr. Unattended 115.20.
Sand point Distr. Unattended 115.20.
South Lewiston Distr. Unattended 115.13.
Sweetwater Distr. Unattended 115.24.
St. Maries Distr. Unattended 115.24.
Tenth & Stewart Distr. Unattended 115.13.
Wallace Dist & Whse Unattnd 115.13.
Rathdrum Tran & Dist Unattnd 230.115.13.
Other: 29 substa less than 10 MV Distr. Unattended
STATE OF MONTANA
1 substation less than 10 MV A Distr. Unattended
SUBSTA. ~ GENERATING PLANTS
STATE OF WASHINGTON
Boulder Park Trans Step-115.13.
Kettle Falls Trans Step-Up 115.13.
Long Lake Trans.115.
Nine Mile Tms Step-Up & Dist 115.60.
Little Falls Trans.115.
Northeast Trans. Step-Up 115.13.
STATE OF IDAHO
Cabinet Gorge (Switchyard)230.115.13.
Cabinet Gorge (HED)Trans. Step-Up 230.13.
Post Falls Trans. Step-115.
Rathdrum Trans. Step-115.13.
STATE OF MONTANA
Noxon Trans. Step-230.13.
SUMMARY:
Washington:
8 subs Trans. Unattended
114 subs Distr. Unattended
3 subs Tran & Dist Unattnd
Idaho:
6 subs Trans. Unattended
56 subs Distr. Unattended
9 subs Tran & Dist Unattnd
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)
Dec. 31, 2003(2) 0 A Resubmission 04/30/2004
SUBSTATIONS (Continued)
5. Show in columns (I), 0), 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)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)
(j)
(k)
Fred Air Fan
Fred Air Fan
Port Fan/FredOil/Air
Fred Oil & Air Fan
Two Stage Fan
Fred OiVAirlTwo Stg
462 FredOil/AirFan/Cptrs 243 470
Two Stage Fan
Two Stage Fan
Fred Oil & Air Fan
Fred Oil & Air Fan
Two Stage Fan
125 2 stage fan
Fred Oil and Air Fan
Fred AirlOillAir Fan
114 Two Stage Fan 190
532 Fred Oil Air 555
724
1186
604
660
530
1222
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31,2003(2) 0 A Resubmission 04/30/2004
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 (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
Montana:1 sub Trans. Unattended
1 sub Distr. Unattended
System: 198 subs
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ~ort Is:Date of Report Year of Report
Avista Corp.(1) X An Original (Mo, Da, Yr)Dec. 31,2003(2) n A Resubmission 04/30/2004
SUBSTATIONS (Continued)
5. Show in columns (I), m, 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)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)(9)(h)(i)(k)
533
5464
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmisslon 04/30/2004 Dec 31 2003
FOOTNOTE DATA
'Schedule Page: 103 Line No.25 Column:
In 2003, assets previously held by Avista Labs were aquired by AVLB, Inc. Avista Labsowns 17.5 percent of AVLB, Inc.
ISchedule Page: 103.Line No.23 Column:
Indirectly controlled by the Respondent owned by Pentzer Corporation, a wholly ownedAvista Capital Subsidiary. See Avista Capital and Pentzer Corporation listings on page03.
~chedule Page: 103.Line No.18 Column:
51% owned by Cogentrix, Inc.
chedule Pa e: 103.Line No.21 Column:
50% owned by Mirant Americas Development, Inc.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31 2003
FOOTNOTE DATA
ISchedule Page: 219 Line No.Column:
nterest credits under sinking fund method (on Hydro plant only) is $4 945,725.
fschedule Page: 219 Line No.12 Column:
The difference between FERC FORM 1 page 219 for "Book Cost of Plant Retired" and pages
204-207 is $106,094. Page 219 only shows retirements for account 108, Accumulated
provision for Depreciation of Electric Utility Plant, whereas pages 204-207 includeaccount 111, Accumulated Provision for Amortization of Electric Utility Plant.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista Corp.(2) A Resubmission 04/30/2004 Dec 31 2003
FOOTNOTE DATA
chedule Pa e: 227 Line No.Column: dElectric
chedule Pa e: 227 Line No.Column: d
chedule Pa e: 227 Line No.Column: d
Schedule Pa e: 227 Line No.Column: d
Schedule Pa e: 227 Line No.Column: dElectric.
Schedule Pa e: 227 Line No.10 Column: d
Electric gas & miscellaneous.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1 ) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 , 2003
FOOTNOTE DATA
ISchedule Page: 233.Line No.Column: bMisc. Work Order ~ $50,000 - Beginning balance for 2003
balance for 2002, due to the addition of line 35 (Care -46 (Shareholder Lawsuit 2002 for $39,790.When line 35
they equal $75,798.
is $75,798 less than ending
California for $36,008) and line
and line 46 are added together,
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 , 2003
FOOTNOTE DATA
'Schedule Page: 261 Line No.Column: b
BP A C&RD Receipts
Contributions in Aid of Construction - Electric
Contributions in Aid of Construction - Gas
Contributions in Aid of Construction -- OR
Contributions in Aid of Construction -- CA
Customer Uncollectibles - W AIID
Customer Uncollectibles - ORICA
BETC Interest
Transportation Tax Depreciation Capitalized - W AIID
Transportation Tax Depreciation Capitalized - ORICA
Taxable income Not Reported on Books
180
978,929
315,446
26,224
142
(286,005)
(121,125)
10,246
997,200
23,040
948,277
'Schedule Page: 261 Line No.10 Column: b
Hamilton Street Bridge
Severance Stock Options - Accelerated Vesting
Supplemental Executive Retirement Plan
Non-monetary Purchased Power
Amortization of Centralia Gain
Book Depr-Electric (Utility Code 0, 7 & 9)
Book Depr-Gas (Utility Code 1 & 8)
Book Deprec (Utility Code 2)
Rathdrum Turbine Sales Tax Refund
Wood Power Inc. Buyout
Investment Exchange Power - WNP 3
FASB 106-Def Amort-Postretirement Benefits - W A Electric
FASB 106-Def Amort-Postretirement Benefits - ID Electric
FASB 106-Def Amort-Postretirement Benefits - W A Gas
Redemption Expense Amortization - PCBs
DSM -- Electric Program Amortization
DSM -- Gas Program Amortization
DSM -- Electric Program Amortization Sandpoint
Political Contributions
Paid Time Off Equalization
SalelLease General Office Bldg
Airplane Lease Payments
CSS Hardware Lease - Principal Only
CSS Software Lease - Principal Only
EGMA Hardware & Software Lease - Principal Only
WMS Software Lease - Principal Only
Office Furniture Lease Series A - Principal only
Office Furniture Lease Series B - Principal only
Office Furniture Lease Series C - Principal only
Office Furniture Lease Series D - Principal only
CIT Operating Lease
F AS 106 Current Retiree Medical accrual
Redemption Expense Amortization
Meal Disallowances
Transportation Book Depreciation
Preferred Dividend Requirement
Deductions Recorded on Books Not Deducted for Return
I FERC FORM NO.1 (ED. 12-87)
164,551
(526,473)
335,692
(181,376)
(1,763,806)
55,017,391
297,459
237,654
(33,828)
391,992
2,450,004
250,572
88,788
55,560
194,424
206,890
566,736
113,388
440,000
(100,136)
(238,028)
269,825
220,624
032,892
138,238
455,636
80,351
32,889
80,057
29,027
(39,276)
(1,131,553)
877,910
288,000
682,946
094 628
81,079,648
ge 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmlssion 04/30/2004 Dec 31, 2003
FOOTNOTE DATA
ISchedule Page: 261 Line No.15 Column: b
Injury & Damages - Electric
Injury & Damages - Gas
Injury & Damages - ORICA
Kettle Falls Nonoperating
Gain on General Office Bldg - Elec
Gain on General Office Bldg - Gas
Clark Fork PMEs
Nez Perce settlement -- W A
Nez Perce settlement -- ID
F ASB 87
Deferred Compensation Accrual
W A Deferred Power Costs
W A Deferred Power Costs - Interest
Idaho PCA
Idaho PeA - Interest
Deferred Gas - W A
W A Deferred Gas Costs - Interest
Deferred Gas - ill
ill Deferred Gas Costs - Interest
Deferred Gas - OR
OR Deferred Gas - Interest
Deferred Gas - CA
CA Deferred Gas - Interest
WPNG DSM - OR
OR DSM - Interest
PGE Monetization
AFUDC Elec
AFUDC Gas
AFUDC - ORICA
Officers' Life Insurance
Income Recorded on Books Not Included in Return
150,459
(39,260)
(257,555)
(228,480)
( 196,092)
(65,364)
(26,194)
(22,008)
212
(67,130)
262 927
137,329
(6,873,898)
518,073
(985,150)
220,126
(252,168)
844 023
(66,021)
(8,780,887)
(150,057)
(621,450)
(31,163)
(249,716)
89,993
219,439
(273,847)
(18,333)
(5,722)
(559,987)
677 099
'Schedule Page: 261 Line No.20 Column: b
BP A Residential Exchange -- W A & ill
W A & ill DSM Tariff Rider -- Electric
W A & ill DSM Tariff Rider -- Gas
RemovaVSalvage - Electric (Utility Code 0, 7 & 9)
RemovaVSalvage - Gas (Utility Code 1 & 8)
RemovaVSalvage - ORICA
Basic American Foods-Non-Utility
Tax Depreciation - Basic American Foods -- Non-Utility
Engineering Overheads - Electric
Tax Depreciation - Electric
Tax Depreciation - Rathdrum Turbine
Engineering Overheads - Gas
Tax Depreciation - Gas
Tax Depreciation - Sandpoint Acquisition Adjustment
Engineering Overheads - OR
Tax Depreciation - Common
Tax Depreciation - OR
I FERC FORM NO.1 (ED. 12-87)
(423,500)
363,144
(616,884)
(183,243)
(36,884 )
(189,586)
788
(16,259)
(6,000,000)
(58,754,699)
(3,518,376)
(2,000,000)
(12,210,606)
(458,114)
000,000)
(721,113)
(4,861,909)
Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmisslon 04/30/2004 Dec 31 2003
FOOTNOTE DATA
Tax Depreciation - CA
Tax Amortization: WPNG Acquisition - OR
Tax Amortization: WPNG Acquisition - CA
WPNG Acquisition OR - Book
WPNG Acquisition CA - Book
Deductions on Return Not Charged Against Book Income
(590,863)
(768,683)
(135,297)
117,260
206,160
(88,791,664)
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 , 2003
FOOTNOTE DATA
ISchedule Page: 300 Line No.Column: b
Classification between commercial and industrial customers is based on whether the entity
manufactures a product (industrial) or provides a service or product for salecommercial) .
\Schedule Page: 300 Line No.10 Column: b
Includes unmetered revenue for services such as area lights and street lights. Unmetered
revenue is included in all classifications.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31 , 2003
FOOTNOTE DATA
'Schedule Page: 304 Line No.41 Column:
Includes the following fuel adjustment revenues:
WA (Sch 93) - $26,955,433ID (Sch 66) - $26,753,952
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31 2003
FOOTNOTE DATA
chedule Pa e: 310.Line No.Column: b
Enron contact assi ned to Peaker, LLC November 17, 2003.
Schedule Pa e: 310.Line No.Column: b
NorthWestern Energy contract terminates October
Schedule Pa e: 310.Line No.Column: b
PacifiCorp sale terminated September 15, 2003.
Schedule Page: 310.Line No.: 8 Column: b
PacifiCorp sale terminates October 31, 2008.
31, 2008.
chedule Pa e: 310.Line No.Column: b
Peaker, LLC capacity contract terminates December
Schedule Pa e: 310.Line No.Column: b
PP&L Montana terminates October 31, 2008.
chedule Pa e: 310.Line No.Column: b
puget Sound Ener terminates October 31, 2008.
Schedule Pa e: 310.Line No.12 Column:
Intracompany Wheeling
chedule Pa e: 310.Line No.12 Column: b
IntraCompany Wheeling terminates 09/30/2023.
31, 2016.
Schedule Pa e: 310.Line No.12 Column:
Transmission revenue for pre-s88 contracts. Reclassification of revenue.
chedule Pa e: 310.Line No.13 Column:
Intracompany generation - sale of ancillary services
chedule Pa e: 310.Line No.13 Column: b
IntraCompany Generation - Sale of Ancillary Services terminates 12/31/2009.
chedule Pa e: 310.Line No.13 Column:
Sale of Ancillary Services to Avista Transmission Department.
chedule Pa e: 310.Line No.14 Column: b
Estimated revenues - true up in later periods.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission 04/30/2004 Dec 31, 2003
FOOTNOTE DATA
ISchedule Page: 326 Line No.Column: b
BPA - WNP#3 contract terminates June 30, 2017.
ISchedule Page: 326 Line No.Column: b
BPA - CSPE & Supp/Entitlement Capacity - terminated March 31, 2003.
'Schedule Page: 326 Line No.Column: I
ther charges - Internal Nonmonetary accrual
~chedule Page: 326 Line No.10 Column: b
Storage charges
ISchedule Page: 326 Line No.10 Column: I
Other Charges - Storage charges
ISchedule Page: 326.Line No.Column: b
CSPE Capacity - terminated March 31, 2003.
ISchedule Page: 326.Line No.: 8 Column: b
Service to Deer Lake customers delivered from Inland Power & Light.
~chedule Page: 326.Line No.10 Column: I
ther Charges - Internal Nonmonetary accrual
~chedu/e Page: 326.Line No.13 Column: I
ther Charges - Internal Nonmonetary accrual
~chedule Page: 326.Line No.14 Column: I
ther Charges Internal Nonmonetary accrual
~chedule Page: 326.Line No.11 Column: I
Off system exchange of energy
~chedule Page: 326.Line No.11 Column: I
Other Charges - Ancillary services
ISchedule Page: 326.Line No.Column: I
ther Charges - Amortization of contract buyout
~chedule Page: 326.Line No.Column:
IntraCompany generation - ancillary services, terminates December 31, 2009.
jSchedule Page: 326.Line No.Column: b
IntraCompany generation - Ancillary services
'Schedule Page: 326.Line No.Column: I
IntraCompany generation - Ancillary services. terminates December 31, 2009.
~chedule Page: 326.Line No.Column: Transmission losses
ISchedule Page: 326.Line No.Column:
Inadvertant Energy
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2) A Resubmission 04/30/2004 Dec 31 2003
FOOTNOTE DATA
chedule Pa e: 328 Line No.
Subsidiary of Avista Corp.
Column:
chedule Pa e: 328 Line No.
Subsidiary of Avista Corp.
chedule Pa e: 328 Line No.: 3
Subs idiary of Avi ta Corp.
Schedule Pa e: 328 Line No.
Subsidiary of Avista Corp.
Schedule Pa e: 328 Line No.
Subsidiary of Avista Corp.
Column:
Column:
Column:
Column:
chedule Pa e: 328 Line No.Column:
Subsidiary of Avista Corp.
chedule Pa e: 328 Line No.Column:
Subsidiary of Avista Corp
Other Charges - Prior period
ISchedule Page: 328 Line No.Column:
Transfer Agreement terminates October 31, 2005
ISchedule Page: 328 Line No.16 Column:
Agreement Treminates Sept. 30, 2006
Other Charges - Use of Facilities
chedule Pa e: 328.Line No.Column:
Agreement Terminates on one ear notice
chedule Pa e: 328.Line No.15 Column:
AGreement terminates Dec. 31, 2012
chedule Pa e: 328.Line No.Column:
Other Charges - prior period
chedule Pa e: 328.Line No.Column:
Agreement terminates Oct. 30, 2005
~chedule Page: 328.Line No.Column:
Agreement terminates Oct 30, 2005
ther Charges - Use of Facilities
~chedule Page: 328.Line No.: 3 Column:
Agreement terminates Dec 31, 2003
!Schedule Page: 328.Line No.Column:
greement terminates Oct. 30, 2005
~chedule Page: 328.Line No.Column:
Agreement terminates Nov. 11, 2015
Other Charges - Use of Facilities
'Schedule Page: 328.Line No.13 Column:
Agreement terminates Dec. 31, 2009
Other Charges - losses delivered
jFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da. Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 2003
FOOTNOTE DATA
'Schedule Page: 332 Line No.Column:
Other Charges - Prior Period
ISchedule Page: 332 Line No.Column:
Delivered Power to Wheeler
Other Charges - Prior period
'Schedule Page: 332 Line No.Column:
Received Power from Wheeler
Other Charges - Prior period
!Schedule Page: 332 Line No.
Received Power from Wheeler
ther Charges - Prior period
Ischedule Page: 332 Line No.
eceived Power from Wheeler
Ischedule Page: 332 Line No.
Received Power from Wheeler
!Schedule Page: 332 Line No.
Delivered Power to Wheeler
ther Charges - Prior period
!Schedule Page: 332.Line No.
eceived Power from Wheeler
Ischedule Page: 332.Line No.
Received Power from Wheeler
'Schedule Page: 332.Line No.
eceived Power from Wheeler
Ischedule Page: 332.Line No.
Received Pwoer from Wheeler
Ischedule Page: 332.Line No.
eceived Power from Wheeler
!schedule Page: 332.Line No.
Delivered Power to Wheeler
Column:
Column:
Column:
Column:
Column:
Column:
Column:
Column:
Column:
Column:
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 2003
FOOTNOTE DATA
Column: b'Schedule Page: 335 Line No.Vendor
SODEXHO INC
RED LION HOTEL
DAVENPORT 2000 LLC
GEORGESON SHAREHOLDER
AUBLE, JOLICOEUR & GENTRY
HELLER EHRMAN WHITE
WILMINGTON TRUST COMPANY
JACK W. GUSTA VEL
WELLS FARGO
SECRETARY OF STATE
SHARMAN COMMUNICATIONS
CAGNEY MCDOWELL INC
FITCH INC
J. CRAIG SWEAT PHOTOGRAPHY
RR DONNELLEY RECEIVABLES INC
MOODY I S INVESTORS SERVI
CITIBANK NA
ADP INVESTOR
STANDARD AND POORS
ANDERSON-MRAX DESIGN
JP MORGAN CHASE BANK
LAWTON PRINTING INC
THE BANK OF NEW YORK
BANKERS TRUST
Purpose
Board meeting & meals
Retirement
Board meeting & travel
Proxy materials & mailingAnalysis fees
Legal Services
Corp trust fees
Quarterly paymentBoard acti vi ties
2003 annual report
2003 annual report
2002 annual reportRelationship fee
2002 & 2003 annual report
2002 financials & proxyStock monitoring services
Services & fees
Proxy materials & solicitation
Analytical services
2003 annual report
Services & fees
2002 annual report
Stock transfer fees & services
Company/Director stock plan
2002 Amount
086.
427.
555.
886.
192.
6, 208.
200.
327.
753.
098.
10,589.
19,608.
21,387.
22,283.
25,403.
28,516.
29,030.
33,790.
33,863.
41,884.
43,990.
450.
143,417.
201,940.
Line No.'Schedule Page: 335
Director
R. John Taylor
David A. Clack
John F. Kelly
Sarah M. R. Jewell
Jessie Knight
Kristianne Blake
Erik J. Anderson
Roy Lewis Eiguren
Lura J. Powell
Column: b
2003 Fees & Expenses
$ 26 716.
$ 29,353.
$ 23,843.$ 6,734.
$ 22,874.
$ 35,995.
$ 25,523.
$ 24,157.
$ 24 860.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31,2003
FOOTNOTE DATA
chedule Pa e: 402 Line No.Column: b
Joint facility with Mirant Oregon, LLC.
chedule Pa e: 402 Line No.Column:
Operated by PPL Montana LLC.
!schedule Page: 402 Line No.Column:
Leased plant.
Operated by Portland General Electric.
IFERC FORM NO.1 (ED. 12-87) Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Mo, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31, 2003
FOOTNOTE DATA
Schedule Pa e: 406 Line No.Column: b
License period from August 1 , 1972 to July 31, 2007.
Schedule Pa e: 406 Line No.Column:
License period from August 1, 1972 to July 31, 2007.
chedule Pa e: 406 Line No.Column:
License period from March 1, 2001 to February 28, 2046
Schedule Pa e: 406 Line No.-2 Column:
License period from March 1, 2001 to February 28, 2046.
Schedule Pa e: 406 Line No.Column:
License period from August 1, 1972 to July 31, 2007.
Schedule Pa e: 406. Line No.Column: b
License period from August 1972 to July 31,2007.
chedule Pa e: 406. Line No.Column:
Licensed period from August 1972 to July 31,2007.
ISchedule Page: 406.Line No.Not a licensed proj ect .Column:
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year of Report
(1) An Original (Me, Da, Yr)
Avista corp.(2)A Resubmission 04/30/2004 Dec 31 2003
FOOTNOTE DATA
ISchedule Page: 422 Line No.31 Column:
Peaker, LLC capacity contract terminates December 31, 2016.
IFERC FORM NO.1 (ED. 12-87)Page 450.