UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549

FORM 10-Q

     (Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2003

OR

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to               

Commission file number 1-3701

AVISTA CORPORATION

(Exact name of registrant as specified in its charter)

Washington	91-0462470
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

1411 East Mission Avenue, Spokane, Washington	99202-2600
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: 509-489-0500
Web site: http://www.avistacorp.com

None

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Act):

Yes x No o

As of October 31, 2003, 48,314,044 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

TABLE OF CONTENTS

		CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Three Months
		CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Nine Months
		CONSOLIDATED BALANCE SHEETS
		CONSOLIDATED STATEMENTS OF CASH FLOWS
		SCHEDULE OF INFORMATION BY BUSINESS SEGMENTS For the Three Months
		SCHEDULE OF INFORMATION BY BUSINESS SEGMENTS For the Nine Months
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosures About Market Risk
	Item 4. Controls and Procedures
Part II. Other Information
	Item 1. Legal Proceedings
	Item 6. Exhibits and Reports on Form 8-K
SIGNATURE
EXHIBIT 4.(F)
EXHIBIT 12
EXHIBIT 31.(A)
EXHIBIT 31.(B)
EXHIBIT 32

AVISTA CORPORATION

Index

				Page No.
	Part I. Financial Information:
		Item 1. Consolidated Financial Statements
			Consolidated Statements of Income and Comprehensive Income - Three Months Ended September 30, 2003 and 2002		3
			Consolidated Statements of Income and Comprehensive Income - Nine Months Ended September 30, 2003 and 2002		4
			Consolidated Balance Sheets - September 30, 2003 and December 31, 2002		5
			Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2003 and 2002		7
			Schedule of Information by Business Segments - Three Months Ended September 30, 2003 and 2002		8
			Schedule of Information by Business Segments - Nine Months Ended September 30, 2003 and 2002		9
			Notes to Consolidated Financial Statements		10
		Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			32
		Item 3. Quantitative and Qualitative Disclosures About Market Risk			67
		Item 4. Controls and Procedures			67
Part II. Other Information:
		Item 1. Legal Proceedings			67
		Item 6. Exhibits and Reports on Form 8-K			67
Signature					68

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
Avista Corporation
For the Three Months Ended September 30
Dollars in thousands, except per share amounts

			2003			2002
OPERATING REVENUES			$	224,377		$	199,976
OPERATING EXPENSES:
	Resource costs			108,218			91,099
	Operations and maintenance			31,722			31,799
	Administrative and general			22,780			22,039
	Depreciation and amortization			20,114			17,440
	Taxes other than income taxes			13,424			13,991
		Total operating expenses		196,258			176,368
INCOME FROM OPERATIONS				28,119			23,608
OTHER INCOME (EXPENSE):
	Interest expense			(22,934	)		(24,870	)
	Capitalized interest			318			3,148
		Net interest expense		(22,616	)		(21,722	)
	Other income - net			2,173			3,018
		Total other income (expense)-net		(20,443	)		(18,704	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES				7,676			4,904
INCOME TAXES				3,290			4,040
INCOME FROM CONTINUING OPERATIONS				4,386			864
DISCONTINUED OPERATIONS (Note 3):
	Loss before income taxes			(101	)		(3,693	)
	Income tax benefit			35			1,214
LOSS FROM DISCONTINUED OPERATIONS				(66	)		(2,479	)
NET INCOME (LOSS)				4,320			(1,615	)
DEDUCT-Preferred stock dividend requirements				—			608
INCOME (LOSS) AVAILABLE FOR COMMON STOCK			$	4,320		$	(2,223	)
Weighted-average common shares outstanding (thousands), Basic				48,281			47,866
Weighted-average common shares outstanding (thousands), Diluted				48,691			47,866
EARNINGS (LOSS) PER COMMON SHARE, BASIC AND DILUTED (Note 11)
	Earnings per common share from continuing operations		$	0.09		$	0.00
	Loss per common share from discontinued operations			—			(0.05	)
		Total earnings (loss) per common share, basic and diluted	$	0.09			($0.05	)
Dividends paid per common share			$	0.125		$	0.12
COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)			$	4,320		$	(1,615	)
OTHER COMPREHENSIVE INCOME (LOSS):
	Foreign currency translation adjustment			25			(154	)
	Unrealized loss on derivative commodity instruments - net of tax			(182	)		—
	Unrealized loss on interest rate swap agreements - net of tax			(91	)		(646	)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)				(248	)		(800	)
COMPREHENSIVE INCOME (LOSS)			$	4,072		$	(2,415	)

The Accompanying Notes are an Integral Part of These Statements.

3

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
Avista Corporation
For the Nine Months Ended September 30
Dollars in thousands, except per share amounts

			2003			2002
OPERATING REVENUES			$	754,651		$	746,209
OPERATING EXPENSES:
	Resource costs			351,090			356,407
	Operations and maintenance			98,504			93,727
	Administrative and general			73,327			78,225
	Depreciation and amortization			57,960			52,930
	Taxes other than income taxes			46,552			50,198
		Total operating expenses		627,433			631,487
INCOME FROM OPERATIONS				127,218			114,722
OTHER INCOME (EXPENSE):
	Interest expense			(69,605	)		(80,369	)
	Capitalized interest			677			7,538
		Net interest expense		(68,928	)		(72,831	)
	Other income - net			4,387			14,631
		Total other income (expense)-net		(64,541	)		(58,200	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES				62,677			56,522
INCOME TAXES				27,136			26,390
INCOME FROM CONTINUING OPERATIONS				35,541			30,132
DISCONTINUED OPERATIONS (Note 3):
	Loss before income taxes			(7,905	)		(9,351	)
	Income tax benefit			2,975			3,197
LOSS FROM DISCONTINUED OPERATIONS				(4,930	)		(6,154	)
NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE				30,611			23,978
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (net of tax)				(1,190	)		(4,148	)
NET INCOME				29,421			19,830
DEDUCT-Preferred stock dividend requirements				1,125			1,824
INCOME AVAILABLE FOR COMMON STOCK			$	28,296		$	18,006
Weighted-average common shares outstanding (thousands), Basic				48,202			47,771
Weighted-average common shares outstanding (thousands), Diluted				48,514			47,842
EARNINGS PER COMMON SHARE, BASIC (Note 11):
	Earnings per common share from continuing operations		$	0.72		$	0.60
	Loss per common share from discontinued operations			(0.10	)		(0.13	)
	Earnings per common share before cumulative effect of accounting change			0.62			0.47
	Loss per common share from cumulative effect of accounting change			(0.03	)		(0.09	)
		Total earnings per common share, basic	$	0.59		$	0.38
EARNINGS PER COMMON SHARE, DILUTED (Note 11):
	Earnings per common share from continuing operations		$	0.71		$	0.60
	Loss per common share from discontinued operations			(0.10	)		(0.13	)
	Earnings per common share before cumulative effect of accounting change			0.61			0.47
	Loss per common share from cumulative effect of accounting change			(0.03	)		(0.09	)
		Total earnings per common share, diluted	$	0.58		$	0.38
Dividends paid per common share			$	0.365		$	0.36
COMPREHENSIVE INCOME:
NET INCOME			$	29,421		$	19,830
OTHER COMPREHENSIVE INCOME (LOSS):
	Foreign currency translation adjustment			693			(3	)
	Unrealized loss on interest rate swap agreements - net of tax			(104	)		(990	)
	Unfunded accumulated benefit obligation - net of tax			12			—
	Unrealized loss on derivative commodity instruments - net of tax			(182	)		—
	Unrealized investment losses - net of tax			—			(934	)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)				419			(1,927	)
COMPREHENSIVE INCOME			$	29,840		$	17,903

The Accompanying Notes are an Integral Part of These Statements.

4

CONSOLIDATED BALANCE SHEETS
Avista Corporation
Dollars in thousands

			September 30,		December 31,
			2003		2002
ASSETS:
CURRENT ASSETS:
	Cash and cash equivalents		$	187,184	$	186,269
	Securities held for trading			18,884		—
	Accounts and notes receivable-less allowances of $46,646 and $46,909, respectively			261,799		320,836
	Energy commodity assets			198,711		365,477
	Materials and supplies, fuel stock and natural gas stored			26,244		21,746
	Prepayments and other current assets			83,954		73,437
	Assets held for sale from discontinued operations			—		5,900
		Total current assets		776,776		973,665
NET UTILITY PROPERTY:
	Utility plant in service			2,523,236		2,370,811
	Construction work in progress			36,845		17,581
		Total		2,560,081		2,388,392
	Less: Accumulated depreciation and amortization			875,011		824,688
		Total net utility property		1,685,070		1,563,704
OTHER PROPERTY AND INVESTMENTS:
	Investment in exchange power-net			38,996		40,833
	Non-utility properties and investments-net			93,607		199,579
	Non-current energy commodity assets			284,204		348,309
	Other property and investments-net			15,036		12,702
		Total other property and investments		431,843		601,423
DEFERRED CHARGES:
	Regulatory assets for deferred income tax			132,104		139,138
	Other regulatory assets			26,868		29,735
	Utility energy commodity derivative assets			52,397		60,322
	Power and natural gas deferrals			176,299		166,782
	Unamortized debt expense			50,537		51,128
	Other deferred charges			29,514		28,236
		Total deferred charges		467,719		475,341
		TOTAL ASSETS	$	3,361,408	$	3,614,133

The Accompanying Notes are an Integral Part of These Statements.

5

CONSOLIDATED BALANCE SHEETS (continued)
Avista Corporation
Dollars in thousands

			September 30,			December 31,
			2003			2002
LIABILITIES AND STOCKHOLDERS’ EQUITY:
CURRENT LIABILITIES:
	Accounts payable		$	281,639		$	339,637
	Energy commodity liabilities			160,067			304,781
	Current portion of long-term debt			16,283			71,896
	Current portion of preferred stock-cumulative (17,500 shares outstanding)			1,750			—
	Short-term borrowings			85,530			30,000
	Interest accrued			23,334			20,307
	Other current liabilities			209,139			172,125
	Liabilities of discontinued operations			—			2,084
		Total current liabilities		777,742			940,830
LONG-TERM DEBT				899,048			902,635
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES				100,000			0
PREFERRED STOCK-CUMULATIVE (subject to mandatory redemption):
	10,000,000 shares authorized: $6.95 Series K
	297,500 shares outstanding ($100 stated value) as of September 30, 2003			29,750			0
OTHER NON-CURRENT LIABILITIES AND DEFERRED CREDITS:
	Non-current energy commodity liabilities			241,155			314,204
	Utility energy commodity derivative liabilities			43,594			50,058
	Deferred income taxes			438,110			454,147
	Other non-current liabilities and deferred credits			102,700			106,218
		Total other non-current liabilities and deferred credits		825,559			924,627
		TOTAL LIABILITIES		2,632,099			2,768,092
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES				0			100,000
PREFERRED STOCK-CUMULATIVE (subject to mandatory redemption):
	10,000,000 shares authorized: $6.95 Series K
	332,500 shares outstanding ($100 stated value) as of December 31, 2002			0			33,250
COMMON EQUITY:
	Common stock, no par value; 200,000,000 shares authorized; 48,310,886 and 48,044,208 shares outstanding			626,354			623,092
	Note receivable from employee stock ownership plan			(2,866	)		(4,146	)
	Capital stock expense and other paid in capital			(11,169	)		(11,928	)
	Accumulated other comprehensive loss			(19,945	)		(20,364	)
	Retained earnings			136,935			126,137
		Total common equity		729,309			712,791
		TOTAL STOCKHOLDERS’ EQUITY		729,309			746,041
COMMITMENTS AND CONTINGENCIES (See Notes to Consolidated Financial Statements)
		TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,361,408		$	3,614,133

The Accompanying Notes are an Integral Part of These Statements.

6

CONSOLIDATED STATEMENTS OF CASH FLOWS
Increase (Decrease) in Cash and Cash Equivalents
Avista Corporation
For the Nine Months Ended September 30
Dollars in thousands

				2003			2002
CONTINUING OPERATING ACTIVITIES:
	Net income			$	29,421		$	19,830
	Loss from discontinued operations				4,930			6,154
	Cumulative effect of accounting change				1,190			4,148
	Non-cash items included in net income:
		Depreciation and amortization			57,960			52,930
		Provision for deferred income taxes			(8,886	)		(37,785	)
		Power and natural gas cost amortizations (deferrals), net			(1,343	)		66,518
		Amortization of debt expense			5,965			6,810
		Energy commodity assets and liabilities			10,998			80,889
		Other			(5,868	)		(11,682	)
		Changes in working capital components:
			Sale of customer accounts receivable-net		(25,000	)		(33,000	)
			Accounts and notes receivable		84,300			132,713
			Materials and supplies, fuel stock and natural gas stored		(4,498	)		(6,166	)
			Other current assets		(10,517	)		14,675
			Accounts payable		(57,998	)		(61,606	)
			Other current liabilities		40,041			52,597
NET CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES					120,695			287,025
CONTINUING INVESTING ACTIVITIES:
	Utility property construction expenditures (excluding AFUDC)				(64,617	)		(46,823	)
	Other capital expenditures				(2,686	)		(14,536	)
	Investment in securities held for trading				(18,884	)		—
	Changes in other property and investments				(2,554	)		1,175
	Repayments received on notes receivable				1,178			5,078
	Assets acquired and investments in subsidiaries				(150	)		(352	)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES					(87,713	)		(55,458	)
CONTINUING FINANCING ACTIVITIES:
	Increase in short-term borrowings				55,530			33,982
	Proceeds from issuance of long-term debt				44,795			—
	Redemption and maturity of long-term debt				(109,582	)		(200,504	)
	Redemption of preferred stock				(1,575	)		(1,750	)
	Issuance of common stock				4,541			5,359
	Cash dividends paid				(18,749	)		(19,121	)
	Premiums paid for the redemption of long-term debt				(1,709	)		(9,707	)
	Long-term debt and short-term borrowing issuance costs				(2,113	)		(6,460	)
NET CASH USED IN CONTINUING FINANCING ACTIVITIES					(28,862	)		(198,201	)
NET CASH PROVIDED BY CONTINUING OPERATIONS					4,120			33,366
NET CASH USED IN DISCONTINUED OPERATIONS					(3,205	)		(6,257	)
NET INCREASE IN CASH AND CASH EQUIVALENTS					915			27,109
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD					186,269			171,097
CASH AND CASH EQUIVALENTS AT END OF PERIOD				$	187,184		$	198,206
SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid during the period:
		Interest		$	60,532		$	67,050
		Income taxes			11,476			7,428
	Non-cash financing and investing activities:
		Property and equipment purchased under capital leases			5,312			—
		Unrealized investment losses			—			(1,436	)

The Accompanying Notes are an Integral Part of These Statements.

7

SCHEDULE OF INFORMATION BY BUSINESS SEGMENTS
Avista Corporation
For the Three Months Ended September 30
Dollars in thousands

			2003			2002
OPERATING REVENUES:
	Avista Utilities		$	190,988		$	171,526
	Energy Marketing and Resource Management			45,035			26,381
	Avista Advantage			5,002			4,419
	Other			2,959			3,985
	Intersegment eliminations			(19,607	)		(6,335	)
		Total operating revenues	$	224,377		$	199,976
RESOURCE COSTS:
	Avista Utilities		$	95,564		$	80,816
	Energy Marketing and Resource Management			32,261			16,618
	Intersegment eliminations			(19,607	)		(6,335	)
		Total resource costs	$	108,218		$	91,099
OPERATIONS AND MAINTENANCE EXPENSES:
	Avista Utilities		$	25,476		$	24,951
	Energy Marketing and Resource Management			—			—
	Avista Advantage			2,841			3,235
	Other			3,405			3,613
		Total operations and maintenance expenses	$	31,722		$	31,799
ADMINISTRATIVE AND GENERAL EXPENSES:
	Avista Utilities		$	15,728		$	14,455
	Energy Marketing and Resource Management			5,248			4,862
	Avista Advantage			1,678			1,608
	Other			126			1,114
		Total administrative and general expenses	$	22,780		$	22,039
DEPRECIATION AND AMORTIZATION EXPENSES:
	Avista Utilities		$	18,572		$	16,061
	Energy Marketing and Resource Management			358			336
	Avista Advantage			685			728
	Other			499			315
		Total depreciation and amortization expenses	$	20,114		$	17,440
INCOME FROM OPERATIONS (PRE-TAX):
	Avista Utilities		$	22,503		$	21,958
	Energy Marketing and Resource Management			6,898			3,870
	Avista Advantage			(202	)		(1,152	)
	Other			(1,080	)		(1,068	)
		Total income from operations	$	28,119		$	23,608
INCOME FROM CONTINUING OPERATIONS:
	Avista Utilities		$	907		$	(461	)
	Energy Marketing and Resource Management			4,844			2,732
	Avista Advantage			(265	)		(905	)
	Other			(1,100	)		(502	)
		Total income from continuing operations	$	4,386		$	864
ASSETS (2002 amounts as of December 31):
	Avista Utilities		$	2,287,578		$	2,184,008
	Energy Marketing and Resource Management			996,492			1,349,626
	Avista Advantage			31,496			31,733
	Other			45,842			42,866
	Discontinued Operations			—			5,900
		Total assets	$	3,361,408		$	3,614,133
CAPITAL EXPENDITURES:
	Avista Utilities		$	27,812		$	13,895
	Energy Marketing and Resource Management			524			9,861
	Avista Advantage			79			139
	Other			79			85
		Total capital expenditures	$	28,494		$	23,980

The Accompanying Notes are an Integral Part of These Statements.

8

SCHEDULE OF INFORMATION BY BUSINESS SEGMENTS
Avista Corporation
For the Nine Months Ended September 30
Dollars in thousands

			2003			2002
OPERATING REVENUES:
	Avista Utilities		$	657,350		$	648,157
	Energy Marketing and Resource Management			172,719			126,680
	Avista Advantage			14,736			12,182
	Other			10,674			10,365
	Intersegment eliminations			(100,828	)		(51,175	)
		Total operating revenues	$	754,651		$	746,209
RESOURCE COSTS:
	Avista Utilities		$	330,470		$	325,016
	Energy Marketing and Resource Management			121,448			82,566
	Intersegment eliminations			(100,828	)		(51,175	)
		Total resource costs	$	351,090		$	356,407
OPERATIONS AND MAINTENANCE EXPENSES:
	Avista Utilities		$	78,759		$	72,824
	Energy Marketing and Resource Management			—			—
	Avista Advantage			9,038			10,330
	Other			10,707			10,573
		Total operations and maintenance expenses	$	98,504		$	93,727
ADMINISTRATIVE AND GENERAL EXPENSES:
	Avista Utilities		$	48,883		$	45,005
	Energy Marketing and Resource Management			17,879			16,063
	Avista Advantage			4,927			5,084
	Other			1,638			12,073
		Total administrative and general expenses	$	73,327		$	78,225
DEPRECIATION AND AMORTIZATION EXPENSES:
	Avista Utilities		$	53,406		$	48,538
	Energy Marketing and Resource Management			978			1,031
	Avista Advantage			2,074			2,230
	Other			1,502			1,131
		Total depreciation and amortization expenses	$	57,960		$	52,930
INCOME FROM OPERATIONS (PRE-TAX):
	Avista Utilities		$	100,402		$	108,348
	Energy Marketing and Resource Management			31,319			25,299
	Avista Advantage			(1,303	)		(5,462	)
	Other			(3,200	)		(13,463	)
		Total income from operations	$	127,218		$	114,722
INCOME FROM CONTINUING OPERATIONS:
	Avista Utilities		$	19,944		$	24,788
	Energy Marketing and Resource Management			21,089			19,418
	Avista Advantage			(1,230	)		(3,551	)
	Other			(4,262	)		(10,523	)
		Total income from continuing operations	$	35,541		$	30,132
ASSETS (2002 amounts as of December 31):
	Avista Utilities		$	2,287,578		$	2,184,008
	Energy Marketing and Resource Management			996,492			1,349,626
	Avista Advantage			31,496			31,733
	Other			45,842			42,866
	Discontinued Operations			—			5,900
		Total assets	$	3,361,408		$	3,614,133
CAPITAL EXPENDITURES:
	Avista Utilities		$	64,617		$	46,823
	Energy Marketing and Resource Management			1,621			14,242
	Avista Advantage			265			139
	Other			800			155
		Total capital expenditures	$	67,303		$	61,359

The Accompanying Notes are an Integral Part of These Statements.

9

AVISTA CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The accompanying consolidated financial statements of Avista Corporation (Avista Corp. or the Company) for the interim periods ended September 30, 2003 and 2002 are unaudited but, in the opinion of management, reflect all adjustments necessary for a fair statement of the results of operations for those interim periods. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Consolidated Statements of Income and Comprehensive Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company’s audited consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002 (2002 Form 10-K).

Please refer to the section “Acronyms and Terms” in the 2002 Form 10-K for definitions of terms such as capacity, energy and therm.

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corp. is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. Avista Utilities, an operating division of Avista Corp. and not a separate entity, represents the regulated utility operations. Avista Utilities generates, transmits and distributes electricity in parts of eastern Washington and northern Idaho. Avista 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. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies engaged in the other non-utility lines of business.

The Company’s operations are exposed to risks including, but not limited to, the effects of: legislation and governmental regulations; the price and supply of purchased power, fuel and natural gas; recoverability of power and natural gas costs; streamflow and weather conditions; availability of generation facilities; competition; technology; and availability of funding. In addition, the energy business exposes the Company to the financial, liquidity, credit and commodity price risks associated with wholesale purchases and sales.

Basis of Reporting

The consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries. The accompanying financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants.

Use of Estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material impact on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein.

Business Segments

Financial information for each of the Company’s lines of business is reported in the Schedule of Information by Business Segments. Such information is an integral part of these consolidated financial statements. The business segment presentation reflects the basis currently used by the Company’s management to analyze performance and determine the allocation of resources. Avista Utilities’ business is managed based on the total regulated utility operation. The Energy Marketing and Resource Management line of business operations primarily include non-regulated electricity and natural gas marketing and resource management activities including performance-based optimization of energy assets owned by other entities and derivative commodity instruments such as futures, options, swaps and other contractual arrangements. Avista Advantage is a provider of internet-based facility intelligence, cost management, billing and information services to retail customers throughout North America. The Other line of business includes other investments and operations of various subsidiaries as well as the operations of Avista Capital on a parent company only basis.

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Avista Utilities Operating Revenues

Operating revenues for Avista Utilities related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, the amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded.

Avista Energy Operating Revenues

For all periods ending on or before December 31, 2002, Avista Energy followed Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” with respect to all contracts entered into after October 25, 2002. Effective January 1, 2003, Avista Energy follows SFAS No. 133 with respect to all contracts. Avista Energy reports the net margin on derivative commodity instruments accounted for under SFAS No. 133 as operating revenues. Revenues from contracts, which are not accounted for as derivatives under SFAS No. 133, are reported on a gross basis in operating revenues.

Avista Energy followed the mark-to-market method of accounting for energy contracts entered into for trading and price risk management purposes in compliance with Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” through December 31, 2002 for contracts entered into on or prior to October 25, 2002. Avista Energy recognized revenue based on the change in the market value of outstanding derivative commodity sales contracts, net of future servicing costs and reserves, in addition to revenue related to settled contracts. See Note 2 for a discussion of the rescission of EITF Issue No. 98-10 in October 2002.

Other Income-Net

Other income-net consisted of the following items for the three and nine months ended September 30 (dollars in thousands):

		Three months ended September 30,						Nine months ended September 30,
		2003			2002			2003			2002
Interest income		$	1,003		$	2,346		$	3,608		$	6,457
Interest on power and natural gas deferrals			2,417			2,083			6,255			7,526
Net gain (loss) on the disposition of assets			13			—			(206	)		1,844
Net gain (loss) on subsidiary investments			212			170			(1,264	)		(284	)
Other expense			(1,748	)		(2,032	)		(5,636	)		(5,196	)
Other income			276			451			1,630			4,284
	Total	$	2,173		$	3,018		$	4,387		$	14,631

Stock-Based Compensation

The Company follows the disclosure only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation.” Accordingly, employee stock options are accounted for under Accounting Principle Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.” Stock options are granted at exercise prices not less than the fair value of common stock on the date of grant. Under APB No. 25, no compensation expense is recognized pursuant to the Company’s stock option plans.

If compensation expense for the Company’s stock option plans were determined consistent with SFAS No. 123, net income and earnings per common share would have been the following pro forma amounts for the three and nine months ended September 30:

		Three months ended September 30,					Nine months ended September 30,
		2003		2002			2003		2002
Net income (loss) (dollars in thousands):
	As reported	$	4,320	$	(1,615	)	$	29,421	$	19,830
	Pro forma	$	3,607	$	(2,432	)	$	27,275	$	17,406
Earnings (loss) per common share, basic
	As reported	$	0.09	$	(0.05	)	$	0.59	$	0.38
	Pro forma	$	0.07	$	(0.06	)	$	0.54	$	0.33
Earnings (loss) per common share, diluted
	As reported	$	0.09	$	(0.05	)	$	0.58	$	0.38
	Pro forma	$	0.07	$	(0.06	)	$	0.54	$	0.33

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Goodwill

Goodwill arising from acquisitions represents the excess of the purchase price over the estimated fair value of net assets acquired. The Company evaluates goodwill for impairment on an annual basis or more frequently if impairment indicators arise.

Regulatory Deferred Charges and Credits

The Company prepares its consolidated financial statements in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” The Company prepares its financial statements in accordance with SFAS No. 71 because (i) the Company’s rates for regulated services are established by or subject to approval by an independent third-party regulator, (ii) the regulated rates are designed to recover the Company’s cost of providing the regulated services and (iii) in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover the Company’s costs. SFAS No. 71 requires the Company to reflect the impact of regulatory decisions in its financial statements. SFAS No. 71 requires that certain costs and/or obligations (such as incurred power and natural gas costs not currently recovered through rates, but expected to be recovered in the future) are reflected as deferred charges on the balance sheet. These costs and/or obligations are not reflected in the statement of income until the period during which matching revenues are recognized. If at some point in the future the Company determines that it no longer meets the criteria for continued application of SFAS No. 71 with respect to all or a portion of the Company’s regulated operations, the Company could be required to write off its regulatory assets. The Company could also be precluded from the future deferral of costs not recovered through rates at the time such costs were incurred, even if such costs were expected to be recovered in the future.

The Company’s primary regulatory assets include power and natural gas deferrals (see “Power Cost Deferrals and Recovery Mechanisms” and “Natural Gas Cost Deferrals and Recovery Mechanisms” below for further information), investment in exchange power, regulatory assets for deferred income taxes, unamortized debt expense, regulatory assets offsetting energy commodity derivative liabilities (see Note 5 for further information), demand side management programs, conservation programs and the provision for postretirement benefits. Those items without a specific line on the Consolidated Balance Sheets are included in other regulatory assets. Other regulatory assets consisted of the following as of September 30, 2003 and December 31, 2002 (dollars in thousands):

		September 30,		December 31,
		2003		2002
Regulatory asset for postretirement benefit obligation		$	4,373	$	4,728
Demand side management and conservation programs			21,025		23,733
Other			1,470		1,274
	Total	$	26,868	$	29,735

Deferred credits include, among other items, regulatory liabilities offsetting energy commodity derivative assets (see Note 5 for further information), regulatory liabilities created when the Centralia Power Plant was sold 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.

Natural Gas Benchmark Mechanism

The Idaho Public Utilities Commission (IPUC), Washington Utilities and Transportation Commission (WUTC) and Oregon Public Utilities Commission (OPUC) approved Avista Utilities’ Natural Gas Benchmark Mechanism in 1999. The mechanism eliminated the majority of natural gas procurement operations within Avista Utilities and consolidated natural gas procurement operations under Avista Energy, the Company’s non-regulated subsidiary. The ownership of the natural gas assets remains with Avista Utilities; however, the assets are managed by Avista Energy through an Agency Agreement. Avista Utilities continues to manage natural gas procurement for its California operations, which currently represents approximately four percent of its total natural gas therm sales.

The Natural Gas Benchmark Mechanism provides benefits to retail customers and allows Avista Energy to retain a portion of the benefits associated with asset optimization and the efficiencies gained in purchasing natural gas for Avista Utilities 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 Benchmark Mechanism and related Agency Agreement through January 29, 2004. In April 2003, the Company filed a request with the WUTC to amend certain aspects of the Natural Gas Benchmark Mechanism and related Agency Agreement and requested an extension

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through March 31, 2007. In July 2003, the WUTC staff and the Public Counsel Section of the Attorney General’s Office filed testimony recommending termination of the Natural Gas Benchmark Mechanism in Washington at the end of January 2004. The termination of the mechanism would likely result in natural gas procurement operations being performed by Avista Utilities for Washington natural gas customers. WUTC staff and Public Counsel have recommended that if the WUTC determines that the mechanism should not be terminated, the level of benefits provided to Avista Utilities’ customers be increased on a prospective basis. During August 2003, Avista Utilities filed its response to the WUTC staff and Public Counsel recommendations requesting the continuation of the Natural Gas Benchmark Mechanism and further explaining the benefits that customers receive by having natural gas procurement operations managed by Avista Energy as part of a larger natural gas portfolio. Hearings will be held before the WUTC during November 2003 to determine any changes and whether or not the Natural Gas Benchmark Mechanism and related Agency Agreement will be extended beyond January 29, 2004.

In accordance with SFAS No. 71, profits recognized by Avista Energy on natural gas sales to Avista Utilities, including gains and losses on natural gas contracts, are not eliminated in the consolidated financial statements. This is due to the fact that costs incurred by Avista Utilities for natural gas purchases to serve retail customers and for fuel for electric generation are expected to be recovered through future retail rates.

Power Cost Deferrals and Recovery Mechanisms

Avista Utilities defers the recognition in the income statement of certain power supply costs as approved by the WUTC. Deferred power supply costs are recorded as a deferred charge on the balance sheet for future review and the opportunity for recovery through retail rates. The power supply costs deferred include certain differences between actual power supply costs incurred by Avista Utilities and the costs included in base retail rates. This difference in power supply costs primarily results from changes in short-term wholesale market prices, changes in the level of hydroelectric generation and changes in the level of thermal generation (including changes in fuel prices). Avista Utilities accrues interest on deferred power costs in the Washington jurisdiction at a rate, which is adjusted semi-annually, of 8.8 percent as of September 30, 2003. Total deferred power costs for Washington customers were $127.8 million and $123.7 million as of September 30, 2003 and December 31, 2002, respectively.

In June 2002, the WUTC issued an order that became effective July 1, 2002. The order provided for the restructuring of rate increases previously approved by the WUTC totaling 31.2 percent. The general increase to base retail rates was 19.3 percent and the remaining 11.9 percent represents the continued recovery of deferred power costs. In the June 2002 rate order, the WUTC approved the establishment of an Energy Recovery Mechanism (ERM). The ERM replaced a series of temporary deferral mechanisms that were in place in Washington since mid-2000. The ERM allows Avista Utilities to increase or decrease electric rates 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 first $9.0 million in annual 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 Avista Utilities’ customers. The remaining 10 percent of power supply costs are an expense of, or benefit to, the Company.

Under the ERM, Avista Utilities agreed to make 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. The settlement agreement establishing the ERM provided for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by WUTC order. 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. Previous settlement agreements established the prudence and recoverability of power costs incurred through June 30, 2002. In May 2003, the WUTC staff, the Industrial Customers of Northwest Utilities (ICNU), and the Public Counsel Section of the Attorney General’s Office filed a motion requesting a pre-hearing conference related to Avista Utilities’ March 2003 ERM filing. As a result of that motion, a pre-hearing conference was held in May 2003 and an order was issued by the WUTC establishing a hearing schedule. The WUTC staff, the ICNU and Public Counsel filed testimony in August 2003 and Avista Utilities filed its response to this testimony in September 2003. The WUTC staff and the ICNU have taken the position that costs ranging from $2.0 million to $2.6 million associated with the delay of the Coyote Springs 2 project should be disallowed and removed from the deferred power cost balance. Public Counsel has taken the position that $14.0 million of losses on the sale of natural gas purchased for electric generation should be disallowed and removed from the deferred power cost balance. The Company believes that such costs were prudently incurred and in the best interest of its electric customers. The originally scheduled October 2003 evidentiary hearing has been delayed until December 2003 at the request of Public Counsel.

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Avista Utilities has a power cost adjustment (PCA) mechanism in Idaho that allows it to modify electric rates periodically with IPUC approval to recover or rebate a portion of the difference between actual net power supply costs and the amount included in base retail rates. The PCA mechanism allows for the deferral of 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. Avista Utilities accrues interest on deferred power costs in the Idaho jurisdiction at a rate, which is adjusted annually, of 2.0 percent on current year deferrals and 4.0 percent on carryover balances as of September 30, 2003. The IPUC originally approved a 19.4 percent surcharge in October 2001, which had been extended through October 2003. In October 2003, the IPUC issued another order extending the surcharge for an additional 60-day period while it continues to consider extending the surcharge for an additional 12 months. The IPUC staff filed comments recommending the continuation of the 19.4 percent PCA surcharge; however, they recommend the disallowance of approximately $5.9 million of deferred power costs. The recommended disallowance relates to natural gas purchased for electric generation under long-term contracts entered into during 2001 at a time of both high wholesale power and natural gas prices. The Company believes that such costs were prudently incurred and in the best interest of its electric customers and has requested that these costs be addressed in a general electric rate case that the Company plans to file in the first quarter of 2004. The IPUC staff comments also recommend that the Company work with the IPUC staff and customers with respect to its risk policies. Total deferred power costs for Idaho customers were $30.9 million and $31.5 million as of September 30, 2003 and December 31, 2002, respectively.

Natural Gas Cost Deferrals and Recovery Mechanisms

Under established regulatory practices in each respective state, Avista 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 gas costs 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 $17.6 million and $11.5 million as of September 30, 2003 and December 31, 2002, respectively.

Intersegment Eliminations

Intersegment eliminations represent the transactions between Avista Utilities and Avista Energy for energy commodities and services.

Reclassifications

Certain prior period amounts were reclassified to conform to current statement format. These reclassifications were made for comparative purposes and to conform to changes in accounting standards and have not affected previously reported total net income or common equity.

NOTE 2. NEW ACCOUNTING STANDARDS

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations” which addresses financial accounting and reporting for 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 impact on the Company’s financial condition or results of operations.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” which nullifies EITF Issue No. 94-3, “Liability Recognition for Certain Employee 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 disposal activity is recognized when the liability is incurred. Under EITF Issue No. 94-3, a liability for an exit cost was recognized at the date of an entity’s commitment to an exit plan. SFAS No. 146 also requires the initial measurement of the liability at fair value. This statement is effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of this statement did not have any impact on the Company’s financial condition or results of operations.

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In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure” which amends SFAS No. 123 “Accounting for Stock-Based Compensation.” This statement provides alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based compensation. In addition, this statement requires the disclosure of pro forma net income and earnings per common share had the Company adopted the fair value method of accounting for stock-based compensation in a more prominent place in the financial statements (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 financial statement disclosures are effective for fiscal years ending after December 15, 2002. Interim disclosures are required for periods ending after December 15, 2002. The adoption of this statement affects the Company’s disclosures. As the Company has not elected to adopt the fair value method of accounting for stock-based compensation, the adoption of this statement does not have any impact on the Company’s financial condition or results of operations.

In 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 SFAS No. 133; (2) in connection with other FASB projects dealing with financial 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 SFAS No. 149 that relate to SFAS No. 133 implementation issues 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 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 have been 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 5). In accordance with the provisions of SFAS No. 149, Avista Utilities recorded derivative liabilities of $0.7 million as of September 30, 2003.

In May 2003, the FASB issued SFAS 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 determinable date or upon an event that is certain to occur. This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise shall be 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 during the quarter ended September 30, 2003 requires the Company to classify $100.0 million of mandatorily redeemable preferred trust securities and $31.5 million of preferred stock subject to mandatory redemption as liabilities on the Consolidated Balance Sheet. The adoption of this statement also requires the Company to classify preferred stock dividends as interest expense in the Consolidated Statements of Income and Comprehensive 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 Avista Corp. to be greater than 65 percent at the end of any fiscal quarter.

Avista Energy accounted for energy commodity trading activity in compliance with EITF Issue No. 98-10 through December 31, 2002 for contracts entered into on or prior to October 25, 2002. Under EITF Issue No. 98-10, Avista Energy recognized revenue based on the change in the market value of outstanding derivative commodity sales contracts, net of future servicing costs and reserves, in addition to revenue related to settled contracts. In October 2002, the EITF rescinded Issue No. 98-10. As such, Avista Energy is required to account for energy trading contracts that meet the definition of a derivative at market value in compliance with SFAS No. 133. This statement now applies to all contracts as of January 1, 2003. Contracts not meeting the definition of a derivative are no longer accounted for at market value and include Avista Energy’s Agency Agreement with Avista Utilities, natural gas storage contracts, tolling agreements and natural gas transportation agreements. The transition from EITF Issue No. 98-10 to accrual based accounting resulted in the adjustment of the contracts not considered derivatives, from their market value to their cost basis. Any gains or losses on contracts that are not considered derivatives are recognized

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when the contracts are settled or realized. The Company anticipates that the changes will primarily affect the timing of the recognition of income or loss in earnings, and not change the underlying economics or cash flows of transactions entered into by Avista Energy. The transition to SFAS No. 133 increased the volatility in reported earnings due to the fact that certain contracts, which are not considered derivatives, economically hedge contracts that are accounted for as derivative instruments at market value under SFAS No. 133. During September 2003, Avista Energy implemented hedge accounting for certain transactions (see Note 6). This should partially mitigate the effects from the transition to SFAS No. 133 and reduce the volatility of reporting earnings on a prospective basis. On January 1, 2003, Avista Energy recorded as a cumulative effect of accounting change a charge of $1.2 million (net of tax) related to the transition from EITF Issue No. 98-10 to SFAS No. 133.

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 SFAS No. 5, “Accounting for Contingencies” relating to a guarantor’s accounting for, and disclosure of, the issuance of certain types of guarantees. This interpretation requires that upon issuance of a guarantee, the guarantor must recognize a liability for the fair value of the obligation it assumes under that guarantee. The initial recognition and measurement provisions of this interpretation are to be applied on a prospective basis to guarantees issued or modified subsequent to December 31, 2002 and did not have a material impact on the Company’s financial condition or results of operations. The disclosure requirements of this interpretation are effective for financial statements issued for periods that end after December 15, 2002.

In October 2003, the FASB delayed the implementation of Interpretation No. 46, “Consolidation of Variable Interest Entities” 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 financial resources for the entity to support its activities. Variable interest entities are commonly referred to as special purpose entities or off-balance sheet structures; however, this FASB interpretation applies to a broader group of entities. This interpretation requires a variable interest entity to be consolidated by the primary beneficiary of that entity. The primary beneficiary is subject to a majority of the risk of loss from the variable interest entity’s activities or it is entitled to receive a majority of the entity’s residual returns. The interpretation also requires disclosure of variable interest entities that a company is not required to consolidate but in which it has a significant variable interest. The consolidation requirements of this interpretation apply immediately to variable interest entities created after January 31, 2003 and apply to existing entities for the first fiscal year or interim period ending after December 15, 2003. Certain disclosure requirements apply to all financial statements issued after January 31, 2003, regardless of when the variable interest entity was established.

FASB Interpretation No. 46 will require the Company to consolidate WP Funding LP effective for the period ended December 31, 2003. WP Funding LP is an entity that was formed in 1993 for the purpose of acquiring the natural gas-fired combustion turbine generating facility in Rathdrum, Idaho (Rathdrum CT). WP Funding LP purchased the Rathdrum CT from the Company with funds provided by unrelated investors of which 97 percent represented debt and 3 percent represented equity. The Company operates the Rathdrum CT and leases it from WP Funding LP. The total amount of WP Funding LP debt outstanding was $54.6 million as of September 30, 2003. The lease term expires in February 2020; however, the current debt matures in October 2005 and will need to be refinanced at that time. As of September 30, 2003, the book value of the debt and equity of WP Funding LP exceeds the book value of the Rathdrum CT by $16.1 million. In accordance with regulatory accounting practices, the Company will record this amount as a regulatory asset upon the consolidation of WP Funding LP. The addition of the Rathdrum CT to Avista Utilities’ generation resource base, which entered commercial operation in 1995, was reviewed in previous state regulatory filings with the WUTC and IPUC. Based on September 30, 2003 amounts, the consolidation of WP Funding LP will increase long-term debt by $54.6 million, net utility plant by $40.2 million, regulatory assets by $16.1 million and other liabilities by $1.7 million (representing minority interest). The adoption of this FASB interpretation will 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 Avista Corp. to be greater than 65 percent at the end of any fiscal quarter.

Based on current interpretations, the Company believes that FASB Interpretation No. 46 will result in the Company no longer including Avista Capital I and Avista Capital II in its consolidated financial statements for the period ended December 31, 2003. Avista Capital I and Avista Capital II are business trusts formed 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 Avista Corp. The sole assets of Avista Capital I and Avista 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 FASB Interpretation No. 46. As Avista Corp. is not the primary

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beneficiary, these entities will no longer be included in Avista Corp.’s consolidated financial statements. The removal of Avista Capital I and Avista Capital II will result in a decrease in preferred trust securities of $100.0 million, an increase in long-term debt of $113.4 million and an increase in other property and investments 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).

NOTE 3. DISCONTINUED OPERATIONS

In July 2003, Avista Corp. announced an investment of $6.0 million by a group of private equity investors in a new entity, AVLB, Inc., which acquired the assets previously held by Avista Corp.’s fuel cell manufacturing and development subsidiary, Avista Labs. In September 2003, AVLB, Inc. (doing business under the name Avista Labs) received an additional investment by private equity investors of $6.2 million. This investment relieved Avista Corp. of its commitment to provide additional funding of up to $1.5 million to AVLB, Inc. Avista Corp. has an ownership interest of approximately 17.5 percent in AVLB, Inc., with the opportunity but no further obligation to fund or invest in this business. Avista Corp.’s investment in AVLB, Inc. is accounted for under the cost method.

In September 2001, the Company reached a decision that it would dispose of substantially all of the assets of Avista Communications. The divestiture of the operating assets of Avista Communications was complete by the end of 2002. Revenues for Avista Communications were $0.5 million and $3.5 million for the three and nine months ended September 30, 2002, respectively.

Amounts reported as discontinued operations for the three and nine months ended September 30, 2003 represent the operations of Avista Labs. Amounts reported as discontinued operations for the three and nine months ended September 30, 2002 represents the operations of Avista Labs and Avista Communications as follows:

			Avista Labs			Avista Communications			Total
Three months ended September 30, 2002
	Loss before income taxes		$	(3,613	)	$	(80	)	$	(3,693	)
	Income tax benefit (expense)			1,667			(453	)		1,214
		Loss from discontinued operations	$	(1,946	)	$	(533	)	$	(2,479	)
Nine months ended September 30, 2002
	Income (loss) before income taxes		$	(10,410	)	$	1,059		$	(9,351	)
	Income tax benefit (expense)			4,047			(850	)		3,197
		Income (loss) from discontinued operations	$	(6,363	)	$	209		$	(6,154	)

NOTE 4. ACCOUNTS RECEIVABLE SALE

In 1997, Avista Receivables Corp. (ARC), formerly known as WWP Receivables Corp., was formed as a wholly owned, bankruptcy-remote subsidiary of the Company for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On May 29, 2002, ARC, the Company and a third-party financial institution entered into a three-year agreement whereby ARC can sell without recourse, on a revolving basis, up to $100.0 million of those receivables. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. On a consolidated basis, the amount of such fees is included in operating expenses of the Company. As of September 30, 2003 and December 31, 2002, $40.0 million and $65.0 million, respectively, in accounts receivables were sold under this revolving agreement.

NOTE 5. UTILITY ENERGY COMMODITY DERIVATIVE ASSETS AND LIABILITIES

SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires the recording of all derivatives as either assets or liabilities 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.

Avista Utilities enters into forward contracts to purchase or sell energy. Under these forward contracts, Avista Utilities commits to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. Certain of these forward contracts are considered derivative instruments. Avista Utilities also records

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derivative commodity assets and liabilities for over-the-counter and exchange-traded derivative instruments as well as certain long-term contracts. These contracts are entered into to manage Avista Utilities’ loads and resources as discussed in Note 6. In conjunction with the issuance of SFAS 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 Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income and Comprehensive Income. Such realized gains or losses are recognized in the period of settlement subject to current or future recovery in retail rates. Realized gains and losses are reflected as adjustments through purchased gas cost adjustments, the ERM and the PCA mechanism.

Prior to the adoption of SFAS No. 149 on July 1, 2003, Avista Utilities believed substantially all of its purchases and sales contracts for both capacity and energy qualified as normal purchases and sales under SFAS No. 133 and were not required to be recorded 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. In accordance with the provisions of SFAS No. 149, Avista Utilities recorded derivative liabilities of $0.7 million as of September 30, 2003. Contracts that are not considered derivatives under SFAS No. 133 are generally accounted for at cost until they are settled, unless there is a decline in the fair value of the contract that is determined to be other than temporary.

As of September 30, 2003, the utility derivative commodity asset balance was $52.4 million, the derivative commodity liability balance was $43.6 million and the offsetting net regulatory liability was $8.8 million. As of December 31, 2002, the utility derivative commodity asset balance was $60.3 million, the derivative commodity liability balance was $50.1 million and the offsetting net regulatory 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 derivative commodity asset balance is included in Deferred Charges – Utility energy commodity derivative assets and the derivative commodity liability balance is included in Non-Current Liabilities and Deferred Credits – Utility energy commodity derivative liabilities on the Consolidated Balance Sheet. The offsetting net regulatory asset is included in Deferred Charges – Other regulatory assets and the offsetting net regulatory liability is included in Non-Current Liabilities and Deferred Credits – Other non-current liabilities and deferred credits on the Consolidated Balance Sheet.

Interpretations that may be issued by the Derivatives Implementation Group, a task force created to assist the FASB in answering questions that companies have in implementing SFAS No. 133, may change the conclusions that the Company has reached regarding accounting for energy contracts. As a result, the accounting treatment and financial statement impact could change in future periods.

NOTE 6. ENERGY COMMODITY MANAGEMENT AND TRADING

The Company’s energy-related businesses are exposed to risks relating to, but not limited to, changes in certain commodity prices and counterparty performance. In order to manage the various risks relating to these exposures, Avista Utilities utilizes electric, natural gas and related derivative commodity instruments, such as forwards, futures, swaps and options, and Avista Energy engages in the trading of such instruments. Avista Utilities and Avista Energy have policies and procedures to manage risks inherent in these activities. The Company has a Risk Management Committee, separate from the units that create such risk exposure, that is overseen by the Audit Committee of the Company’s Board of Directors, to monitor compliance with the Company’s risk management policies and procedures.

Avista Utilities

Avista Utilities 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. Avista 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 and including long-term contracts that extend beyond one year. Avista Utilities makes continuing projections of (1) future retail and wholesale loads based on, among other things, forward estimates of factors such as customer usage and weather as well as historical data and contract terms and (2) resource availability based on, among other things, estimates of streamflows, generating unit availability, historic and forward

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market information and experience. On the basis of these continuing projections, Avista 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 Avista Utilities’ own resources, as well as other wholesale transactions to capture the value of available generation and transmission resources. This optimization process includes hedging transactions as a means of managing risks.

Avista Utilities manages the impact of fluctuations in electric energy prices by establishing volume limits for the imbalance between projected loads and resources and through the use of derivative commodity instruments for hedging purposes. Any imbalance is required to remain within limits, or management action or decisions are triggered to address larger imbalance situations and manage the exposure to market risk. Avista Energy is responsible for the daily management of natural gas supplies to meet the requirements of Avista Utilities’ customers in the states of Washington, Idaho and Oregon (see description of Natural Gas Benchmark Mechanism in Note 1). Avista Utilities continues to manage natural gas procurement for its California operations, which currently represents approximately four percent of its total natural gas therm sales.

The Risk Management Committee has limited the types of commodity instruments Avista Utilities may use to those related to electricity and natural gas commodities and those instruments are to be used for hedging price fluctuations associated with the management of energy resources owned or under contract by Avista Utilities.

Avista Energy

Avista Energy is an electricity and natural gas marketing and resource management business. Avista Energy focuses on asset-backed optimization of combustion turbines and hydroelectric assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric and natural gas transmission and transportation arrangements. Avista Energy is also involved in the trading of electricity and natural gas, including derivative commodity instruments.

Effective January 1, 2003, Avista Energy accounts for energy trading contracts that meet the definition of a derivative in compliance with SFAS No. 133. Contracts not meeting the definition of a derivative are accounted for on an accrual basis. Avista Energy accounted for energy commodity trading activity in compliance with EITF Issue No. 98-10 through December 31, 2002 for contracts entered into on or prior to October 25, 2002. In October 2002, the EITF rescinded Issue No. 98-10, which required Avista Energy to adopt SFAS No. 133. See Note 2 for further details.

Avista Energy purchases natural gas and electricity from producers and energy marketing and trading companies. Its customers include commercial and industrial end-users, electric utilities, natural gas distribution companies, and energy marketing and trading companies. Avista Energy’s marketing and energy risk management services are provided through the use of a variety of derivative commodity contracts to purchase or supply natural gas and electric energy at specified delivery points and at specified future dates. Avista Energy trades natural gas and electricity derivative commodity instruments on national exchanges and through other unregulated exchanges and brokers from whom these commodity derivatives are available, and therefore can experience net open positions in terms of price, volume, and specified delivery point. The open positions expose Avista Energy to the risk that fluctuating market prices may adversely impact its financial condition or results of operations. However, the net open position is actively managed with strict policies designed to limit the exposure to market risk and requires daily reporting to management of potential financial exposure.

Avista Energy measures the risk in its electric and natural gas portfolio daily utilizing a Value-at-Risk (VAR) model, monitoring its risk in comparison to established thresholds. VAR measures the expected portfolio loss under hypothetical adverse price movements over a given time interval within a given confidence level. Avista Energy also measures its open positions in terms of volumes at each delivery location for each forward time period. The extent of open positions is included in the risk management policy and is measured with stress tests and VAR modeling.

Derivative commodity instruments sold and purchased by Avista Energy include: forward contracts, which involve physical delivery of an energy commodity; futures contracts, which involve the buying or selling of natural gas or electricity at a fixed price; over-the-counter swap agreements, which require Avista Energy to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity; and options, which mitigate price risk by providing for the right, but not the requirement, to buy or sell energy-related

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commodities at a fixed price. Foreign currency risks are primarily related to Canadian exchange rates and are managed using standard instruments available in the foreign currency markets.

Avista Energy’s derivative commodity instruments accounted for under SFAS No. 133 are subject to mark-to-market accounting, under which changes in the market value of outstanding electric, natural gas and related derivative commodity instruments are recognized as unrealized gains or losses in the period of change. Market prices are utilized in determining the value of the electric, natural gas and related derivative commodity instruments. For electric derivative commodity instruments, these market prices are generally available through two years. For natural gas derivative commodity instruments, these market prices are generally available through three years. For longer-term positions and certain short-term positions for which market prices are not available, a model to estimate forward price curves is utilized. Avista Energy reports the net margin on derivative commodity instruments accounted for under SFAS No. 133 as operating revenues. Revenues from contracts, which are not accounted for as derivatives under SFAS No. 133, are reported on a gross basis in operating revenues. Costs from contracts, which are not accounted for as derivatives under SFAS No. 133, are reported on a gross basis in resource costs. Contracts in a receivable position, as well as the options held, are reported as assets. Similarly, contracts in a payable position, as well as options written, are reported as liabilities. Net cash flows are recognized in the period of settlement.

Avista Energy implemented hedge accounting in accordance with SFAS No. 133 during the third quarter of 2003. Specific natural gas and electric trading derivative contracts have been designated as hedging instruments in cash flow hedging relationships. The hedge strategies represent cash flow hedges of the variable price risk associated with expected purchases of natural gas and sales of electricity. These designated hedging instruments represent hedges of variable price exposures generated from certain contracts, which do not qualify as derivatives under SFAS No. 133. For all derivatives designated as cash flow hedges, Avista Energy documents the relationship between the hedging instrument and the hedged item (forecasted purchases and sales of power and natural gas), as well as the risk management objective and strategy for using the hedging instrument. Avista Energy assesses whether change in the value of the designated derivative is highly effective in achieving offsetting cash flows attributable to the hedged item, both at the inception of the hedge and on an ongoing basis. Any change in the fair value of the designated derivative that is effective, is recorded in accumulated other comprehensive income or loss, while changes in fair value that is not effective is recognized currently in earnings as operating revenues. Amounts recorded in accumulated other comprehensive income or loss are recognized in earnings during the period that the hedged item is recognized in earnings.

During the third quarter of 2003, a loss of $0.1 million related to hedge ineffectiveness was recorded in earnings as a reduction of operating revenues. As of September 30, 2003, there was a loss of $0.2 million (net of tax) in accumulated other comprehensive loss related to designated cash flow hedges, while no amounts in accumulated other comprehensive loss were recognized in earnings during the third quarter. Of the amount in accumulated other comprehensive loss as of September 30, 2003, $0.1 million is expected to be recognized in earnings during the next 12 months. The actual amounts that will be recognized in earnings during the next 12 months will vary from the expected amounts as a result of changes in market prices. The maximum term of the designated hedging instruments was 18 months.

Contract Amounts and Terms Under Avista Energy’s derivative instruments, Avista Energy either (i) as “fixed price payor,” is obligated to pay a fixed price or a fixed amount and is entitled to receive the commodity or a fixed amount or (ii) as “fixed price receiver,” is entitled to receive a fixed price or a fixed amount and is obligated to deliver the commodity or pay a fixed amount or (iii) as “index price payor,” is obligated to pay an indexed price or an indexed amount and is entitled to receive the commodity or a variable amount or (iv) as “index price receiver,” is entitled to receive an indexed price or amount and is obligated to deliver the commodity or pay a variable amount.

The contract or notional amounts and terms of Avista Energy’s derivative commodity investments outstanding as of September 30, 2003 are set forth below (in thousands of mmBTUs and MWhs):

Fixed

Fixed

Maximum

Index

Index

Maximum

Price

Price

Terms in

Price

Price

Terms in

Payor

Receiver

Years

Payor

Receiver

Years

Energy commodities (volumes)

Electric

78,546

77,764

14

599

209

3

Natural gas

64,216

43,210

6

365,621

392,455

3

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Contract or notional amounts reflect the volume of transactions, but do not necessarily represent the dollar amounts exchanged by the parties to the derivative commodity instruments. Accordingly, contract or notional amounts do not accurately measure Avista Energy’s exposure to market or credit risks. The maximum terms in years detailed above are not indicative of likely future cash flows as these positions may be offset in the markets at any time.

Estimated Fair Value The estimated fair value of Avista Energy’s derivative commodity instruments outstanding as of September 30, 2003, and the average estimated fair value of those instruments held during the nine months ended September 30, 2003, are set forth below (dollars in thousands):

	Estimated Fair Value								Average Estimated Fair Value for the
	as of September 30, 2003								nine months ended September 30, 2003
	Current		Long-term		Current		Long-term		Current		Long-term		Current		Long-term
	Assets		Assets		Liabilities		Liabilities		Assets		Assets		Liabilities		Liabilities
Electric	$	156,306	$	275,345	$	132,830	$	236,400	$	276,504	$	312,240	$	255,788	$	279,403
Natural gas		42,405		8,859		27,237		4,755		100,376		15,417		73,565		12,741
Total	$	198,711	$	284,204	$	160,067	$	241,155	$	376,880	$	327,657	$	329,353	$	292,144

The weighted average term of Avista Energy’s electric derivative commodity instruments as of September 30, 2003 was approximately 6 months. The weighted average term of Avista Energy’s natural gas derivative commodity instruments as of September 30, 2003 was approximately 3 months. The change in the estimated fair value position of Avista Energy’s energy commodity portfolio, net of reserves for credit and market risk for the nine months ended September 30, 2003 was an unrealized loss of $11.0 million and is included in the Consolidated Statements of Income and Comprehensive Income in operating revenues. The change in the fair value position for the nine months ended September 30, 2002 was an unrealized loss of $87.4 million.

Market Risk

Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Market risk is influenced to the extent that the performance or nonperformance by market participants of their contractual obligations and commitments affect the supply of, or demand for, the commodity.

Avista Utilities and Avista Energy manage, on a portfolio basis 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. Avista Energy measures the risk in its portfolio on a daily basis utilizing a VAR model and monitors its risk in comparison to established thresholds.

Credit Risk

Credit risk relates to the risk of loss that Avista Utilities and/or Avista Energy would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy and make financial settlements. Credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. Avista Utilities and Avista Energy seek to mitigate credit risk by applying specific eligibility criteria to existing and prospective counterparties and by actively monitoring current credit exposures. These policies include an evaluation of the financial condition and credit ratings of counterparties, collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees, and the use of standardized agreements that allow for the netting or offsetting of positive and negative exposures associated with a single counterparty.

Avista Energy has concentrations of suppliers and customers in the electric and natural gas industries including electric utilities, natural gas distribution companies, and other energy marketing and trading companies. In addition, Avista Energy has concentrations of credit risk related to geographic location as Avista Energy operates primarily in the western United States and western Canada. These concentrations of counterparties and concentrations of geographic location may impact Avista Energy’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

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Credit risk also involves the exposure that counterparties perceive related to performance by Avista Utilities and Avista Energy to perform deliveries and settlement of energy transactions. These counterparties may seek assurance of performance in the form of letters of credit, prepayment or cash deposits, and, in the case of Avista Energy, parent company (Avista Capital) performance guarantees. In periods of price volatility, the level of exposure can change significantly, with the result that sudden and significant demands may be made against the Company’s capital resource reserves (credit facilities and cash). Avista Utilities and Avista Energy actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements.

Other Operating Risks

In addition to commodity price risk, Avista Utilities’ commodity positions are subject to operational and event risks including, among others, increases in load demand, transmission or transport disruptions, fuel quality specifications, a change in regulatory requirements, forced outages at generating plants and disruptions to information systems and other administrative tools required for normal operations. Avista Utilities also has exposure to weather conditions and natural disasters that can cause physical damage to property, requiring immediate repairs to restore utility service. The emergence of terrorism threats, both domestic and foreign, is a risk to the entire utility industry, including Avista 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 in the event that its facilities are targeted.

NOTE 7. 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 September 30, 2003 and December 31, 2002, the Company had $85.0 million and $30.0 million, respectively, of borrowings outstanding under this committed line of credit. As of September 30, 2003 and December 31, 2002, there were $11.0 million and $14.3 million in letters of credit outstanding, respectively. The committed line of credit is secured by $245.0 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 permit the ratio of “consolidated total debt” (not including preferred securities) to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at the end of any fiscal quarter. As of September 30, 2003, the Company was in compliance with this covenant with a ratio of 53.8 percent. The committed line of credit also has a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the twelve-month period ending September 30, 2003 to be greater than 1.6 to 1. As of September 30, 2003, the Company was in compliance with this covenant with a ratio of 2.18 to 1.

On July 25, 2003, Avista Energy and its subsidiary, Avista Energy Canada, Ltd., as co-borrowers, entered into a committed credit agreement with a group of banks in the aggregate amount of $110.0 million expiring July 23, 2004, replacing a previous uncommitted credit agreement that had an extended expiration date of July 31, 2003. This new committed credit facility provides for the issuance of letters of credit to secure contractual obligations to counterparties. This facility is guaranteed by Avista Capital and secured by Avista Energy’s assets. The maximum amount of credit extended by the banks for the issuance of letters of credit is the subscribed amount of the facility less the amount of outstanding cash advances, if any. The maximum amount of credit extended by the banks for cash advances is $30.0 million. No cash advances were outstanding as of September 30, 2003 and December 31, 2002. Letters of credit in the aggregate amount of $32.2 million and $17.4 million were outstanding as of September 30, 2003 and December 31, 2002, respectively.

The Avista Energy credit agreement contains customary covenants and default provisions, including covenants to maintain “minimum net working capital” and “minimum net worth”, as well as a covenant limiting the amount of indebtedness which the co-borrowers may incur. The credit agreement also contains covenants and other restrictions related to Avista Energy’s trading limits and positions, including VAR limits, restrictions with respect to changes in risk management policies or volumetric limits, and limits on exposure related to hourly and daily trading of electricity. Also, a reduction in the credit rating of Avista Corp. would represent an event of default under Avista Energy’s credit agreement. These covenants as well as certain counterparty agreements result in Avista Energy

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maintaining certain levels of cash and therefore inherently limiting the amount of cash dividends that are available for distribution to Avista Capital and ultimately to Avista Corp. Avista Energy was in compliance with the covenants of its credit agreement as of September 30, 2003.

NOTE 8. LONG-TERM DEBT

The following details the interest rate and maturity dates of long-term debt outstanding as of September 30, 2003 and December 31, 2002 (dollars in thousands):

Maturity				Interest			September 30,			December 31,
Year		Description		Rate			2003			2002
	2003	Secured Medium-Term Notes			6.25	%	$	15,000		$	15,000
	2005	Secured Medium-Term Notes			6.39%-6.68	%		29,500			29,500
	2006	Secured Medium-Term Notes			7.89%-7.90	%		30,000			30,000
	2007	First Mortgage Bonds			7.75	%		150,000			150,000
	2008	Secured Medium-Term Notes			6.89%-6.95	%		20,000			20,000
	2010	Secured Medium-Term Notes			6.67%-6.90	%		10,000			10,000
	2012	Secured Medium-Term Notes			7.37	%		7,000			7,000
	2013	First Mortgage Bonds			6.13	%		45,000			—
	2018	Secured Medium-Term Notes			7.26%-7.45	%		27,500			27,500
	2023	Secured Medium-Term Notes			7.18%-7.54	%		24,500			24,500
			Total secured long-term debt					358,500			313,500
	2003	Unsecured Medium-Term Notes			6.75%-9.13	%		—			56,250
	2004	Unsecured Medium-Term Notes			7.42	%		28,500			30,000
	2006	Unsecured Medium-Term Notes			8.14	%		8,000			8,000
	2007	Unsecured Medium-Term Notes			5.99%-7.94	%		25,850			26,000
	2008	Senior Notes			9.75	%		317,746			341,529
	2008	Unsecured Medium-Term Notes			6.06	%		25,000			25,000
	2010	Unsecured Medium-Term Notes			8.02	%		25,000			25,000
	2012	Unsecured Medium-Term Notes			8.05	%		—			12,000
	2022	Unsecured Medium-Term Notes			8.15%-8.23	%		5,000			10,000
	2023	Unsecured Medium-Term Notes			7.99	%		5,000			5,000
	2023	Pollution Control Bonds			6.00	%		4,100			4,100
	2028	Unsecured Medium-Term Notes			6.37%-6.88	%		25,000			35,000
	2032	Pollution Control Bonds			5.00	%		66,700			66,700
	2034	Pollution Control Bonds			5.13	%		17,000			17,000
			Total unsecured long-term debt					552,896			661,579
			Other long-term debt					6,025			1,613
			Unamortized debt discount					(2,090	)		(2,161	)
			Total					915,331			974,531
			Current portion of long-term debt					(16,283	)		(71,896	)
			Total long-term debt				$	899,048		$	902,635

The following table details the Company’s debt repurchases prior to scheduled maturity from January 1, 2003 through September 30, 2003 (dollars in thousands):

Repurchase			Interest			Maturity		Principal
Date	Description		Rate			Year		Amount
January 2003	Unsecured Senior Notes			9.75	%		2008	$	10,000
February 2003	Unsecured Senior Notes			9.75	%		2008		505
March 2003	Unsecured Medium-Term Notes			8.23	%		2022		5,000
April 2003	Unsecured Medium-Term Notes			6.88	%		2028		10,000
May 2003	Unsecured Medium-Term Notes			5.99	%		2007		150
June 2003	Unsecured Medium-Term Notes			7.42	%		2004		1,500
July 2003	Unsecured Medium-Term Notes			8.05	%		2012		12,000
July 2003	Unsecured Senior Notes			9.75	%		2008		3,000
August 2003	Unsecured Senior Notes			9.75	%		2008		10,330
		Total debt repurchases						$	52,485

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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.

In September 2003, the Company issued $45.0 million of 6.125 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.

NOTE 9. 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 rate swap 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 LIBOR. With the termination of the interest rate swap agreement, Avista Corp. received $1.5 million, which was 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).

Rathdrum Power, LLC (RP LLC), an unconsolidated entity that is 49 percent owned by Avista Power, operates a 270 MW natural gas-fired combustion turbine plant in northern Idaho (Lancaster Project). As of September 30, 2003, RP LLC had $118.0 million of debt outstanding that is not included in the consolidated financial statements of the Company. There is no recourse to the Company with respect to this debt. RP LLC has entered into two interest rate swap agreements, maturing in 2006, to manage the risk that changes in interest rates may affect the amount of future interest payments. RP LLC agreed to pay fixed rates of interest with the differential paid or received under the interest rate swap agreements recognized as an adjustment to interest expense. These interest rate swap agreements are considered hedges against fluctuations in future cash flows associated with changes in interest rates in accordance with SFAS No. 133. The fair value of the interest rate swap agreements was determined by reference to market values obtained from various third party sources. Avista Power’s 49 percent ownership interest in RP LLC is accounted for under the equity method of accounting. As of September 30, 2003, there was an unrealized loss of $1.4 million recorded as accumulated other comprehensive loss on the Consolidated Balance Sheet.

NOTE 10. PREFERRED STOCK-CUMULATIVE

In March 2003, the Company redeemed 17,500 shares of preferred stock for $1.6 million, satisfying its redemption requirement for 2003.

NOTE 11. EARNINGS PER COMMON SHARE

The following table presents the computation of basic and diluted earnings per common share for the three and nine months ended September 30 (in thousands, except per share amounts):

		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2003			2002			2003			2002
Numerator:
Income from continuing operations		$	4,386		$	864		$	35,541		$	30,132
Loss from discontinued operations			(66	)		(2,479	)		(4,930	)		(6,154	)
Net income (loss) before cumulative effect of accounting change			4,320			(1,615	)		30,611			23,978
Cumulative effect of accounting change			—			—			(1,190	)		(4,148	)
Net income (loss)			4,320			(1,615	)		29,421			19,830
Deduct: Preferred stock dividend requirements			—			608			1,125			1,824
Income (loss) available for common stock		$	4,320		$	(2,223	)	$	28,296		$	18,006
Denominator:
Weighted-average number of common shares outstanding-basic			48,281			47,866			48,202			47,771
Effect of dilutive securities:
	Restricted stock *		—			—			—			2
	Contingent stock		203			—			203			—
	Stock options *		207			—			109			69
Weighted-average number of common shares outstanding-diluted			48,691			47,866			48,514			47,842

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		Three Months Ended					Nine Months Ended
		September 30,					September 30,
		2003		2002			2003			2002
Earnings (loss) per common share, basic:
	Earnings per common share from continuing operations	$	0.09	$	0.00		$	0.72		$	0.60
	Loss per common share from discontinued operations		—		(0.05	)		(0.10	)		(0.13	)
	Earnings (loss) per common share before cumulative effect of accounting change		0.09		(0.05	)		0.62			0.47
	Loss per common share from cumulative effect of accounting change		—		—			(0.03	)		(0.09	)
	Total earnings (loss) per common share, basic	$	0.09	$	(0.05	)	$	0.59		$	0.38
Earnings (loss) per common share, diluted:
	Earnings per common share from continuing operations	$	0.09	$	0.00		$	0.71		$	0.60
	Loss per common share from discontinued operations		—		(0.05	)		(0.10	)		(0.13	)
	Earnings (loss) per common share before cumulative effect of accounting change		0.09		(0.05	)		0.61			0.47
	Loss per common share from cumulative effect of accounting change		—		—			(0.03	)		(0.09	)
	Total earnings (loss) per common share, diluted	$	0.09	$	(0.05	)	$	0.58		$	0.38

* Due to the loss from continuing operations for the three months ended September 30, 2002, the common stock equivalents from outstanding restricted stock and stock options are not included in the calculation for weighted-average number of common shares outstanding for diluted loss per common share because the effect is antidilutive.

NOTE 12. 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 the consolidated financial condition of the Company, but could be material to results of operations or cash flows for a particular quarter or annual period. No assurance can be given, however, as to the ultimate outcome with respect to any particular issue.

Federal Energy Regulatory Commission Inquiry

In February 2002, the Federal Energy Regulatory Commission (FERC) issued an order commencing a fact-finding investigation of potential manipulation of electric and natural gas prices in the California energy markets by multiple companies. On May 8, 2002, the FERC requested data and information with respect to certain trading strategies that companies may have engaged in. Specifically, the requests inquired as to whether or not the Company engaged in certain trading strategies that were the same or similar to those used by Enron Corporation (Enron) and its affiliates. These requests were made to all sellers of wholesale electricity and/or ancillary services in power markets in the western United States during 2000 and 2001, including Avista Corp. and Avista Energy. On May 22, 2002, Avista Corp. and Avista Energy filed their responses to this request indicating that both companies had engaged in sound business practices in accordance with established market rules, and that no information was evident from business records or employee interviews that would indicate that Avista Corp. or Avista Energy, or its employees, were knowingly engaged in these trading strategies, or any variant of the strategies.

On June 4, 2002, the FERC issued an additional order to Avista Corp. and three other companies requiring these companies to show cause within ten days as to why their authority to charge market-based rates should not be revoked. In this order, the FERC alleged that Avista Corp. failed to respond fully and accurately to the data request made on May 8, 2002. On June 14, 2002, Avista Corp. 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 of the investigation was to determine whether Avista Corp. and Avista Energy engaged in or facilitated certain Enron trading strategies, whether Avista Corp.’s or Avista Energy’s role in transactions with EPMI and PGE resulted in the circumvention of a code of conduct governing transactions with affiliates, and the imposition of any appropriate remedies such as refunds and revocation of market-based rates. The

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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, Avista Corp. and Avista Energy filed a joint motion announcing that the parties had reached an agreement in principle and requesting 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, Avista Corp. and Avista Energy. PGE filed comments supporting the agreement in resolution, but took exception to how certain transactions were reported. On March 3, 2003, Avista Corp. and Avista Energy 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 Avista Corp., Avista 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 final 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, Avista Corp. and Avista 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 staff be delayed to further address certain issues and to allow for potential uncertainty to be removed with respect to the final resolution of the case. The FERC’s administrative law judge agreed and ordered a further prehearing 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’s administrative law judge held a further prehearing conference on May 20, 2003, at which time the FERC trial staff reviewed its findings 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. Avista Corp., Avista 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 final 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 filed 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 defining improper trading activities with the effect of further validating the findings of the FERC trial staff’s 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

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asking for clarification and reconsideration of the June 25, 2003 order. The FERC’s trial staff requested that the agreement in resolution be certified and forwarded to the FERC commissioners for final 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 staff’s July 10, 2003 motion for reconsideration. In the order, the judge found that there are no unresolved issues of material fact and that the record is 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 final approval. In reaching this conclusion, the FERC’s administrative law judge considered the July 10, 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 states that “the Chief Judge further finds 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’s 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.

U.S. Commodity Futures Trading Commission (CFTC) Subpoena

Beginning on June 17, 2002, the CFTC issued several subpoenas directing Avista Corp. and Avista Energy to produce certain materials, make employees available to respond to certain interrogatories. The inquiries relate to whether the electricity and natural gas trades by Avista Corp. and Avista Energy involved “round trip trades,” “wash trades,” or “sell/buyback trades” and proper “price reporting.” Avista Corp. and Avista Energy are cooperating with the CFTC and providing the information requested by the CFTC.

Class Action Securities Litigation

On September 27, 2002, Ronald R. Wambolt filed a class action lawsuit in the United States District Court for the Eastern District of Washington against Avista Corp., Thomas M. Matthews, the former Chairman of the Board, President and 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. On October 9, 2002, Gail West filed a similar class action lawsuit in the same court against the same parties. On November 7, 2002, Michael Atlas filed a similar class action lawsuit in the same court against the same parties. On November 21, 2002, Peter Arnone filed a similar class action lawsuit in the same court against the same parties. 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’s 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 common 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 intends to vigorously defend against this lawsuit.

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California Energy Markets

In April 2002, several subsidiaries of Reliant Energy, Inc. (Reliant) and Duke Energy Corporation (Duke) filed cross-complaints against Avista Energy and numerous other participants in the California energy markets. The cross-complaints seek indemnification for any liability which may arise from original complaints filed against Reliant and Duke with respect to charges of unlawful and unfair business practices in the California energy markets under California law. Avista Energy filed motions to dismiss the cross-complaints. In the meantime, the U.S. District Court remanded the case to California State Court, which remand is itself the subject of an appeal to the United States Court of Appeals for the Ninth Circuit.

In March 2002, the Attorney General of the State of California (California AG) filed a complaint with the FERC against certain specific companies (not including Avista Corp. or its subsidiaries) and “all other public utility sellers” in California. The complaint alleges that sellers with market-based rates have violated their tariffs by not filing with the FERC transaction-specific information about all of their sales and purchases at market-based rates. As a result, 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.

In April 2002, the California AG provided notice of intent to file a complaint against Avista Energy in the California State Court on behalf of the State of California. In the notice of intent to file a complaint, the California AG alleges that Avista Energy failed to file rates and changes to rates charged for each sale of wholesale electricity in California markets with the FERC as required by Federal Power Act regulations and FERC orders. The threatened complaint asserts that each violation of law, regulation and order is an unlawful and unfair business practice under the California Business and Professions Code, subject to a penalty of $2,500 per violation. The threatened complaint further alleges that certain rates charged for wholesale electricity sold in California exceeded a just and reasonable rate. As such, the threatened complaint alleges that these rates violate the Federal Power Act and are also a violation under the California Business and Professions Code, subject to penalty. A significant portion of the transactions involved in this threatened complaint are also the subject of FERC proceedings to examine potential refunds and in most cases are transactions for which Avista Energy is still owed payment. As of the filing date of this report, the California AG has not filed any such complaint against Avista Energy. Complaints have been filed by the California AG against approximately a dozen other companies, many of which have been dismissed based upon federal preemption and primary jurisdiction arguments. Those orders of dismissal have been appealed by the California AG to the United States Court of Appeals for the Ninth Circuit.

Port of Seattle Complaint

On May 21, 2003, the Port of Seattle filed 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 Sherman Act and the Racketeer Influenced and Corrupt Organization Act by transmitting, via wire communications, false information intended to increase the price of power, knowing that others would rely upon such information. 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 filed a motion to dismiss this complaint. A conditional transfer order has been granted, which if it becomes final, would move this case to the United States District Court for the Southern District of California to consolidate it with other pending actions.

State of Montana Complaint

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 Avista Corp. The complaint alleges that the companies illegally manipulated western electric and natural gas markets in 2000 and 2001. The Montana AG also petitioned the Montana Public Service Commission to fine public utilities $1,000 a day for each day it finds they engaged in alleged “deceptive, fraudulent, anticompetitive or abusive practices” and order refunds when consumers were forced to pay more than just and

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reasonable rates. This case was subsequently moved to the United States District Court for the District of Montana and is the subject of a conditional transfer order, which if it becomes final, would consolidate this case with other pending actions in the United States District Court for the Southern District of California. The Company intends to file a motion to dismiss this complaint.

State of Washington Business and Occupation Tax

The State of Washington’s Business and Occupation Tax applies to gross revenue from business activities. For most types of business, the tax applies to the gross sales price received for goods or services. For certain types of financial trading activities, including the sale of stocks, bonds and other securities, the tax applies to the realized gain from the sale of the financial asset. On an audit for the period from July 1, 1997 through June 30, 2000, the Department of Revenue (DOR) took the position that approximately 20 percent of the forward energy trades of Avista Energy should not be treated as securities trades, but rather as energy deliveries. As a result, the DOR applied tax against the gross sales price of the energy contracts at issue. Avista Energy subsequently received an assessment of $14.5 million for tax and interest related to the disputed issue. It is the position of Avista Energy that all of its forward contract trading activities are substantively the same and there is no proper basis for the distinction made by the DOR. An administrative appeal was filed with the DOR and a hearing was held on September 25, 2001. The DOR issued a Proposed Determination on December 4, 2002, which reiterated the original $14.5 million assessment. At the present time Avista Energy is still in active negotiations with the DOR with respect to a final resolution of this matter and believes that a satisfactory settlement can be reached. However, if a satisfactory settlement can not be reached, Avista Energy will have to record a charge and resolve the issue in court.

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 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 Colstrip in defense of this complaint.

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 Avista 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. The Company intends to defend itself against 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. On January 15, 1999, the Company received notice from the State of Washington’s Department of Ecology (DOE) that it had been designated as a potentially liable party (PLP) with respect to any hazardous substances located on this site, stemming from the Company’s past ownership of the former gas plant site. In its notice, the DOE stated that it intended to complete an on-going remedial investigation of this site, complete a feasibility study to determine the most 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.

An Agreed Order was signed by the DOE, the Company and another PLP, Burlington Northern & Santa Fe Railway Co. (BNSF) on March 13, 2000 that 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; performance of a focused feasibility study; and implementation of an interim groundwater monitoring plan. During the second quarter of 2000, the Company received comments from the DOE on its initial remedial

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investigation, then submitted another draft of the remedial investigation, which was accepted as final by the DOE. After responding to comments from the DOE, the feasibility study was accepted by the DOE during the fourth quarter of 2000. After receiving input from the Company and the other PLPs, the final Cleanup Action Plan (CAP) was issued by the DOE on August 10, 2001. On September 10, 2001, the DOE issued an initial draft Consent Decree for the PLPs to review. During the first quarter of 2002, the Company and BNSF signed a cost sharing agreement. On September 11, 2002, the Company, BNSF and the DOE finalized the Consent Decree to implement the CAP. The third PLP has indicated it will not sign the Consent Decree. It is currently estimated that the Company’s share of the costs will be less than $1.0 million. The Engineering and Design Report for the CAP was submitted to the DOE in January 2003 and approved by the DOE in May 2003. Work under the CAP commenced during the second quarter of 2003. Negotiations are continuing with the third PLP with respect to the logistics of the CAP.

Spokane River

In March 2001, the DOE informed Avista Development, a subsidiary of Avista Capital, of a health advisory concerning PCBs found in fish caught in a portion of the Spokane River. In June 2001, Avista Development received official notice that it had been designated as a PLP with respect to contaminated sites on the Spokane River. The DOE discovered PCBs in fish and sediments in the Spokane River in the 1970s and 1980s. In the 1990s, the DOE performed subsequent sampling of the river and identified potential sources of the PCBs, including the Spokane Industrial Park (SIP) and a number of other entities in the area. The SIP, renamed Pentzer Development Corporation (Pentzer Development) in 1990, operated a wastewater treatment plant at the site until it was closed in December 1993. The SIP’s treatment plant discharged to the Spokane River under the terms of a National Pollutant Discharge Elimination System permit issued by the DOE. Pentzer Development sold the property in 1996 and merged with Avista Development in 1998. Avista Development filed a response to this notice in August 2001. In December 2001, the DOE confirmed Avista Development’s status as a PLP and named at least two other PLPs in this matter. During the first half of 2002, Avista and one other PLP met with the DOE to begin discussions and provide comments to the DOE on a draft Consent Decree and Scope of Work for a focused remedial investigation and feasibility study of the site. One other PLP has not been participating in negotiations. The Consent Decree and Scope of Work for the remedial investigation and feasibility study of the site were finalized during the fourth quarter of 2002 and formally entered into Spokane County Superior Court in January 2003. As directed by Avista and the other PLP, the field work for the remedial investigation began in April 2003. The other PLP that has been participating with Avista Development has filed for bankruptcy; however, the bankruptcy court has permitted the disbursement of funds related to this remedial investigation and feasibility study. Disbursement of funds related to the actual cleanup of PCBs will need to settled and approved by the bankruptcy court. In April 2003, the DOE released its study of wastewater and sludge handling from facilities owned by a fourth PLP. The DOE study indicated that the fourth PLP continued to discharge PCBs into the Spokane River. The DOE issued the fourth PLP a final notice of participation as a PLP on April 30, 2003. As directed by Avista and the other PLP, sampling of groundwater and completion of transects for bottom profiling of the Spokane River behind Upriver Dam was completed during the second quarter of 2003 as part of the remedial investigation. The sampling of water and sediments for PCBs was completed during the third quarter of 2003. It is currently expected that the actual cleanup of PCB sediments in the Spokane River will be coordinated to the extent possible with the EPA’s separate plan to remove heavy metals from the Spokane River, contamination that resulted from decades of mining upstream at locations in Idaho and is not related to the activities of Avista Development.

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.

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Spokane River Relicensing

The Company operates six hydroelectric plants on the Spokane River, and five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls) are under one FERC license and referred to herein as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. The license for the Spokane River Project expires in August 2007; the Company filed a Notice of Intent to Relicense on July 29, 2002. The formal consultation process involving planning and information gathering with stakeholder groups is underway. The Company’s goal is to develop with the stakeholders a comprehensive and cost-effective settlement agreement to be filed as part of the Company’s license application to the FERC in July 2005.

Clark Fork Settlement Agreement

The issue of high levels of dissolved gas which exceed Idaho and federal water quality standards downstream of the Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) during spill periods continues to be studied, as agreed to in the Clark Fork Settlement Agreement and incorporated into the operating license renewed by the FERC in 1999. 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 during 2002 with the other signatories to the agreement. In December 2002, the Company submitted its plan for review and approval by the other signatories as well as the FERC. The structural alternative proposed in the plan provides for the modification of the two existing diversion tunnels built when Cabinet Gorge was originally constructed. The costs of modifications to the first tunnel are currently estimated to be $37 million (including AFUDC and inflation) and would be incurred between 2004 and 2009. The second tunnel would be modified only after evaluation of the performance of the first tunnel and such modifications would commence no later than 10 years following the completion of the first tunnel. It is currently estimated that the costs to modify the second tunnel would be $23 million (including AFUDC and inflation). As part of the plan, the Company will also provide $0.5 million annually commencing as 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 determine the best use of funds toward continuing fish passage efforts or other population enhancement measures.

Other Contingencies

In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes that any ultimate liability arising from these actions will not have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Safe Harbor for Forward-Looking Statements

This Report on Form 10-Q contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Avista Corp. is including the following cautionary statement to make applicable, and to take advantage of, the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, strategies, projections of future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions). Forward-looking statements are all statements other than statements of historical fact, including without limitation those that are identified by the use of words such as, but not limited to, “will,” “anticipates,” “seeks to,” “estimates,” “expects,” “intends,” “plans,” “predicts,” and similar expressions. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements.

Such statements are inherently subject to a variety of risks and uncertainties that could cause actual results to differ materially from those expressed. Certain of these risks and uncertainties are beyond the Company’s control. Such risks and uncertainties include, among others:

• changes in the utility regulatory environment in the individual states in which the Company operates and the United States in general. This can impact allowed rates of return, financings, or industry and rate structures;

• the impact of regulatory and legislative decisions including FERC price controls, and including possible retroactive price caps and resulting refunds;

• the potential effects of any energy-related legislation passed into law by the United States Congress;

• the impact from the potential formation of a Regional Transmission Organization and/or an Independent Transmission Company;

• the impact from the implementation of the FERC’s proposed wholesale power market rules;

• volatility and illiquidity in wholesale energy markets, including the availability and prices of purchased energy;

• wholesale and retail competition (including but not limited to electric retail wheeling and transmission costs);

• future streamflow conditions that affect the availability of hydroelectric resources;

• outages at any company-owned generating facilities;

• unanticipated delays or changes in construction costs with respect to present or prospective generating facilities;

• changes in weather conditions that can affect customer demand, result in natural disasters and/or customer outages;

• changes in industrial, commercial and residential growth and demographic patterns in the Company’s service territory;

• the loss of significant customers and/or suppliers;

• failure to deliver on the part of any parties from which the Company purchases and/or sells capacity or energy;

• changes in the creditworthiness of customers and energy trading counterparties;

• the Company’s ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including the Company’s credit ratings, interest rate fluctuations and other capital market conditions;

• changes in future economic conditions in the Company’s service territory and the United States in general, including inflation or deflation and monetary policy;

• the potential for future terrorist attacks, particularly with respect to utility plant assets;

• changes in tax rates and/or policies;

• changes in, and compliance with, environmental and endangered species laws, regulations, decisions and policies, including present and potential environmental remediation costs;

• the outcome of legal and regulatory proceedings concerning the Company or affecting directly or indirectly its operations;

• employee issues, including changes in collective bargaining unit agreements, strikes, work stoppages or the loss of key executives, as well as the ability to recruit and retain employees;

• changes in actuarial assumptions and the return on assets with respect to the Company’s pension plan, which can impact future funding obligations, costs and pension plan liabilities;

• increasing health care costs and the resulting effect on health insurance premiums paid for employees and on the obligation to provide postretirement health care benefits;

• increasing costs of insurance, changes in coverage terms and the ability to obtain insurance.

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The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. However, there can be no assurance that the Company’s expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. The Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the Company’s business or the extent to which any such factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.

The following discussion and analysis is provided for the consolidated financial condition and results of operations of Avista Corp., including its subsidiaries. This discussion focuses on significant factors concerning the Company’s financial condition and results of operations and should be read along with the consolidated financial statements.

Avista Corp. Lines of Business

Avista Corp. is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. The Company is organized into four lines of business – Avista Utilities, Energy Marketing and Resource Management, Avista Advantage, and Other. Avista Utilities, an operating division of Avista Corp. and not a separate entity, represents the regulated utility operations. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies engaged in the non-utility lines of business. As of September 30, 2003, the Company had common equity investments of $463.5 million and $265.8 million in Avista Utilities and Avista Capital, respectively.

Avista Utilities generates, transmits and distributes electricity and distributes natural gas. Avista Utilities owns and operates eight hydroelectric projects, a wood-waste fueled generating station, a two-unit natural gas-fired combustion turbine (CT) generating facility and two small generating facilities. It also owns a 15 percent share in a two-unit coal-fired generating facility and leases and operates a two-unit natural gas-fired CT generating facility. In July 2003, the combined cycle natural gas-fired Coyote Springs 2 Generation Project (Coyote Springs 2) was placed into operation. Avista Utilities has a 50 percent ownership interest (140 MW) in Coyote Springs 2. Avista Utilities’ facilities have a total net capability of approximately 1,651 megawatts (MW), of which 58 percent is hydroelectric and 42 percent is thermal. In addition to company owned resources, Avista Utilities has a number of long-term power purchase and exchange contracts that increase its available resources.

Avista 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. Avista 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 and including long-term contracts that extend beyond one year. Avista Utilities makes continuing projections of (1) future retail and wholesale loads based on, among other things, forward estimates of factors such as customer usage and weather as well as historical data and contract terms and (2) resource availability based on, among other things, estimates of streamflows, generating unit availability, historic and forward market information and experience. On the basis of these continuing projections, Avista Utilities 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 Avista Utilities’ own resources, as well as other wholesale transactions to capture the value of available generation and transmission resources. This optimization process includes hedging transactions as a means of managing risks.

The Energy Marketing and Resource Management line of business is comprised of Avista Energy, Inc. (Avista Energy) and Avista Power, LLC (Avista Power). Avista Energy is an electricity and natural gas marketing and resource management business, operating primarily in the Western Electricity Coordinating Council (WECC) geographical area, which is comprised of eleven Western states as well as the provinces of British Columbia and Alberta, Canada. Avista Power was formed to develop and own generation assets. Avista Power continues to manage the generation assets it currently owns, primarily its 49 percent interest in a 270 megawatt (MW) natural gas-fired combustion turbine plant in northern Idaho (Lancaster Project), which commenced commercial operation in September 2001.

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Avista Advantage, Inc. (Avista Advantage) is a provider of internet based facility intelligence, cost management, billing and information services to multi-site retail customers throughout North America. Its primary product lines include consolidated billing, resource accounting, energy analysis and load profiling services.

The Other line of business includes Avista Ventures, Inc. (Avista Ventures), Pentzer Corporation (Pentzer), Avista Development, Avista Services and the operations of Avista Capital that are not included through its subsidiaries. Included in this line of business is Advanced Manufacturing and Development, a subsidiary of Avista Ventures that performs custom manufacturing of sheet metal of electronic enclosures, parts and systems for the computer, telecom and medical industries. Advanced Manufacturing and Development also has a wood products division that provides complete fabrication and turnkey assembly for arcade games, kiosks, store fixtures, and displays. The Company continues to limit its future investment in the Other line of business.

In July 2003, Avista Corp. announced an investment of $6.0 million by a group of private equity investors in a new entity, AVLB, Inc., which acquired the assets previously held by Avista Corp.’s fuel cell manufacturing and development subsidiary, Avista Labs. As such, these operations are reported as a discontinued operation. In September 2003, AVLB, Inc. (doing business under the name Avista Labs) received an additional investment by private equity investors of $6.2 million. This investment relieved Avista Corp. of its commitment to provide additional funding of up to $1.5 million to AVLB, Inc. Avista Corp. has an ownership interest of approximately 17.5 percent in AVLB, Inc., with the opportunity but no further obligation to fund or invest in this business.

In September 2001, Avista Corp. decided that it would dispose of substantially all of the assets of Avista Communications, Inc. (Avista Communications), formerly part of the Information and Technology line of business with Avista Advantage and Avista Labs. The divestiture of operating assets was complete by the end of 2002. The operations of Avista Communications are included as part of discontinued operations during the three and nine months ended September 30, 2002.

Avista Utilities – Regulatory Matters

General Rate Cases

The Company regularly reviews the need for electric or natural gas rate changes in each state in which it provides service. Currently, the Company is planning to file electric and natural gas general rate cases in Idaho during the first quarter of 2004.

In April 2003, Avista Utilities filed revised tariff schedules to effect a general rate increase for Oregon retail customers of approximately $7.5 million. In September 2003, the OPUC approved an annual revenue increase of $6.3 million effective October 1, 2003, which provides for, among other things, an overall rate of return of 8.88 percent and a return on equity of 10.25 percent.

Purchased Gas Adjustments

Natural gas commodity prices increased towards the end of 2002 and into the first half of 2003 before declining somewhat during the third quarter of 2003. The Company is well connected to multiple supply basins in the western United States and western Canada and believes there will be sufficient supplies of natural gas to meet its customers’ needs. However, natural gas prices in the Pacific Northwest are increasingly affected by supply and demand factors in other parts of the United States and Canada. Natural gas commodity costs in excess of the amount recovered in current rates are deferred and recovered in future periods with applicable regulatory approval through adjustments to rates. Market prices for natural gas continue to be competitive compared to alternative fuel sources for residential, commercial and industrial customers. Avista Utilities believes that natural gas should sustain its market advantage based on the levels of existing reserves and potential natural gas development in the future.

During the second half of 2002, Avista Utilities adjusted its natural gas rates in response to a decrease in current and projected natural gas costs at that time. During the fourth quarter of 2002, natural gas rate decreases of 17.4 percent, 15.5 percent, 7.1 percent and 16.2 percent were approved and implemented in Washington, Idaho, Oregon and California, respectively. As discussed above, current and projected natural gas prices increased towards the end of 2002 and into the first half of 2003. During September and October of 2003, natural gas rate increases of 8.7 percent, 2.4 percent, 12.4 percent and 15.0 percent were approved and implemented in Washington, Idaho, Oregon and California, respectively. The rate increase in Washington was approved subject to refund, pending further review of the deferred natural gas costs. These natural gas rate increases and decreases are designed to pass through changes in purchased natural gas costs to customers and reduce operating revenues and resource costs with no change in Avista Utilities’ gross margin or net income. Total deferred natural gas costs were $17.6 million and $11.5 million as of September 30, 2003 and December 31, 2002, respectively.

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Natural Gas Benchmark Mechanism

The IPUC, WUTC and OPUC approved Avista Utilities’ Natural Gas Benchmark Mechanism in 1999. The mechanism eliminated the majority of natural gas procurement operations within Avista Utilities and consolidated natural gas procurement operations under Avista Energy, the Company’s non-regulated subsidiary. The ownership of the natural gas assets remains with Avista Utilities; however, the assets are managed by Avista Energy through an Agency Agreement. The Natural Gas Benchmark Mechanism provides benefits to retail customers and allows Avista Energy to retain a portion of the benefits associated with asset optimization and the efficiencies gained in purchasing natural gas for Avista Utilities as part of Avista Energy’s larger portfolio of natural gas assets. In the first quarter of 2002, the IPUC and the OPUC approved the continuation of the Natural Gas Benchmark Mechanism and related Agency Agreement through March 31, 2005. In January 2003, the WUTC approved the continuation of the Natural Gas Benchmark Mechanism and related Agency Agreement through January 29, 2004. In April 2003, the Company filed a request with the WUTC to amend certain aspects of the Natural Gas Benchmark Mechanism and related Agency Agreement and requested an extension through March 31, 2007. In July 2003, the WUTC staff and the Public Counsel Section of the Attorney General’s Office filed testimony recommending termination of the Natural Gas Benchmark Mechanism in Washington at the end of January 2004. The termination of the mechanism would likely result in natural gas procurement operations being performed by Avista Utilities for Washington natural gas customers. The WUTC staff and Public Counsel have recommended that if the WUTC determines that the mechanism should not be terminated, the level of benefits provided to Avista Utilities customers be increased on a prospective basis. During August 2003, Avista Utilities filed its response to the WUTC staff and Public Counsel recommendations requesting the continuation of the Natural Gas Benchmark Mechanism and further explaining the benefits that customers receive by having natural gas procurement operations managed by Avista Energy as part of a larger natural gas portfolio. Hearings will be held before the WUTC during November 2003 to determine any changes and whether or not the Natural Gas Benchmark Mechanism and related Agency Agreement will be extended beyond January 29, 2004.

Significant Customer Contract

A power purchase and sales contract with Potlatch Corporation (Potlatch) expired on December 31, 2001. Potlatch’s Lewiston, Idaho facility has electric requirements of about 100 aMW. The facility also typically produces approximately 60 aMW of generation. Since January 2002, Potlatch had been using its generation to supply a portion of its own electric requirements, which resulted in a net electric requirement on Avista Utilities’ system of approximately 40 aMW. In December 2002, Potlatch filed a complaint with the IPUC requesting that Avista Utilities be required to purchase its generation at a rate equivalent to Avista Utilities’ avoided costs. During July 2003, Avista Utilities and Potlatch executed a ten-year power purchase and sales contact, under which Avista Utilities will purchase up to 62 aMW of Potlatch’s generation at a price slightly below the IPUC administratively determined avoided cost rate. Additionally, Avista Utilities may from time to time purchase generation above 62 aMW at a price that is somewhat below market prices, when market conditions are such that it is mutually beneficial to Potlatch and Avista Utilities. Avista Utilities will serve Potlatch’s entire electric requirements of approximately 100 aMW at the retail tariff rates established for large industrial customers, unless a different rate is ordered by the IPUC. The agreement is subject to the approval of the IPUC, including the full recovery of the costs associated with the agreement through the Idaho PCA mechanism or base retail rates. If approved by the IPUC, Avista Utilities does not expect the agreement to have a material impact on future net income. However, it would result in an increase in both retail revenues and resource costs.

Integrated Resource Plan

In May 2003, Avista Utilities submitted its 2003 Integrated Resource Plan (IRP) to the WUTC and the IPUC. The IRP describes the mix of generating resources including, but not limited to, an investment in wind power starting in 2008, as well as energy efficiency programs to meet future electric power needs at least cost. The IRP is developed every two years with a 20-year view to the future.

Power Cost Deferrals and Recovery Mechanisms

Avista Utilities defers the recognition in the income statement of certain power supply costs that are in excess of the level currently recovered from retail customers as authorized by the WUTC and the IPUC. A portion of power supply costs are recorded as a deferred charge on the balance sheet for future review and the opportunity for recovery through retail rates. The specific power costs deferred are a percentage of the difference between certain actual power supply costs incurred by Avista Utilities and the costs included in base retail rates. This difference is primarily related to changes in short-term wholesale market prices, changes in the level of hydroelectric generation and changes in the level of thermal generation (including changes in fuel prices).

In June 2002, the WUTC issued an order that became effective July 1, 2002 with respect to a general electric rate

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case filed by Avista Utilities in December 2001. The order provided for the restructuring of rate increases previously approved by the WUTC totaling 31.2 percent. The general increase to base retail rates was 19.3 percent and the remaining 11.9 percent represents the continued recovery of deferred power costs.

In the June 2002 rate order, the WUTC approved the establishment of the ERM. The ERM replaced a series of temporary power cost deferral mechanisms that were in place in Washington since mid-2000. The ERM allows Avista 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 first $9.0 million in annual power supply costs above or below the amount included in base retail rates. Under the ERM, 90 percent of the power supply costs exceeding or below the initial $9.0 million are deferred for future surcharge or rebate to Avista Utilities’ customers. The remaining 10 percent of power supply costs are an expense of, or benefit to, the Company.

The Company expensed the initial $9.0 million of power supply costs above the amount included in base retail rates during the first quarter of 2003. The majority of these costs relate to fuel contracts entered into during 2001 that expire in 2004 for the Company’s thermal generating units.

Under the ERM, Avista Utilities agreed to make an annual filing on or before April 1st of each year 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. The settlement agreement establishing the ERM provided for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by WUTC order. Avista Utilities made its first annual filing with the WUTC on March 28, 2003 related to $18.4 million of deferred power costs incurred for the period July 1, 2002 through December 31, 2002. Previous settlement agreements established the prudence and recoverability of power costs incurred through June 30, 2002. On May 8, 2003 the WUTC staff, the Industrial Customers of Northwest Utilities, and the Public Counsel Section of the Attorney General’s Office filed a motion requesting a pre-hearing conference related to Avista Utilities’ March 28, 2003 ERM filing. As a result of that motion, a pre-hearing conference was held in May 2003 and an order was issued by the WUTC establishing a hearing schedule. The WUTC staff, the ICNU and Public Counsel filed testimony in August 2003 and Avista Utilities filed its response to this testimony in September 2003. The WUTC staff and the ICNU have taken the position that costs ranging from $2.0 million to $2.6 million associated with the delay of the Coyote Springs 2 project should be disallowed and removed from the deferred power cost balance. Public Counsel has taken the position that $14.0 million of losses on the sale of natural gas purchased for electric generation should be disallowed and removed from the deferred power cost balance. The Company believes that such costs were prudently incurred and in the best interest of its electric customers. The originally scheduled October 2003 evidentiary hearing has been delayed until December 2003 at the request of Public Counsel.

Avista Utilities has a PCA mechanism in Idaho that allows it to modify electric rates periodically with IPUC approval to recover or rebate a portion of the difference between actual net power supply costs and the amount included in base retail rates. The PCA mechanism allows for the deferral of 90 percent of the difference between certain actual net power supply expenses and the authorized level of net power supply expense approved in the last Idaho general rate case. The IPUC originally approved a 19.4 percent surcharge in October 2001, which had been extended through October 2003. In October 2003, the IPUC issued another order extending the surcharge for an additional 60-day period while it continues to consider extending the surcharge for an additional 12 months. The IPUC staff filed comments recommending the continuation of the 19.4 percent PCA surcharge; however, they recommend the disallowance of approximately $5.9 million of deferred power costs. The recommended disallowance relates to natural gas purchased for electric generation under long-term contracts entered into during 2001 at a time of both high wholesale power and natural gas prices. The Company believes that such costs were prudently incurred and in the best interest of its electric customers and has requested that these costs be addressed in a general electric rate case that the Company plans to file in the first quarter of 2004. The IPUC staff comments also recommend that the Company work with the IPUC staff and customers with respect to its risk policies.

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The following table shows activity in deferred power costs for Washington and Idaho during 2002 and the nine months ended September 30, 2003 (dollars in thousands):

		Washington			Idaho			Total
Deferred power costs as of December 31, 2001		$	140,238		$	73,087		$	213,325
Activity from January 1 – December 31, 2002:
	Power costs deferred		22,423			13,471			35,894
	Unrealized gain on fuel contracts (1)		(7,068	)		(3,485	)		(10,553	)
	Interest and other net additions		6,726			888			7,614
	Amortization of deferred credit		—			(27,711	)		(27,711	)
	Recovery of deferred power costs through retail rates		(38,570	)		(24,732	)		(63,302	)
Deferred power costs as of December 31, 2002			123,749			31,518			155,267
Activity from January 1 – September 30, 2003:
	Power costs deferred		16,992			17,425			34,417
	Unrealized loss on fuel contracts (1)		1,053			535			1,588
	Interest and other net additions		5,216			839			6,055
	Recovery of deferred power costs through retail rates		(19,183	)		(19,411	)		(38,594	)
Deferred power costs as of September 30, 2003		$	127,827		$	30,906		$	158,733

(1) Unrealized gains and losses on fuel contracts are not included in the ERM and PCA mechanism until the contracts are settled or realized.

During a year having normal streamflow conditions, Avista Utilities would expect to have generation from its hydroelectric resources (both owned and purchased under long-term hydroelectric contracts) of approximately 550 aMW. For 2002, streamflow conditions were 112 percent of normal and hydroelectric generation was 553 aMW (101 percent of normal). Current forecasts indicate that streamflow conditions for 2003 are expected to be approximately 85 percent of normal. Avista Utilities currently estimates that hydroelectric generation will be 500 aMW (90 percent of normal) in 2003. Based on current projections, total deferred power costs are expected to be approximately $158 million at the end of 2003. It is expected that the recovery of deferred power costs will take several years.

Power Market Issues

Avista Utilities and Avista Energy participate directly and indirectly in the power markets in the United States. Developments in these markets, particularly in the western part of the United States, have affected both Avista Utilities and Avista Energy. Federal and state officials including, but not limited to, the FERC and the CPUC, commenced reviews in 2000 to determine the causes of the changes in the wholesale energy markets to develop legal and regulatory remedies to address alleged market failures or abuses and large defaults by certain parties in the wholesale markets. The proceedings are continuing and their ultimate outcome and the resulting impact on the Company cannot be predicted at this time.

California Energy Market

In early 2001, California’s two largest utilities, Southern California Edison (SCE) and Pacific Gas & Electric Company (PG&E), defaulted on payment obligations owed to various energy sellers, including the California Power Exchange (CalPX), California Independent System Operator (CalISO), and Automated Power Exchange (APX). Consequently, CalPX, CalISO and APX defaulted on their payment obligations to others including Avista Energy. PG&E and CalPX filed voluntary petitions under chapter 11 of the bankruptcy code for protection from creditors. On March 1, 2002, SCE paid its past due obligations to the CalPX and various other creditors; however, these funds did not flow directly to Avista Energy or others. As of September 30, 2003, Avista Energy’s accounts receivable outstanding related to defaulting parties in California did not exceed its reserves for uncollected amounts, cost of collection, and refunds. Avista Energy is currently pursuing recovery of the defaulted obligations.

In July 2001, the FERC issued an order to commence a fact-finding hearing to determine if refunds should be owed and, if so, the amounts of such refunds for sales during the period from October 2, 2000 to June 20, 2001 in the California spot market. The order provides that any refunds owed could be offset against unpaid energy debts due to the same party. However, in 2002 the FERC announced that it was considering changing the method used to determine natural gas costs for calculating refunds in this proceeding, which would delay their findings. Furthermore, on November 20, 2002, the FERC issued a Discovery Order, which reopened the evidentiary record and allowed parties in the proceeding to conduct additional discovery for the period January 1, 2000 to June 20, 2001. The November 20, 2002 Discovery Order required that, by no later than March 3, 2003, the market

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participants provide relevant documents to support any proposed recommendations to the FERC. The Discovery Order also afforded parties in this proceeding the opportunity to respond by March 20, 2003 to submissions made by March 3, 2003. On December 12, 2002, the FERC administrative law judge issued a Certification of Proposed Findings on California Refund Liability detailing the proposed refund amounts, which was presented to the FERC for consideration.

Several parties filed documents with the FERC on March 3, 2003 presenting supplemental information regarding alleged improper market conduct and requests for refunds and other relief under the additional discovery procedures set forth in both the California and Pacific Northwest refund proceedings. The filing parties include the California Parties (a joint filing including the Attorney General of the State of California, the California Electricity Oversight Board, the CPUC, and PG&E), the City of Tacoma and Port of Seattle (jointly), the City of Seattle, and the Washington State Attorney General. The filing parties, with the exception of the Washington State Attorney General, have made specific allegations with regard to many companies, including Avista Corp. and Avista Energy. Based upon review of the filings, there were no new allegations or information not known to and addressed by the FERC trial staff in a separate investigation of Avista Corp. and Avista Energy. Avista Corp. and Avista Energy filed reply comments in response to the allegations of the parties in March 2003.

On March 26, 2003, the FERC policy staff issued its final 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, Avista Corp. and Avista Energy were among the few that had already been subjects of a FERC investigation. As explained at “Federal Energy Regulatory Commission Inquiry” in “Note 12 of the Notes to Consolidated Financial Statements” regarding the investigation of Avista Corp. and Avista Energy, 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. On July 24, 2003, the FERC’s administrative law judge certified the agreement in resolution with respect to the FERC’s investigation of Avista Corp. and Avista Energy and forwarded it to the FERC commissioners for final approval. See further discussion of this FERC investigation of Avista Corp. and Avista Energy at “Federal Energy Regulatory Commission Inquiry” in “Note 12 of the Notes to Consolidated Financial Statements.”

On March 26, 2003, the FERC also addressed issues related to refund proceedings in the California energy markets. Based on current information, the Company believes that it has sufficient reserves in place for potential California refunds.

On June 25, 2003, the FERC issued two broad show cause orders to over 60 power trading companies (Avista Corp. and Avista Energy were not included) that are alleged to have engaged in manipulative practices that disrupted western energy markets in 2000 and 2001. On June 25, 2003, the FERC also announced that it had not found evidence that would support the modification of certain long-term power contracts in western energy markets, saying that it would not be in the public interest and that buyers had failed to make a case for such action.

On June 25, 2003, the FERC issued an order with respect to the bidding behavior and practices engaged in by participants in the short-term energy markets operated by the CalISO and the CalPX. This order calls for the review of bids above $250 per MW made by participants during the period from May 1, 2000 to October 2, 2000. This order was made in response to the March 26, 2003 FERC policy staff report on western energy markets, which indicated that certain bids for this period appeared to have been excessive. Market participants with bids above $250 per MW during the period described above will be required to demonstrate why their bidding behavior and practices did not violate applicable market rules. If violations were found to exist, the FERC would require the refund of any unjust profits and could also enforce other non-monetary penalties, such as the revocation of market- based rate authority. Avista Energy is subject to this review. Avista Energy maintains that it has engaged in sound business practices in accordance with established market rules.

Pacific Northwest Refund Proceedings

The July 2001 FERC order also directed an evidentiary proceeding to explore wholesale power market issues in the Pacific Northwest to determine whether there were excessive charges for spot market sales in the Pacific Northwest during the period from December 25, 2000 to June 20, 2001. Based on their application of selected retroactive pricing methods, certain parties asserted claims for significant refunds from Avista Energy and lesser refunds from Avista Utilities. Avista Energy and Avista Utilities joined with numerous other wholesale market participants to

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oppose proposals by parties for refund claims. In September 2001, the FERC’s administrative law judge for this proceeding issued a recommendation that the FERC should not order refunds for the Pacific Northwest for the period in question and that the FERC should take no further action on these matters. On December 19, 2002, the FERC issued a Discovery Order that reopened the evidentiary record and allowed parties in the proceeding to conduct additional discovery for the period January 1, 2000 to June 20, 2001. The December 19, 2002 Discovery Order required that, by no later than March 3, 2003, the market participants provide relevant documents to support any proposed recommendations to the FERC. The Discovery Order also afforded parties in this proceeding the opportunity to respond by March 20, 2003 to submissions made by March 3, 2003.

On March 26, 2003 the FERC policy staff issued a report recommending that the FERC reconsider the refund proceedings in the Pacific Northwest energy markets. On May 6, 2003, the Transaction Finality Group (comprised primarily of western utility and energy companies, including Avista Corp. and Avista Energy) requested oral arguments before the FERC in the Pacific Northwest refund proceedings. In its request to the FERC, the Transaction Finality Group stated, among other things, that any action that the FERC takes regarding the electricity market prices in the Pacific Northwest during 2000 and 2001 will retroactively disturb thousands of completed and long-settled bilateral contracts. On June 25, 2003, the FERC denied the request of certain parties for retroactive refunds for spot market sales in the Pacific Northwest during the period from December 25, 2000 to June 20, 2001. On July 25, 2003, the Transaction Finality Group filed a request for rehearing supporting the FERC’s decision to deny retroactive refund claims in the Pacific Northwest spot market but raising argument on certain procedural issues only in the event that the FERC entertains additional arguments in the case. Also on July 25, 2003, several other parties filed requests for rehearing on the FERC’s order. The request for rehearing was granted by the FERC in August 2003. The Company cannot predict when a final decision in the Pacific Northwest refund proceeding will be issued by the FERC. Until more information is available regarding possible refunds to be paid or received by Avista Corp., Avista Energy and other participants in the Pacific Northwest energy markets, the Company will not be in a position to estimate the net effects on the Company or the materiality of such net effects. The Company continues to oppose any proposals for refund claims as inappropriate. If the FERC orders market participants to pay refunds, those participants, including Avista Corp. and Avista Energy, would seek refunds from other participants which sold power to them. It is possible that certain municipal and other participants that are not generally subject to FERC jurisdiction could assert that, while they are entitled to receive refunds, they are not obligated under a FERC order to pay refunds. If the Company could not recover its refund claims against any such participants in the FERC proceedings, it may seek to do so in a court of law.

See further information under “Federal Energy Regulatory Commission Inquiry,” “U.S. Commodity Futures Trading Commission (CFTC) Subpoena,” “California Energy Markets,” “Port of Seattle Complaint,” and “State of Montana Complaint” in “Note 12 of the Notes to Consolidated Financial Statements.”

Regional Transmission Organizations

Avista Corp. is negotiating with nine other utilities in the western United States in the possible formation of a Regional Transmission Organization (RTO), RTO West, a non-profit organization. The potential formation of RTO West is in response to FERC Order No. 2000 requiring all utilities subject to FERC regulation to file a proposal to form a RTO, or a description of efforts to participate in a RTO, and any existing obstacles to RTO participation. FERC Order No. 2000 is a follow-up to FERC Orders No. 888 and 889 issued in 1996, which required transmission owners to provide non-discriminatory transmission service to third parties. RTO West filed its Stage 2 proposal with the FERC in March 2002 and received limited approval from the FERC of this initial plan in September 2002. With further development of detail and some modifications, the FERC stated that the proposal will satisfy not only FERC Order No. 2000 requirements, but can also provide a basic framework for standard market design in the western United States. Further development of the RTO West proposal by the filing utilities continues. Under the current proposal, RTO West would have its own independent governing board. The participating transmission owners would retain ownership of the transmission assets, but would not have a role in operating the transmission grid.

Avista Corp. and two other western utilities have also taken steps toward the formation of a for-profit Independent Transmission Company, TransConnect, which would be a member of RTO West, serve portions of five states and own or lease the high voltage transmission facilities of the participating utilities. TransConnect filed its proposal with the FERC in November 2001 and received limited approval from the FERC in September 2002.

The final proposals must be approved by the FERC, the boards of directors of the filing companies and regulators in various states. The companies’ decision to move forward with the formation of TransConnect or RTO West will ultimately depend on the conditions related to the formation of the entities, as well as the economics and conditions established in the regulatory approval process. If TransConnect were formed, it could result in Avista Utilities divesting its electric transmission assets. The formation of RTO West or TransConnect could have an impact on the

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Company’s transmission costs and profitability.

In September 2003, Western Interconnection L.L.C. (WI) filed an application with the FERC to issue a note in support of a $100.0 million construction loan as part of seeking certification as a RTO. As proposed, WI would provide transmission service in the western United States. As part of its application, WI has requested that the FERC order each jurisdictional utility in the western United States (including Avista Corp.) to provide escrow funding to WI in the amount of $4.0 million per year. Several parties (including Avista Corp.) have filed motions with the FERC requesting that the FERC deny the WI application.

Wholesale Power Market Design

In April 2003, the FERC issued a White Paper presenting a revised version of proposed wholesale power market rules. The White Paper emphasizes a focus on the formation of RTOs and on ensuring that all independent transmission organizations have sound market rules. The White Paper further indicates that the implementation schedule will vary depending on regional needs and will also allow for regional differences. This White Paper was developed based on input from numerous state regulatory agencies, utility companies, industry and consumer groups, as well as the public. The White Paper reflects significant concerns raised with respect to the FERC’s initial proposal of a Standard Market Design in July 2002. The FERC’s stated goals with respect to wholesale power markets include: reliable and reasonably priced electric service for all customers; sufficient electric infrastructure; transparent markets with fair rules for all market participants; stability and regulatory certainty for customers, the electric power industry, and investors; technological innovation; and efficient use of the nation’s resources. The White Paper proposes a significant role being played by regional authorities in setting up regional power markets. As the proposed market rules develop, the Company continues to assess the impact the changes would have on its operations as well as how the changes would impact the RTO West, TransConnect and WI proposals.

Results of Operations

Diluted earnings (loss) per common share by business segments

The following table presents diluted earnings (loss) per common share by business segments for the three and nine months ended September 30:

		Three months ended						Nine months ended
		September 30,						September 30,
		2003			2002			2003			2002
Avista Utilities		$	0.02		$	(0.02	)	$	0.39		$	0.48
Energy Marketing and Resource Management			0.10			0.05			0.44			0.41
Avista Advantage			(0.01	)		(0.02	)		(0.03	)		(0.07	)
Other			(0.02	)		(0.01	)		(0.09	)		(0.22	)
	Earnings per common share from continuing operations		0.09			0.00			0.71			0.60
Loss per common share from discontinued operations			—			(0.05	)		(0.10	)		(0.13	)
	Earnings (loss) per common share before cumulative effect of accounting change		0.09			(0.05	)		0.61			0.47
Loss per common share from cumulative effect of accounting change			—			—			(0.03	)		(0.09	)
	Total earnings (loss) per common share, diluted	$	0.09		$	(0.05	)	$	0.58		$	0.38

Overall Operations

Three months ended September 30, 2003 compared to the three months ended September 30, 2002

Income from continuing operations was $4.4 million for the three months ended September 30, 2003 compared to $0.9 million for the three months ended September 30, 2002. The increase was primarily due to an increase in net income recorded by Avista Utilities and Energy Marketing and Resource Management and a decrease in the net loss recorded by Avista Advantage, partially offset by an increased net loss for the Other business segment.

Net income for Energy Marketing and Resource Management was $4.8 million for the three months ended September 30, 2003 compared to $2.7 million for the three months ended September 30, 2002. The primary reason for the increase in net income was an increase in gross margin (operating revenues less resource costs). During September 2003, Avista Energy implemented hedge accounting for certain transactions. This should partially mitigate the effects from the transition to SFAS No. 133 and reduce the volatility of reporting earnings on a prospective basis.

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Net income for Avista Utilities was $0.9 million for the three months ended September 30, 2003, compared to a net loss of $0.5 million for the three months ended September 30, 2002. The increase for Avista Utilities was primarily due to an increase in gross margin and a decrease in interest expense, partially offset by an increase in other operating expenses.

Avista Advantage incurred a net loss of $0.3 million for the three months ended September 30, 2003 compared to $0.9 million for the three months ended September 30, 2002. The decrease in the net loss was primarily due to an increase in operating revenues and a decrease in operating expenses.

The Other line of business incurred a net loss of $1.1 million for the three months ended September 30, 2003 compared to $0.5 million for the three months ended September 30, 2002. The increase in the net loss was due to a decrease in interest income as well as an increase in the net loss for Advanced Manufacturing and Development.

Total revenues increased $24.4 million for the three months ended September 30, 2003 compared to the three months ended September 30, 2002. Avista Utilities’ revenues increased $19.5 million, or 11 percent, primarily due to increased electric revenues, partially offset by decreased natural gas revenues. The increase in electric revenues reflects an increase in retail, wholesale and other revenues. The decrease in natural gas revenues was primarily due to natural gas rate decreases implemented during the fourth quarter of 2002. Revenues from Energy Marketing and Resource Management increased $18.7 million, or 71 percent, due to an increase in net trading revenue and increased revenues on contracts, which are not considered derivatives under SFAS No. 133 (primarily the Agency Agreement with Avista Utilities). Revenues from Avista Advantage increased 13 percent to $5.0 million primarily as a result of customer growth. Revenues from the Other line of business decreased $1.0 million primarily due to decreased revenues from Advanced Manufacturing and Development. Intersegment eliminations increased to $19.6 million for the three months ended September 30, 2003 from $6.3 million for the three months ended September 30, 2002 representing increased sales of natural gas under the Agency Agreement between Avista Utilities and Avista Energy.

Total resource costs increased $17.1 million for the three months ended September 30, 2003 compared to the three months ended September 30, 2002. Resource costs for Avista Utilities increased $14.7 million primarily due to an increase in the expense for power purchased and fuel for generation, partially offset by net power and natural gas cost deferrals compared to net amortization of previous deferrals in the prior period. The increase in power purchased expense was primarily due to an increase in the price of power, partially offset by a decrease in the volume of wholesale power purchases. The net deferral of power and natural gas costs was $10.6 million for the three months ended September 30, 2003, compared to net amortization of $3.1 million for the three months ended September 30, 2002. During the three months ended September 30, 2002, the initial $4.5 million in power costs above the amount included in base retail rates in Washington was expensed, which increased resource costs for that period. Resource costs for Energy Marketing and Resource Management increased $15.6 million due to an increase in costs from contracts that are not accounted for as derivatives under SFAS No. 133 (primarily the Agency Agreement with Avista Utilities). Intersegment eliminations increased to $19.6 million for the three months ended September 30, 2003 from $6.3 million for the three months ended September 30, 2002 representing increased purchases of natural gas under the Agency Agreement between Avista Utilities and Avista Energy.

Operations and maintenance expenses decreased $0.1 million for the three months ended September 30, 2003 compared to the three months ended September 30, 2002 primarily due to decreased expenses for Avista Advantage and the Other business segment, partially offset by increased expenses for Avista Utilities. Avista Advantage continues to be focused on reducing operating expenses by improving efficiencies.

Administrative and general expenses increased $0.7 million for the three months ended September 30, 2003 compared to the three months ended September 30, 2002 primarily due to increased expenses for Avista Utilities and Energy Marketing and Resource Management, partially offset by decreased expenses for the Other business segment. The increase for Avista Utilities reflects increased employee expenses, including pension costs. The increase for Energy Marketing and Resource Management was primarily a result of increased compensation expenses resulting from increased earnings, partially offset by decreased professional fees. Administrative and general expenses for the Other business segment decreased primarily due to reduced litigation costs.

Depreciation and amortization increased $2.7 million for the three months ended September 30, 2003 compared to the three months ended September 30, 2002 primarily due to utility plant additions at Avista Utilities and the resulting increase in depreciation expense.

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Taxes other than income taxes decreased $0.6 million for the three months ended September 30, 2003 compared to the three months ended September 30, 2002 primarily due to increased taxes for Energy Marketing and Resource Management.

Interest expense decreased $1.9 million for the three months ended September 30, 2003 compared to the three months ended September 30, 2002 primarily due to a decrease in the average balance of debt outstanding. This increase was partially offset by the inclusion of $0.5 million of preferred stock dividends as interest expense for the three months ended September 30, 2003 in accordance with SFAS No. 150 (see Note 2 of the Notes to Consolidated Financial Statements). During 2002, the Company repurchased $203.6 million of long-term debt. The Company repurchased $52.5 million of long-term debt during the nine months ended September 30, 2003. The Company expects interest expense to continue to decline in 2003 due to the effect of debt repurchases in 2002 and the first nine months of 2003. In September 2003, the Company issued $45.0 million of 6.125 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 and is expected to result in an overall reduction in the Company’s interest expense.

Capitalized interest decreased $2.8 million for the three months ended September 30, 2003 compared to the three months ended September 30, 2002. This was primarily due to the fact that the Company did not capitalize any interest related to Coyote Springs 2 subsequent to September 30, 2002 because the project was substantially completed.

Other income-net decreased $0.8 million for the three months ended September 30, 2003 compared to three months ended September 30, 2002 primarily due to reduced interest income.

Nine months ended September 30, 2003 compared to the nine months ended September 30, 2002

Income from continuing operations was $35.5 million for the nine months ended September 30, 2003 compared to $30.1 million for the nine months ended September 30, 2002. The increase was primarily due to increased net income recorded by Energy Marketing and Resource Management and a decrease in the net losses recorded by Avista Advantage and the Other business segment, partially offset by decreased net income from Avista Utilities.

Net income for Energy Marketing and Resource Management was $21.1 million (excluding the cumulative effect of accounting change) for the nine months ended September 30, 2003 compared to $19.4 million for the nine months ended September 30, 2002. During the nine months ended September 30, 2003, Avista Energy’s earnings were positively impacted by the effects of accounting for energy contracts under SFAS No. 133 and a settlement with certain Enron Corporation affiliates. Avista Energy’s transition to SFAS No. 133 resulted in contracts, which are not considered derivatives, no longer being accounted for at market value. The transition to SFAS No. 133 increased the volatility of reported earnings due to the fact that certain contracts, which are not considered derivatives, economically hedged contracts that are accounted for as derivative instruments at market value under SFAS No. 133. During September 2003, Avista Energy implemented hedge accounting for certain transactions. This should partially mitigate the effects from the transition to SFAS No. 133 and reduce the volatility of reporting earnings on a prospective basis.

Net income for Avista Utilities was $19.9 million for the nine months ended September 30, 2003, compared to $24.8 million for the nine months ended September 30, 2002. The decrease for Avista Utilities was primarily due to an increase in other operating expenses, partially offset by an increase in gross margin and a decrease in interest expense.

Avista Advantage incurred a net loss of $1.2 million for the nine months ended September 30, 2003 compared to $3.6 million for the nine months ended September 30, 2002. The decrease in the net loss was primarily due to an increase in operating revenues and a decrease in operating expenses.

The Other line of business incurred a net loss of $4.3 million for the nine months ended September 30, 2003 compared to $10.5 million (excluding the cumulative effect of accounting change) for the nine months ended September 30, 2002. The decrease in the net loss was primarily due to a reduction in litigation costs and settlements.

Total revenues increased $8.4 million for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002. Avista Utilities’ revenues increased $9.2 million, or 1 percent, primarily due to increased electric revenues, partially offset by decreased natural gas revenues. The decrease in natural gas revenues was primarily due to natural gas rate decreases implemented during the fourth quarter of 2002 and partially due to

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AVISTA CORPORATION

decreased therms sold as a result of milder weather during the first quarter of 2003. The increase in electric revenues reflects an increase in retail, wholesale and other revenues. Revenues from Energy Marketing and Resource Management increased $46.0 million, or 36 percent, primarily due to increased revenues on contracts that are not considered derivatives under SFAS No. 133 (primarily the Agency Agreement with Avista Utilities), as well as the effect of the transition to SFAS No. 133. The transition to SFAS No. 133 resulted in certain contracts with net unrecognized losses of $8.2 million for the nine months ended September 30, 2003 not being accounted for at market value. These losses are recognized as transactions under the contracts are settled or realized. These contracts that were not accounted for at market value economically hedged certain other contracts with unrealized gains for the nine months ended September 30, 2003, that were considered derivatives under SFAS No. 133, and as such were recorded at market value. Avista Energy’s settlement of various positions with Enron Corporation affiliates and the resulting release by Avista Energy of amounts which had been reserved against such positions also had a positive impact of $8.3 million on operating revenues for the nine months ended September 30, 2003. Revenues from Avista Advantage increased 21 percent to $14.7 million primarily as a result of customer growth at Avista Advantage. Revenues from the Other line of business increased $0.3 million primarily due to increased revenues from Advanced Manufacturing and Development. Intersegment eliminations increased to $100.8 million for the nine months ended September 30, 2003 from $51.2 million for the nine months ended September 30, 2002 representing increased sales of natural gas under the Agency Agreement between Avista Utilities and Avista Energy.

Total resource costs decreased $5.3 million for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002. Resource costs for Avista Utilities increased $5.5 million primarily due to an increase in the expense for power purchased, fuel for generation and other fuel costs, partially offset by net power and natural gas cost deferrals compared to net amortization of previous deferrals in the prior period. The net deferral of power and natural gas costs was $1.3 million for the nine months ended September 30, 2003, compared to net amortization of $66.5 million for the nine months ended September 30, 2002. The increase in power purchased expense was primarily due to an increase in the price of power and partially due to an increase in the volume of wholesale power purchases. During the nine months ended September 30, 2003, the initial $9.0 million in power costs above the amount included in base retail rates in Washington was expensed as compared to $4.5 million expensed during the third quarter of 2002. Resource costs for Energy Marketing and Resource Management increased $38.9 million due to an increase in costs from contracts that are not accounted for as derivatives under SFAS No. 133 (primarily the Agency Agreement with Avista Utilities), partially offset by a change in natural gas inventory valuations. Intersegment eliminations increased to $100.8 million for the nine months ended September 30, 2003 from $51.2 million for the nine months ended September 30, 2002, representing increased purchases of natural gas under the Agency Agreement between Avista Utilities and Avista Energy.

Operations and maintenance expenses increased $4.8 million for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002 primarily due to increased expenses for Avista Utilities, partially offset by decreased expenses for Avista Advantage. The increase in operations and maintenance expenses for Avista Utilities was partially due to increased pension costs. The increase for Avista Utilities was also due to initiatives implemented during the third quarter of 2001 designed to temporarily reduce certain operating expenses to improve liquidity and operating cash flows. These initiatives resulted in significantly reduced expenses for 2001 and the first half of 2002. Cost reduction measures were not as restrictive during the last half of 2002 and 2003 as the second half of 2001 and the first half of 2002. Avista Advantage continues to be focused on reducing operating expenses by improving efficiencies.

Administrative and general expenses decreased $4.9 million for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002 primarily due to decreased expenses for the Other business segment, partially offset by increased expenses for Energy Marketing and Resource Management and Avista Utilities. Administrative and general expenses for the Other business segment decreased due to reduced litigation costs and settlements. The increase for Energy Marketing and Resource Management was primarily a result of increased compensation expenses. The increase for Avista Utilities was consistent with the increase in operations and maintenance expenses. Increased insurance costs also contributed to the increase in administrative and general expenses.

Depreciation and amortization increased $5.0 million for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002 primarily due to utility plant additions at Avista Utilities and the resulting increase in depreciation expense.

Taxes other than income taxes decreased $3.6 million for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002 primarily due to decreased retail natural gas revenues and related taxes for Avista Utilities.

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Interest expense decreased $10.8 million for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002 primarily due to a decrease in the average balance of debt outstanding. This increase was partially offset by the inclusion of $0.5 million of preferred stock dividends as interest expense for the nine months ended September 30, 2003 in accordance with SFAS No. 150 (see Note 2 of the Notes to Consolidated Financial Statements). During 2002, the Company repurchased $203.6 million of long-term debt. The Company repurchased $52.5 million of long-term debt during the nine months ended September 30, 2003. The Company expects interest expense to continue to decline in 2003 due to the effect of debt repurchases in 2002 and the first nine months of 2003. In September 2003, the Company issued $45.0 million of 6.125 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 and is expected to result in an overall reduction in the Company’s interest expense.

Capitalized interest decreased $6.9 million for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002. This was primarily due to the fact that the Company did not capitalize any interest related to Coyote Springs 2 subsequent to September 30, 2002 because the project was substantially completed.

Other income-net decreased $10.2 million for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002 primarily due to reduced interest income (including accrued interest on power and natural gas deferrals) as well as a decrease in the gains on the disposition of assets by Avista Capital subsidiaries. Increased losses on certain investments in the Other business segment also contributed to the decrease in other income-net.

Income taxes increased $0.7 million for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002, primarily due to increased earnings before income taxes. The effective tax rate was 43.3 percent for the nine months ended September 30, 2003 compared to 46.7 percent for the nine months ended September 30, 2002.

During the nine months ended September 30, 2003, Avista Energy recorded as a cumulative effect of accounting change a charge of $1.2 million (net of tax) related to the transition from EITF Issue No. 98-10 to SFAS No. 133.

In April 2002, the Company completed its transitional test of goodwill related to the adoption of SFAS No. 142 “Goodwill and Other Intangible Assets.” Accordingly, the Company determined that $6.4 million of goodwill related to Advanced Manufacturing and Development was impaired. The Company recorded this impairment of $4.1 million, net of tax, as a cumulative effect of accounting change for the nine months ended September 30, 2002.

Avista Utilities

Three months ended September 30, 2003 compared to the three months ended September 30, 2002

Net income for Avista Utilities was $0.9 million for the three months ended September 30, 2003 compared to a net loss of $0.5 million for the three months ended September 30, 2002. Avista Utilities’ income from operations was $22.5 million for the three months ended September 30, 2003 compared to $22.0 million for the three months ended September 30, 2002. This increase was primarily due to an increase in gross margin (operating revenues less resource costs), partially offset by an increase in other operating expenses. The increase in other operating expenses reflects increased pension and insurance costs.

The following table presents Avista Utilities’ gross margin for the three months ended September 30 (dollars in thousands):

	Electric				Natural Gas				Total
	2003		2002		2003		2002		2003		2002
Operating revenues	$	164,010	$	141,993	$	26,978	$	29,533	$	190,988	$	171,526
Resource costs		79,980		63,953		15,584		16,863		95,564		80,816
Gross margin	$	84,030	$	78,040	$	11,394	$	12,670	$	95,424	$	90,710

Avista Utilities’ operating revenues increased $19.5 million and resource costs increased $14.8 million resulting in an increase of $4.7 million in gross margin for the three months ended September 30, 2003 as compared to the three months ended September 30, 2002. The gross margin on electric sales increased $6.0 million and the gross margin on natural gas sales decreased $1.3 million.

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The increase in electric gross margin was primarily due to an increase in use per customer and the resulting increase in retail MWhs sold. Total retail MWhs sold increased 13 percent and residential use per customer increased 6 percent primarily due to weather. Also contributing to the increase in electric gross margin was the initial $4.5 million of excess power costs that Avista Utilities expensed under the ERM during the third quarter of 2002, which reduced electric gross margin for that period.

The following table presents Avista Utilities’ electric operating revenues and MWh sales for the three months ended September 30 (dollars and MWhs in thousands):

		Electric Operating				Electric Energy
		Revenues				MWh Sales
		2003		2002		2003		2002
Residential		$	44,028	$	40,399		712		663
Commercial			52,050		49,236		762		718
Industrial			23,099		17,997		545		404
Public street and highway lighting			1,186		1,174		6		6
	Total retail		120,363		108,806		2,025		1,791
Wholesale			18,673		17,329		330		637
Other			24,974		15,858		—		—
	Total	$	164,010	$	141,993		2,355		2,428

Retail electric revenues increased $11.6 million for the three months ended September 30, 2003 from the three months ended September 30, 2002. This increase was primarily due to increased use per customer and total MWhs sold. These increases reflect an increase in use per customer as well as an increase in the average number of customers. The increase in use per customer appears to reflect warmer weather during the three months ended September 30, 2003 as compared to the three months ended September 30, 2002 and the resulting impact on air conditioning usage.

Wholesale electric revenues increased $1.3 million, or 8 percent, reflecting average sales prices that were 108 percent higher than the prior period, partially offset by a 48 percent decrease in wholesale sales volumes. Average wholesale prices increased to $56.63 per MWh for the three months ended September 30, 2003 from $27.22 per MWh for the three months ended September 30, 2002. The increase in average wholesale sales prices appears to primarily reflect decreased hydroelectric resources as compared to the prior year throughout the western United States and an increase in the cost of natural gas used for generation. The extent of future wholesale transactions will be based on the projection of future needs, the availability of resources owned or under contract by Avista Utilities, wholesale market prices and changes to loads of Avista Utilities’ customers and contractual obligations.

Other electric revenues increased $9.1 million primarily due to the sale of natural gas purchased as fuel for electric generation that was not used in generation. This natural gas was not used for generation because electric wholesale market prices were generally below the cost of operating the gas-fired thermal generating units.

The following table presents Avista Utilities’ natural gas operating revenues and therm sales for the three months ended September 30 (dollars and therms in thousands):

		Natural Gas				Natural Gas
		Operating Revenues				Therm Sales
		2003		2002		2003		2002
Residential		$	13,855	$	15,232		13,966		13,452
Commercial			9,164		9,737		12,143		10,779
Industrial			1,500		1,239		2,967		1,783
	Total retail		24,519		26,208		29,076		26,014
Wholesale			—		344		—		1,445
Transportation			1,572		2,174		27,787		35,499
Other			887		807		1,649		687
	Total	$	26,978	$	29,533		58,512		63,645

Natural gas revenues decreased $2.6 million for the three months ended September 30, 2003 from the three months ended September 30, 2002 primarily due to a decrease in retail rates. During the fourth quarter of 2002, retail rates for natural gas were reduced in response to a decrease in current and projected natural gas costs. The decrease in rates was partially offset by an increase in total retail therms sold during the third quarter of 2003 as compared to the third quarter of 2002.

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The following table presents Avista Utilities’ average number of electric and natural gas customers as well as heating degree days for the three months ended September 30:

			Electric				Natural Gas
			Customers				Customers
			2003		2002		2003		2002
Residential				283,106		278,524		260,004		253,475
Commercial				36,299		35,965		31,190		30,670
Industrial				1,418		1,416		312		312
Public street and highway lighting				429		415		—		—
	Total retail			321,252		316,320		291,506		284,457
Wholesale				44		48		—		1
Transportation				—		—		82		90
	Total customers			321,296		316,368		291,588		284,548
Heating degree days:
	Spokane, Washington
		Actual						161		273
		30 year average						282		309
	Medford, Oregon
		Actual						36		66
		30 year average						139		112

The following table presents Avista Utilities’ resource costs for the three months ended September 30 (dollars in thousands):

			2003			2002
Electric resource costs:
	Power purchased		$	41,348		$	31,031
	Power cost amortizations (deferrals), net			(6,844	)		3,614
	Fuel for generation			17,040			4,761
	Other fuel costs			24,868			24,101
	Other regulatory amortizations, net			(1,560	)		(3,281	)
	Other electric resource costs			5,128			3,727
		Total electric resource costs		79,980			63,953
Natural gas resource costs:
	Natural gas purchased			19,310			17,280
	Natural gas cost deferrals, net of amortization			(3,780	)		(481	)
	Other regulatory amortizations, net			54			64
		Total natural gas resource costs		15,584			16,863
Total resource costs			$	95,564		$	80,816

Power purchased for the three months ended September 30, 2003 increased $10.3 million, or 33 percent, compared to the three months ended September 30, 2002 due to an increase in price of power purchases, partially offset by a decrease in the volume of wholesale power purchases. Average purchased power prices for the three months ended September 30, 2003 were $34.87 per MWh or 48 percent higher than $23.64 per MWh for the three months ended September 30, 2002 and volumes purchased decreased 10 percent compared to the three months ended September 30, 2002. The increase in the price of power purchases reflects increases in the price of power in the western United States and the Pacific Northwest. Warm and dry conditions in the Pacific Northwest as well as the increased cost of natural gas used to generate electricity during May through September of 2003 appear to have increased the price of electricity during the third quarter of 2003 as compared to the third quarter of 2002. Reduced hydroelectric availability and increased demand due to warmer weather also appear to have affected wholesale electric prices in the western United States and the Pacific Northwest.

The net deferral of power costs was $6.8 million for the three months ended September 30, 2003 compared to $3.6 million of net amortization for the three months ended September 30, 2002. During the three months ended September 30, 2003, Avista Utilities recovered (collected as revenue) $6.1 million of previously deferred power costs in Washington and $6.8 million in Idaho. During the three months ended September 30, 2003, Avista Utilities deferred $11.6 million of power costs in Washington and $8.2 million in Idaho. Total deferred power costs were $158.7 million as of September 30, 2003. See further description of issues related to deferred power costs in the section “Avista Utilities – Regulatory Matters.”

During the three months ended September 30, 2003, Avista Utilities had $3.8 million of net deferrals of natural gas

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AVISTA CORPORATION

costs compared to $0.5 million of net deferrals for the three months ended September 30, 2002. Total deferred natural gas costs were $17.6 million as of September 30, 2003.

The expense for natural gas purchased for the three months ended September 30, 2003 increased $2.0 million compared to the three months ended September 30, 2002 primarily due to the increase in total therms purchased consistent with an increase in retail natural gas sales.

Fuel for generation for the three months ended September 30, 2003 increased $12.3 million compared to the three months ended September 30, 2002. This was due to expenses associated with natural gas used as fuel for Coyote Springs 2, which was placed into operation on July 1, 2003.

Nine months ended September 30, 2003 compared to the nine months ended September 30, 2002

Net income for Avista Utilities was $19.9 million for the nine months ended September 30, 2003 compared to $24.8 million for the nine months ended September 30, 2002. Avista Utilities’ income from operations was $100.4 million for the nine months ended September 30, 2003 compared to $108.3 million for the nine months ended September 30, 2002. This decrease was primarily due to an increase in other operating expenses, partially offset by an increase in gross margin.

The increase in other operating expenses reflects increased pension and insurance costs. The increase in other operating expense was also due to initiatives implemented during the third quarter of 2001 designed to temporarily reduce certain operating expenses to improve liquidity and operating cash flows. These initiatives resulted in significantly reduced expenses for 2001 and the first half of 2002. Cost reduction measures were not as restrictive during the second half of 2002 and 2003 as the second half of 2001 and the first half of 2002.

The following table presents Avista Utilities’ gross margin for the nine months ended September 30 (dollars in thousands):

	Electric				Natural Gas				Total
	2003		2002		2003		2002		2003		2002
Operating revenues	$	484,126	$	429,175	$	173,224	$	218,982	$	657,350	$	648,157
Resource costs		218,742		173,026		111,728		151,990		330,470		325,016
Gross margin	$	265,384	$	256,149	$	61,496	$	66,992	$	326,880	$	323,141

Avista Utilities’ operating revenues increased $9.2 million and resource costs increased $5.5 million, which resulted in an increase of $3.7 million in gross margin for the nine months ended September 30, 2003 as compared to the nine months ended September 30, 2002. The gross margin on natural gas sales decreased $5.5 million and the gross margin on electric sales increased $9.2 million.

The decrease in the gross margin on natural gas sales was primarily due to a decrease in retail customer usage. Primarily due to milder weather during the first three months of 2003, total retail therm sales decreased by 5 percent.

The increase in electric gross margin was primarily due to the general electric rate increase of 19.3 percent in Washington base retail rates effective July 1, 2002. This increase was partially offset by the expense of the initial $9.0 million of power supply costs in Washington exceeding the amount included in base retail rates during the nine months ended September 30, 2003 as compared to $4.5 million expensed during the nine months ended September 30, 2002.

The following table presents Avista Utilities’ electric operating revenues and MWh sales for the nine months ended September 30 (dollars and MWhs in thousands):

		Electric Operating				Electric Energy
		Revenues				MWh sales
		2003		2002		2003		2002
Residential		$	145,710	$	141,139		2,337		2,303
Commercial			149,204		144,449		2,158		2,114
Industrial			56,932		51,194		1,285		1,146
Public street and highway lighting			3,564		3,485		19		19
	Total retail		355,410		340,267		5,799		5,582
Wholesale			60,139		51,470		1,740		1,869
Other			68,577		37,438		—		—
	Total	$	484,126	$	429,175		7,539		7,451

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AVISTA CORPORATION

Retail electric revenues increased $15.1 million for the nine months ended September 30, 2003 from the nine months ended September 30, 2002. This increase was primarily due to electric rate increases implemented during 2002 and partially due to an increase in total MWhs sold. The weather was generally milder than 2002 during the first quarter of 2003 which reduced MWh sales during the first part of the year. However, this was offset by warmer weather during the second and third quarters of 2003, which increased residential and commercial air conditioning usage during the period.

Wholesale electric revenues increased $8.7 million, or 17 percent, reflecting average sales prices that were 26 percent higher than the prior period, partially offset by a 7 percent decrease in wholesale sales volumes. Average wholesale prices increased to $34.57 per MWh for the nine months ended September 30, 2003 from $27.54 per MWh for the nine months ended September 30, 2002. The increase in average wholesale sales prices appears to primarily reflect decreased hydroelectric resources as compared to the prior year throughout the western United States and an increase in the cost of natural gas used for generation. The extent of future wholesale transactions will be based on the projection of future needs, the availability of resources owned or under contract by Avista Utilities, wholesale market prices and changes to loads of Avista Utilities’ customers and contractual obligations.

Other electric revenues increased $31.1 million primarily due to the sale of natural gas purchased as fuel for electric generation that was not used in generation. This natural gas was not used for generation because electric wholesale market prices were generally below the cost of operating the gas-fired thermal generating units.

The following table presents Avista Utilities’ natural gas operating revenues and therm sales for the nine months ended September 30 (dollars and therms in thousands):

	Natural Gas				Natural Gas
	Operating Revenues				Therm Sales
	2003		2002		2003		2002
Residential	$	103,109	$	127,778		125,334		130,336
Commercial		56,555		75,080		78,801		85,430
Industrial		4,512		5,754		8,134		8,368
Total retail		164,176		208,612		212,269		224,134
Wholesale		—		686		—		2,281
Transportation		6,299		7,202		108,864		129,631
Other		2,749		2,482		2,565		1,276
Total	$	173,224	$	218,982		323,698		357,322

Natural gas revenues decreased $45.8 million for the nine months ended September 30, 2003 from the nine months ended September 30, 2002 due to a decrease in retail rates. During the fourth quarter of 2002, retail rates for natural gas were reduced in response to a decrease in current and projected natural gas costs. The decrease also reflects a decrease in total therms sold as a result of mild weather during the first quarter of 2003.

The following table presents Avista Utilities’ average number of electric and natural gas customers as well as heating degree days for the nine months ended September 30:

			Electric				Natural Gas
			Customers				Customers
			2003		2002		2003		2002
Residential				282,640		279,188		260,029		253,907
Commercial				36,231		35,859		31,256		30,776
Industrial				1,414		1,421		309		315
Public street and highway lighting				419		410		—		—
	Total retail			320,704		316,878		291,594		284,998
Wholesale				50		47		—		1
Transportation				—		—		85		88
	Total customers			320,754		316,925		291,679		285,087
Heating degree days:
	Spokane, Washington
		Actual						3,794		4,338
		30 year average						4,201		4,243
	Medford, Oregon
		Actual						2,504		2,585
		30 year average						2,807		2,821

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The following table presents Avista Utilities’ resource costs for the nine months ended September 30 (dollars in thousands):

			2003			2002
Electric resource costs:
	Power purchased		$	105,305		$	72,972
	Power cost amortizations, net of deferrals			4,355			34,722
	Fuel for generation			25,360			13,692
	Other fuel costs			77,685			52,391
	Other regulatory amortizations, net			(5,955	)		(11,446	)
	Other electric resource costs			11,992			10,695
		Total electric resource costs		218,742			173,026
Natural gas resource costs:
	Natural gas purchased			117,262			120,003
	Natural gas cost amortizations (deferrals), net			(5,698	)		31,796
	Other regulatory amortizations, net			164			191
		Total natural gas resource costs		111,728			151,990
Total resource costs			$	330,470		$	325,016

Power purchased for the nine months ended September 30, 2003 increased $32.3 million, or 44 percent, compared to the nine months ended September 30, 2002 primarily due to an increase in price of power purchases and partially due to an increase in the volume of power purchases. Average purchased power prices for the nine months ended September 30, 2003 were $31.59 per MWh or 41 percent higher than $22.38 per MWh for the nine months ended September 30, 2002 and volumes purchased increased 2 percent compared to the nine months ended September 30, 2002. The increase in the price of power purchases reflects increases in the price of power in the western United States and the Pacific Northwest. This appears to be partially due to lower than normal precipitation and snowpack conditions during the fourth quarter of 2002 and the first two months of 2003 and the anticipated effects on hydroelectric generation in the region. Precipitation and snowpack conditions improved substantially during March 2003, which appears to be partially responsible for decreasing wholesale electric prices in March and April 2003. Warm and dry conditions in the Pacific Northwest as well as the increased cost of natural gas used to generate electricity during May through September of 2003 appear to have increased the price of electricity during the second and third quarters of 2003 as compared to the second and third quarters of 2002. Reduced hydroelectric availability and increased demand due to warmer weather also appear to have affected wholesale electric prices in the western United States and the Pacific Northwest.

Net amortization of deferred power costs was $4.4 million for the nine months ended September 30, 2003 compared to $34.7 million for the nine months ended September 30, 2002. During the nine months ended September 30, 2003, Avista Utilities recovered (collected as revenue) $19.2 million of previously deferred power costs in Washington and $19.4 million in Idaho. During the nine months ended September 30, 2003, Avista Utilities deferred $17.0 million of power costs in Washington and $17.4 million in Idaho.

During the nine months ended September 30, 2003, Avista Utilities had $5.7 million of net deferrals of natural gas costs compared to $31.8 million of net amortization for the nine months ended September 30, 2002.

The expense for natural gas purchased for the nine months ended September 30, 2003 decreased $2.7 million compared to the nine months ended September 30, 2002 primarily due to the decrease in total therms purchased consistent with a decrease in natural gas sales.

Fuel for generation for the nine months ended September 30, 2003 increased $11.7 million compared to the nine months ended September 30, 2002. This was due to expenses associated with natural gas used as fuel for Coyote Springs 2, which was placed into operation on July 1, 2003.

Other fuel costs for the nine months ended September 30, 2003 increased $25.3 million compared to the nine months ended September 30, 2002. This was due to an increase in natural gas purchased as fuel for electric generation that was not used. This natural gas was sold with the associated revenues reflected as other electric revenues. Other fuel costs exceeded the revenues from selling the natural gas. This cost is accounted for under the ERM in Washington and the PCA in Idaho.

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Energy Marketing and Resource Management

Energy Marketing and Resource Management includes the results of Avista Energy and Avista Power.

Avista Energy is an electricity and natural gas marketing and resource management business, operating primarily within the WECC. Avista Energy focuses on asset-backed optimization of combustion turbines and hydroelectric assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric and natural gas transmission and transportation arrangements. Avista Energy is also involved in the trading of electricity and natural gas, including derivative commodity instruments. Avista Energy’s marketing efforts are driven by its base of knowledge and experience in the operation of both electric energy and natural gas physical systems in the WECC, as well as its relationship-focused approach with its customers. Avista Energy’s earnings are primarily derived from the following activities:

• The marketing and management of combustion turbines and hydroelectric assets owned by other entities.

• The capture of price differences between commodities (spark spread) by converting natural gas into electricity through the power generation process.

• The purchase and storage of natural gas during periods of lower prices for sales during peak demand periods and higher prices.

• The transmission of electricity or transportation of natural gas between locations, including the moving of energy from lower priced/demand regions to higher priced/demand markets and hub locations throughout the WECC.

• Taking positions on future price movements within established risk management policies.

Both the volatility and liquidity in the wholesale energy markets affect Avista Energy’s earnings. The volatility in wholesale energy markets measures the size and frequency of price movements. Liquidity represents the volume of activity in the wholesale energy markets during a given period of time. Increases in the volatility and liquidity in wholesale energy markets generally increases Avista Energy’s earnings or losses while decreases in the volatility and liquidity tend to decrease Avista Energy’s earnings or losses.

Derivative commodity instruments in the energy trading portfolio are marked to estimated fair market value on a daily basis (mark-to-market accounting), which causes earnings variability. Market prices are utilized in determining the value of electric, natural gas and related derivative commodity instruments. For electric commodity instruments, these market prices are generally available through two years. For natural gas commodity instruments, these market prices are generally available through three years. For longer-term positions and certain short-term positions for which market prices are not available, models based on forward price curves are utilized. These models incorporate a variety of estimates and assumptions, the ultimate outcomes of which are beyond Avista Energy’s control including, among others, estimates and assumptions as to demand growth, fuel price escalation, availability of existing generation and costs of new generation. Actual experience can vary significantly from these estimates and assumptions.

Avista Energy trades electricity and natural gas, along with derivative commodity instruments including futures, options, swaps and other contractual arrangements. Most transactions are conducted on a largely unregulated “over-the-counter” basis, there being no central clearing mechanism (except in the case of specific instruments traded on the commodity exchanges). Avista Energy’s trading operations are affected by, among other things, volatility of prices within the electric energy and natural gas markets, the demand for and availability of energy, lower unit margins on new sales contracts, deregulation of the electric utility industry, the creditworthiness of counterparties and the reduced liquidity in energy markets. See “Business Risk” for further information.

Avista Energy reports the net margin on derivative commodity instruments accounted for under SFAS No. 133 as operating revenues. Revenues from contracts, which are not accounted for as derivatives under SFAS No. 133, are reported on a gross basis in operating revenues. Costs from contracts, which are not accounted for as derivatives under SFAS No. 133, are reported on a gross basis in resource costs.

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The following table presents Avista Energy’s gross margin for the three and nine months ended September 30 (dollars in thousands):

	Three months ended					Nine months ended
	September 30,					September 30,
	2003		2002			2003			2002
Realized gross margin	$	7,034	$	61,471		$	62,268		$	125,003
Unrealized gross margin		5,740		(51,708	)		(10,997	)		(80,889	)
Total gross margin	$	12,774	$	9,763		$	51,271		$	44,114

Three months ended September 30, 2003 compared to the three months ended September 30, 2002

Energy Marketing and Resource Management’s net income was $4.8 million for the three months ended September 30, 2003, compared to $2.7 million for the three months ended September 30, 2002. The primary reason for the increase in net income was an increase in the gross margin (operating revenues less resource costs). Operating revenues increased $18.7 million and resource costs increased $15.6 million for the three months ended September 30, 2003 as compared to the three months ended September 30, 2002.

Avista Energy’s gross margin was $12.8 million for the three months ended September 30, 2003 compared to $9.8 million for the three months ended September 30, 2002. The increase in gross margin was partially due to accounting for energy contracts under SFAS No. 133, which resulted in certain contracts with net unrecognized losses of $0.3 million for the three months ended September 30, 2003 not being accounted for at market value. These losses are recognized as the contracts are settled or realized. These contracts that are not accounted for at market value economically hedge certain other contracts with unrealized gains for the three months ended September 30, 2003, that are considered derivatives under SFAS No. 133, and as such are recorded at market value with a positive impact on gross margin. During September 2003, Avista Energy implemented hedge accounting for certain transactions. This should partially mitigate the effects from the transition to SFAS No. 133 and reduce the volatility of reporting earnings on a prospective basis.

Realized gains decreased to $7.0 million for the three months ended September 30, 2003 from $61.5 million for the three months ended September 30, 2002. Realized gains represent the net gain on contracts that have settled. The decrease in realized gains was primarily due to a decrease in the gains on physical electric and natural gas transactions. The decrease in realized gains on physical electric and natural gas transactions was due to a decrease in the average margin. The total mark-to-market adjustment for Energy Marketing and Resource Management was an unrealized gain of $5.7 million for the three months ended September 30, 2003 compared to an unrealized loss of $51.7 million for the three months ended September 30, 2002. The change in the unrealized gain/loss was primarily due to the settlement of contracts and the realization of previously unrealized gains during the three months ended September 30, 2002.

Administrative and general expenses increased $0.4 million, or 8 percent, from the prior period primarily due to increased incentive compensation expense based on higher earnings in the third quarter of 2003, partially offset by decreased professional fees.

Nine months ended September 30, 2003 compared to the nine months ended September 30, 2002

Energy Marketing and Resource Management’s net income was $21.1 million (excluding the cumulative effect of accounting change) for the nine months ended September 30, 2003, compared to $19.4 million for the nine months ended September 30, 2002. Operating revenues increased $46.0 million and resource costs increased $38.9 million for the nine months ended September 30, 2003 as compared to the nine months ended September 30, 2002.

Avista Energy’s gross margin (operating revenues less resource costs) was $51.3 million for the nine months ended September 30, 2003 compared to $44.1 million for the nine months ended September 30, 2002. The increase in gross margin was partially due to the transition to SFAS No. 133 which resulted in certain contracts with net unrecognized losses of $8.2 million for the nine months ended September 30, 2003 not being accounted for at market value. These losses are recognized as the contracts are settled or realized. These contracts that are not accounted for at market value economically hedge certain other contracts with unrealized gains for the nine months ended September 30, 2003 that are considered derivatives under SFAS No. 133, and as such are recorded at market value with a positive impact on gross margin. The positive effects of the transition to SFAS No. 133 will be reversed in future periods as market values change or the contracts are settled and realized. During September 2003, Avista Energy implemented hedge accounting for certain transactions. This should partially mitigate the effects from the transition to SFAS No. 133 and reduce the volatility of reporting earnings on a prospective basis. Avista Energy’s

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settlement of various positions with Enron Corporation affiliates and the resulting release by Avista Energy of amounts which had been reserved against such positions also had a positive impact of $8.3 million on gross margin for the nine months ended September 30, 2003. During the nine months ended September 30, 2003, Avista Energy reached settlement agreements on its terminated positions with certain Enron Corporation affiliates. These settlement agreements were approved by the U.S. Bankruptcy Court in May 2003. In each instance, the settlement agreements reached satisfy all of the Avista entity’s obligations and exposure to such Enron Corporation affiliate.

Realized gains decreased to $62.3 million for the nine months ended September 30, 2003 from $125.0 million for the nine months ended September 30, 2002. Realized gains represent the net gain on contracts that have settled. The decrease in realized gains was primarily due to a decrease in the gains on physical electric and natural gas transactions partially offset by the settlement with Enron Corporation affiliates, increased gains on settled financial transactions and gains on the change in natural gas inventory valuations. Realized gains for the nine months ended September 30, 2002 also reflects gains from the settlement of transactions that were initiated during the period of high wholesale market prices and volatility during 2000 and 2001. The total mark-to-market adjustment for Energy Marketing and Resource Management was an unrealized loss of $11.0 million for the nine months ended September 30, 2003 compared to an unrealized loss of $80.9 million for the nine months ended September 30, 2002. The change in the unrealized loss was primarily due to the transition to SFAS No. 133 described above and the settlement of contracts with significant realized gains during the nine months ended September 30, 2002.

Energy Marketing and Resource Management’s total assets decreased $353.1 million from December 31, 2002 to September 30, 2003 primarily due to a decrease in energy commodity assets and the transfer of the Coyote Springs 2 plant from Avista Power to Avista Corp. in January 2003. The decrease in energy commodity assets reflects both the settlement of contracts during the period and a decrease in energy commodity prices.

Energy trading activities and positions

The following table summarizes information with respect to Avista Energy’s trading activities during the nine months ended September 30, 2003 (dollars in thousands):

	Electric			Natural Gas			Total
	Assets net of			Assets net of			Unrealized
	Liabilities			Liabilities			Gain (Loss)
Fair value of contracts as of December 31, 2002	$	60,081		$	34,720		$	94,801
Less contracts settled during 2003 (1)		(44,378	)		(17,890	)		(62,268	)
Cumulative effect of accounting change (2)		(357	)		(1,473	)		(1,830	)
Fair value of new contracts when entered into during 2003 (3)		—			—			—
Change in fair value due to changes in valuation techniques (4)		—			—			—
Change in fair value attributable to market prices and other market changes		47,075			3,916			50,991
Fair value of contracts as of September 30, 2003	$	62,421		$	19,273		$	81,694

(1)	Contracts settled during the nine months ended September 30, 2003 include those contracts that were open in 2002 but settled during the nine months ended September 30, 2003 as well as new contracts entered into and settled during the nine months ended September 30, 2003. Amount represents realized gains associated with these settled transactions.
(2)	Represents the adjustment for the transition to SFAS No. 133 for contracts not meeting the definition of a derivative. Effective January 1, 2003, contracts that were entered into on or prior to October 25, 2002 and not meeting the definition of a derivative are accounted for on an accrual basis. Contracts not meeting the definition of a derivative include Avista Energy’s Agency Agreement with Avista Utilities, natural gas storage contracts, tolling agreements and natural gas transportation agreements.
(3)	Avista Energy has not entered into any origination transactions during the nine months ended September 30, 2003 in which dealer profit or mark-to-market gain or loss was recorded at inception.
(4)	During the nine months ended September 30, 2003, Avista Energy did not experience a change in fair value as a result of changes in valuation techniques.

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The following table discloses summarized information with respect to valuation techniques and contractual maturities of Avista Energy’s energy commodity contracts outstanding as of September 30, 2003 (dollars in thousands):

					Greater			Greater
					than one			than three		Greater
		Less than			and less than			and less than		than
		one year			three years			five years		five years			Total
Electric assets (liabilities), net
	Prices from other external sources (1)	$	24,273		$	21,225		$	—	$	—		$	45,498
	Fair value based on valuation models (2)		(797	)		14,409			10,697		(7,386	)		16,923
	Total electric assets (liabilities), net	$	23,476		$	35,634		$	10,697	$	(7,386	)	$	62,421
Natural gas assets (liabilities), net
	Prices from other external sources (1)	$	8,722		$	4,132		$	—	$	—		$	12,854
	Fair value based on valuation models (3)		6,446			(1,244	)		791		426			6,419
	Total natural gas assets (liabilities), net	$	15,168		$	2,888		$	791	$	426		$	19,273

(1)	Fair value is determined based upon actively traded, “over-the-counter” market quotes received from third party brokers. For electric assets and liabilities, these market quotes are generally available through two years. For natural gas assets and liabilities, these market quotes are generally available through three years.
(2)	Represents contracts for delivery at basis locations not actively traded in the “over-the-counter” markets. In addition, this includes all contracts with a delivery period greater than two years, for which active quotes are not available. These internally developed market curves are determined using a production cost model with inputs for assumptions related to power prices (including, without limitation, natural gas prices, generation on- line, transmission constraints, future demand and weather). Avista Energy performs frequent stress tests on the valuation of the portfolio. While consistent valuation methodologies are used and updates to the assumptions are used to capture current market information, changes in these methodologies or underlying assumptions could result in significantly different fair values and income recognition. These same pricing techniques and stress tests are used to evaluate a contract prior to taking a position.
(3)	Represents contracts for delivery at basis locations not actively traded in the “over-the-counter” markets. In addition, this includes all contracts with a delivery period greater than three years, for which active quotes are not available. These internally developed market curves are based upon published New York Mercantile Exchange prices through seven years, as well as basis spreads using historical and broker estimates. After seven years, an escalation is used to estimate the valuation.

Avista Power

Avista Power is a 49 percent owner of the Lancaster Project, which commenced commercial operation in September 2001. Cogentrix Energy, Inc. which owns 51 percent of the Lancaster Project, is in the process of being acquired by the Goldman Sachs Group, Inc. in a transaction that is expected to be completed in early 2004. All of the output from the Lancaster Project is contracted to Avista Energy for 25 years. Avista Power and its co-owner, Mirant Oregon LLC (Mirant Oregon) an affiliate of Mirant Americas Development, Inc., substantially completed the construction of Coyote Springs 2 during 2002. In January 2003, Avista Power’s 50 percent ownership interest in Coyote Springs 2 was transferred to Avista Corp. for inclusion in Avista Utilities’ power generation resource portfolio. See “New Generating Resource – Avista Utilities” for further information.

Avista Advantage

Avista Advantage remains focused on growing revenue, improving margins, reducing fixed and variable costs and continuously enhancing client satisfaction.

The following table presents Avista Advantage’s gross margin for the three and nine months ended September 30 (dollars in thousands):

		Three months ended				Nine months ended
		September 30,				September 30,
		2003		2002		2003		2002
Operating revenues		$	5,002	$	4,419	$	14,736	$	12,182
Operation and maintenance expenses			2,841		3,235		9,038		10,330
	Total gross margin	$	2,161	$	1,184	$	5,698	$	1,852

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Three months ended September 30, 2003 compared to the three months ended September 30, 2002

Avista Advantage’s net loss was $0.3 million for the three months ended September 30, 2003 compared to $0.9 million for the three months ended September 30, 2002. Operating revenues for Avista Advantage increased $0.6 million and operating expenses decreased $0.4 million, as compared to the three months ended September 30, 2002. The increase in operating revenues was primarily due to the expansion of Avista Advantage’s customer base. The decrease in operating expenses reflects improved efficiencies, a reduction in the number of employees and a focus on reducing operating expenses.

Nine months ended September 30, 2003 compared to the nine months ended September 30, 2002

Avista Advantage’s net loss was $1.2 million for the nine months ended September 30, 2003 compared to $3.6 million for the nine months ended September 30, 2002. Operating revenues for Avista Advantage increased $2.6 million and operating expenses decreased $1.6 million, as compared to the nine months ended September 30, 2002. The increase in operating revenues was primarily due to the expansion of Avista Advantage’s customer base. Avista Advantage had an 18 percent increase in the number of billed sites as of September 30, 2003 compared to September 30, 2002. The decrease in operating expenses reflects improved efficiencies, a reduction in the number of employees and a focus on reducing operating expenses. Total costs per account were reduced by 26 percent for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002.

Other

The Other line of business includes Avista Ventures, Pentzer, Avista Development, Avista Services and the operations of Avista Capital that are not included through its subsidiaries. As opportunities arise, the Company plans to dispose of investments and phase out of operations in the Other business segment.

Three months ended September 30, 2003 compared to the three months ended September 30, 2002

The net loss from this line of business was $1.1 million for the three months ended September 30, 2003, compared to $0.5 million for the three months ended September 30, 2002. The increase in the net loss was partially due to a decrease in interest income. An increase in the net loss recorded by Advanced Manufacturing and Development also contributed to the increase in the net loss for the segment. Operating revenues from this line of business decreased $1.0 million and operating expenses decreased $1.0 million, respectively, for the three months ended September 30, 2003 as compared to the three months ended September 30, 2002.

Nine months ended September 30, 2003 compared to the nine months ended September 30, 2002

The net loss from this line of business was $4.3 million for the nine months ended September 30, 2003, compared to $10.5 million (excluding the cumulative effect of accounting change) for the nine months ended September 30, 2002. The decrease in the net loss was primarily due to an increase in income from operations. Operating revenues from this line of business increased $0.3 million and operating expenses decreased $10.0 million, respectively, for the nine months ended September 30, 2003 as compared to the nine months ended September 30, 2002. The increase in income from operations was primarily due to a decrease in litigation costs and settlements. The improvement in income from operations was partially offset by an increase in losses on certain other investments of Avista Ventures not related to Advanced Manufacturing and Development.

Discontinued Operations

In July 2003, Avista Corp. announced an investment of $6.0 million by a group of private equity investors in a new entity, AVLB, Inc., which acquired the assets previously held by Avista Corp.’s fuel cell manufacturing and development subsidiary, Avista Labs. In September 2003, AVLB, Inc. (doing business under the name Avista Labs) received an additional investment by private equity investors of $6.2 million. This investment relieved Avista Corp. of its commitment to provide additional funding of up to $1.5 million to AVLB, Inc. Avista Corp. has an ownership interest of approximately 17.5 percent in AVLB, Inc., with the opportunity but no further obligation to fund or invest in this business.

In September 2001, the Company reached a decision that it would dispose of substantially all of the assets of Avista Communications. The divestiture of the operating assets of Avista Communications was complete by the end of 2002.

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Amounts reported as discontinued operations for the three and nine months ended September 30, 2003 represent the operations of Avista Labs. Amounts reported as discontinued operations for the three and nine months ended September 30, 2002 represents the operations of Avista Communications and Avista Labs.

New Generating Resource – Avista Utilities

In July 2003, the 280 MW combined cycle natural gas-fired combustion turbine power plant at Coyote Springs located near Boardman, Oregon was placed into operation. The Company’s ownership interest in the plant was transferred from Avista Power to Avista Corp. in January 2003 to be operated as an asset of Avista Utilities. Avista Corp. and Mirant Oregon are sharing equally in the costs of operation and output from Coyote Springs 2. Each owner is separately responsible for arranging for the purchase and delivery of natural gas in order to fuel its respective interest in the plant. Each owner is also separately responsible for the sale and delivery of electric energy generated with respect to its interest in the plant.

Transactions with Mirant Corporation

On July 14, 2003, Mirant Corporation and substantially all its subsidiaries in the United States filed for bankruptcy protection under chapter 11 of the bankruptcy code for protection from creditors.

The Company does not expect the bankruptcy filing by Mirant Corporation, which did not include Mirant Oregon, the owner of one-half of Coyote Springs 2, to have any material effect on the joint ownership and operation of the plant. Avista Corp. and Mirant Oregon are both current with respect to their obligations to share equally in the costs of the plant. While physical limitations prevent the operation of the plant at less than approximately seventy percent of its base load capacity, the joint operating agreement provides mechanisms to allow a single owner to dispatch and direct the operation of more than its interest in the plant in order to achieve operation at or above the plant’s minimum dispatch level in the event that the other owner is unable or unwilling to dispatch its portion of the plant. Additionally, provisions in the joint operating agreement provide that if either party fails to fund its portion of the operating costs or otherwise meet its obligations under the joint operating agreement, that the non-defaulting owner may elect a variety of remedies. Such remedies include the right, after notice and a cure period, (i) to convert a payment default into an adjustment of the ownership interests in the plant, resulting in a reduction of the defaulting owner’s interest and a corresponding increase in the non-defaulting owner’s interest, (ii) to declare a default and pursue recovery of unpaid amounts or other equitable remedies against the defaulting party, (iii) to exercise a purchase option to acquire the defaulting owner’s interest in the plant, or (iv) to trigger a retirement of the plant. The Company will continue to assess the ability of Mirant Oregon to perform its obligations under the joint operating agreement and the need to exercise remedies in the event the impact of the Mirant Corporation bankruptcy prevents Mirant Oregon from performing its obligations with respect to Coyote Springs 2.

Both Avista Corp. and Avista Energy had energy contracts with a subsidiary of Mirant Corporation that was included in the bankruptcy filing, Mirant Americas Energy Marketing (MAEM). The bankruptcy filing did not represent an event of default or trigger the termination of Avista Corp.’s natural gas swap contract with MAEM. As of the bankruptcy filing date, Avista Corp. was in a liability position with respect to this contract and does not expect to have any material adverse effect on its financial condition or results of operations as a result of this bankruptcy filing. The bankruptcy filing constituted an event of default under contracts between Avista Energy and MAEM. As a result, Avista Energy terminated all of its contracts and suspended trading activities with MAEM. Avista Energy’s contracts with MAEM provide that, upon termination, the net settlement of accounts receivable and accounts payable will be netted against the net mark-to-market value of the terminated forward contracts. As of the bankruptcy filing date, it is estimated that for Avista Energy, netting the mark-to-market positions against net accounts receivables or payables results in a net liability position and will not result in any material adverse effect on its financial condition or results of operations.

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Liquidity and Capital Resources

Review of Cash Flow Statement

Continuing Operating Activities Net cash provided by continuing operating activities was $120.7 million for the nine months ended September 30, 2003 compared to $287.0 million for the nine months ended September 30, 2002. The primary reason for the decrease in net cash provided by continuing operating activities was a decrease in cash provided by working capital components, a change in power and natural gas cost amortizations and deferrals and a change in energy commodity assets and liabilities. Power and natural gas cost deferrals, net of amortization, were $1.3 million for the nine months ended September 30, 2003 compared to net amortization of $66.5 million for the nine months ended September 30, 2002. This was primarily due to reduced amortization (and a corresponding decrease in cash revenues received from customers) of deferred natural gas costs and the reduced amortization (as a greater percentage of electric rate increases have been allocated to a general rate increase) of deferred power costs in Washington. The amortization of deferred power and natural gas costs is substantially matched by an increase in cash revenues collected from customers. The deferral of power and natural gas costs is substantially matched by an increase in cash resource costs paid for power and natural gas costs. Net cash provided by working capital components was $23.3 million for the nine months ended September 30, 2003, compared to $99.2 million for the nine months ended September 30, 2002. Significant changes in non-cash items also included a $69.9 million change in energy commodity assets and liabilities, representing the change from an unrealized loss of $80.9 million on energy trading activities for Avista Energy for the nine months ended September 30, 2002 to an unrealized loss of $11.0 million for the nine months ended September 30, 2003. The $28.9 million change in the provision for deferred income taxes was primarily due to changes in deferred power and natural gas cost amortizations and deferrals described above.

Continuing Investing Activities Net cash used in continuing investing activities was $87.7 million for the nine months ended September 30, 2003, an increase compared to $55.5 million for the nine months ended September 30, 2002. The increase was primarily due to an increase in utility property construction expenditures and the investment in securities held for trading. Utility property construction expenditures were unusually low during 2002 due to liquidity constraints. The securities held for trading represents the investment of cash held at Avista Energy in short-term instruments.

Continuing Financing Activities Net cash used in continuing financing activities was $28.9 million for the nine months ended September 30, 2003 compared to $198.2 million for the nine months ended September 30, 2002. During the nine months ended September 30, 2003, short-term borrowings increased $55.5 million, the Company repurchased $52.5 million of long-term debt scheduled to mature in future years, and $57.1 million of long-term debt matured. In September 2003, the Company issued $45.0 million (net proceeds of $44.8 million) of 6.125 percent First Mortgage Bonds due in 2013. The increase in short-term borrowings primarily reflects an increase in the amount of debt outstanding under Avista Corp.’s line of credit. The overall decrease in borrowings during the nine months ended September 30, 2003 reflects positive cash flows from operations.

During the nine months ended September 30, 2002, the Company repurchased $200.5 million of long-term debt and short-term borrowings increased $34.0 million.

Overall Liquidity

During 2002 and the nine months ended September 30, 2003, the Company’s overall liquidity improved compared to 2001. The general electric rate case order issued by the WUTC in June 2002 is allowing the Company to continue to improve its liquidity. The general electric rate case order provided for the restructuring and continuation of previously approved rate increases totaling 31.2 percent. The general increase to base retail rates was 19.3 percent and the remaining 11.9 percent represents the continued recovery of deferred power costs. Additionally, the Company has a PCA surcharge of 19.4 percent in place in Idaho. See further details in the section “Avista Utilities - Regulatory Matters.”

For 2003, operating budgets were designed to control operating costs and limit capital expenditures. In addition to operating expenses, the Company has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities. In 2001, the Company incurred substantial levels of indebtedness, both short and long-term, to finance these requirements and to otherwise maintain adequate levels of working capital. As a result of improved operating cash flow, during 2002 and through September 30, 2003, the Company repurchased $256.1 million of long-term debt.

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If Avista Utilities’ power and natural gas costs were to significantly exceed the levels currently recovered from retail customers, its cash flows would be negatively affected. Factors that could cause purchased power costs to exceed the levels currently recovered from customers include, but are not limited to, higher prices in wholesale markets combined with an increased need to purchase power in the wholesale markets. Current FERC imposed price caps limit wholesale market prices to $250 per MWh. Factors beyond the Company’s control that could result in an increased need to purchase power in the wholesale markets include, but are not limited to, increases in demand (either due to weather or customer growth), low availability of hydroelectric resources, outages at generating facilities and failure of third parties to deliver on energy or capacity contracts.

Covenants in Avista Energy’s credit agreement as well as certain counterparty agreements result in Avista Energy maintaining certain levels of cash and therefore inherently limiting the amount of cash dividends that are available for distribution to Avista Capital and ultimately to Avista Corp.

In July 2003, Avista Corp. announced an investment by a group of private equity investors in a new entity, AVLB, Inc., which acquired the assets previously held by Avista Corp.’s fuel cell manufacturing and development subsidiary, Avista Labs. In September 2003, AVLB, Inc. (doing business under the name Avista Labs) received an additional investment by private equity investors of $6.2 million. This eliminates Avista Corp.’s future funding requirements for this business while preserving the opportunity, but not the obligation, for future investment.

Capital Resources

The Company incurred significant indebtedness to support capital expenditures, to fund power and natural gas costs that were in excess of the amount recovered currently through rates and to maintain working capital through the end of 2001. However, as of September 30, 2003, the Company’s total debt outstanding was $1,000.9 million, a decrease from $1,004.5 million as of December 31, 2002 and $1,252.6 million as of December 31, 2001. The decrease from December 31, 2002 was primarily due to the repurchase of long-term debt and the maturity of long-term debt, partially offset by the issuance of long-term debt in September 2003 and an increase in short-term borrowings. The decrease in total debt was made possible by positive operating cash flows from both Avista Utilities and Avista Energy. The Company needs to finance capital expenditures and obtain additional working capital from time to time. The cash requirements needed to service indebtedness, both short-term and long-term, reduces the amount of cash flow available to fund working capital, purchased power and natural gas costs, capital expenditures, dividends and other corporate requirements.

The Company generally funds capital expenditures with a combination of internally generated cash and external financing. The level of cash generated internally and the amount that is available for capital expenditures fluctuates depending on a variety of factors. Cash provided by utility operating activities and cash generated by Avista Energy are expected to be the Company’s primary sources of funds for operating needs, dividends and capital expenditures for 2003.

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 September 30, 2003 and December 31, 2002, the Company had $85.0 million and $30.0 million, respectively, of borrowings outstanding under this committed line of credit. As of September 30, 2003 and December 31, 2002, there were $11.0 million and $14.3 million in letters of credit outstanding, respectively. The committed line of credit is secured by $245.0 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 permit the ratio of “consolidated total debt” (not including preferred securities) to “consolidated total capitalization” of Avista Corp. to be, at the end of any fiscal quarter, greater than 65 percent. As of September 30, 2003, the Company was in compliance with this covenant with a ratio of 53.8 percent. The committed line of credit also has a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the twelve-month period ending September 30, 2003 to be greater than 1.6 to 1. As of September 30, 2003, the Company was in compliance with this covenant with a ratio of 2.18 to 1.

Any default on its committed line of credit or other financing arrangements could result in cross-defaults to other agreements and could induce vendors and other counterparties to demand collateral. In the event of default, it would be difficult for the Company to obtain financing on any reasonable terms to pay creditors or fund operations, and the

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Company would likely be prohibited from paying dividends on its common stock. As of September 30, 2003, Avista Corp. was in compliance with the covenants of all of its financing agreements.

In March 2003, the Company redeemed 17,500 shares of preferred stock for $1.6 million, satisfying its redemption requirement for 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 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 September 30, 2003, the Company could issue $64.4 million of additional First Mortgage Bonds under the most restrictive of these financing agreements.

On June 25, 2003, the Company filed a registration statement on Form S-3 with the Securities and Exchange Commission for the purpose of issuing up to $150.0 million of secured or unsecured debt securities. In September 2003, the Company issued $45.0 million of 6.125 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 and is expected to result in an overall reduction in the Company’s interest expense.

In July 2001, the Company filed a registration statement on Form S-3 with the Securities and Exchange Commission for the purpose of issuing up to 3.7 million shares of common stock. No common stock has been issued and the Company currently does not have any plans to issue common stock under this registration statement.

Inter-Company Debt; Subordination

As part of its on-going cash management practices and operations, Avista Corp. from time to time makes unsecured short-term loans to, and borrowings from, Avista Capital. In turn, Avista Capital from time to time makes unsecured short-term loans to, and borrowings from, its subsidiaries. As of September 30, 2003, Avista Corp. held short-term notes receivable from Avista Capital in the principal amount of $40.0 million.

In addition, Avista Capital from time to time guarantees the indebtedness and other obligations of its subsidiaries. See “Energy Marketing and Resource Management Operations” for further information.

The credit arrangements of Avista Capital’s subsidiaries generally provide that any indebtedness owed by such entity to its corporate parent will be subordinated to the indebtedness outstanding under such credit arrangements.

The right of Avista Corp., as a shareholder, to receive assets of any of its direct or indirect subsidiaries upon the subsidiary’s liquidation or reorganization (and the consequent right of the holders of debt securities and other creditors of Avista Corp. to participate in those assets) is junior to the claims against such assets of that subsidiary’s creditors. As a result, the obligations of Avista Corp. to its debt securityholders and other unrelated creditors are effectively subordinated in right of payment to all indebtedness and other liabilities and commitments (including trade payables and lease obligations) of Avista Corp.’s direct and indirect subsidiaries. Similarly, the obligations of Avista Capital to its creditors are effectively subordinated in right of payment to all indebtedness and other liabilities and commitments of its direct and indirect subsidiaries.

Pension Plan

As of September 30, 2003, the Company’s pension plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. In 2002, the Company recorded an additional minimum liability for the unfunded accumulated benefit obligation of $33.4 million and an intangible asset of $6.4 million (representing the amount of unrecognized prior service cost) related to the pension plan. This resulted in a charge to other comprehensive loss of $17.6 million, net of taxes.

The Company does not expect the current pension plan funding deficit to have a material adverse impact on its financial condition, results of operations or cash flows. 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. The Company has made $12 million in cash contributions to the pension plan in 2003 and expects to make $15 million in cash contributions over the next 12 months. The Company’s goal is to have the pension plan’s current obligations fully funded by 2006.

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Off-Balance Sheet Arrangements

Avista Receivables Corp. (ARC), formerly known as WWP Receivables Corp., is a wholly owned, bankruptcy-remote subsidiary of the Company formed in 1997 for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On May 29, 2002, ARC, the Company and a third-party financial institution entered into a three-year agreement whereby ARC can sell without recourse, on a revolving basis, up to $100.0 million of those receivables. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. As of September 30, 2003, $40.0 million in receivables were sold pursuant to the agreement.

WP Funding LP is an entity that was formed in 1993 for the purpose of acquiring the natural gas-fired combustion turbine generating facility in Rathdrum, Idaho (Rathdrum CT). WP Funding LP purchased the Rathdrum CT from the Company with funds provided by unrelated investors of which 97 percent represented debt and 3 percent represented equity. The Company operates the Rathdrum CT and leases it from WP Funding LP and currently makes lease payments of $4.5 million per year. The total amount of WP Funding LP debt outstanding that was not included on the Company’s balance sheet was $54.6 million as of September 30, 2003. The lease term expires in February 2020; however, the current debt matures in October 2005 and will need to be refinanced at that time. The addition of the Rathdrum CT to Avista Utilities’ generation resource base, which entered commercial operation in 1995, was reviewed in previous state regulatory filings with the WUTC and IPUC. FASB Interpretation No. 46 will require the Company to consolidate WP Funding LP effective for the period ended December 31, 2003. Based on September 30, 2003 amounts, the consolidation of WP Funding LP will increase long-term debt by $54.6 million, net utility plant by $40.2 million, regulatory assets by $16.1 million and other liabilities by $1.7 million (representing minority interest).

Total Company Capitalization

The Company’s consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as of September 30, 2003 and December 31, 2002 (dollars in thousands):

		September 30, 2003					December 31, 2002
				Percent					Percent
		Amount		of total			Amount		of total
Current portion of long-term debt		$	16,283		0.9	%	$	71,896		3.9	%
Short-term borrowings			85,530		4.6			30,000		1.6
Long-term debt			899,048		48.3			902,635		48.8
	Total debt		1,000,861		53.8			1,004,531		54.3
Company-obligated mandatorily redeemable preferred trust securities			100,000		5.3			—		—
Preferred stock-cumulative			31,500		1.7			—		—
	Total liabilities		1,132,361		60.8			1,004,531		54.3
Company-obligated mandatorily redeemable preferred trust securities			—		—			100,000		5.4
Preferred stock-cumulative			—		—			33,250		1.8
Common equity			729,309		39.2			712,791		38.5
	Total	$	1,861,670		100.0	%	$	1,850,572		100.0	%

The Company’s total debt decreased by $3.7 million due to both the repurchase of long-term debt and the maturity of long-term debt, partially offset by the issuance of long-term debt in September 2003 and an increase in short-term borrowings. The Company’s consolidated common equity increased $16.5 million during the nine months ended September 30, 2003 primarily due to net income and the issuance of common stock through the Dividend Reinvestment Plan and employee benefit plans, partially offset by dividends. The Company has a target capital structure of 50 percent total debt and 50 percent preferred trust securities, preferred stock and common equity.

Credit Ratings

The Company’s credit ratings were downgraded during the fourth quarter of 2001 resulting in an overall corporate credit rating that is below investment grade. The downgrade was due to liquidity concerns primarily related to the significant amount of purchased power and natural gas costs incurred and the resulting increase in debt levels and debt service costs.

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The following table summarizes the Company’s current credit ratings:

		Standard & Poor's	Moody's	Fitch, Inc.
Avista Corporation
	Corporate/Issuer rating	BB+	Ba1	BB+
	Senior secured debt	BBB-	Baa3	BBB-
	Senior unsecured debt	BB+	Ba1	BB+
	Preferred stock	BB-	Ba3	BB
Avista Capital I*
	Preferred Trust Securities	BB-	Ba2	BB+
Avista Capital II*
	Preferred Trust Securities	BB-	Ba2	BB
Rating outlook		Stable	Negative	Stable

* Only assets are subordinated debentures of Avista Corporation

These security ratings are not recommendations to buy, sell or hold securities. The ratings are subject to change or withdrawal at any time by the respective credit rating agencies. Each credit rating should be evaluated independently of any other rating.

Avista Utilities Operations

Avista Utilities held cash deposits from other parties in the amount of $22.2 million as of September 30, 2003, which is included in cash and cash equivalents with a corresponding amount in other current liabilities on the Consolidated Balance Sheet. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral.

As of September 30, 2003, Avista Utilities had $32.9 million in cash and temporary investments, including the $22.2 million of cash deposits from other parties.

See “Notes 4, 7, 8, 9 and 10 of Notes to Consolidated Financial Statements” for additional details related to financing activities.

Energy Marketing and Resource Management Operations

On July 25, 2003, Avista Energy and its subsidiary, Avista Energy Canada, Ltd., as co-borrowers, entered into a committed credit agreement with a group of banks in the aggregate amount of $110.0 million expiring July 23, 2004, replacing a previous uncommitted credit agreement that had an extended expiration date of July 31, 2003. This new committed credit facility provides for the issuance of letters of credit to secure contractual obligations to counterparties. This facility is guaranteed by Avista Capital and secured by Avista Energy’s assets. The maximum amount of credit extended by the banks for the issuance of letters of credit is the subscribed amount of the facility less the amount of outstanding cash advances, if any. The maximum amount of credit extended by the banks for cash advances is $30.0 million. No cash advances were outstanding under the credit agreement as of September 30, 2003. Letters of credit in the aggregate amount of $32.2 million and $17.4 million were outstanding as of September 30, 2003 and December 31, 2002, respectively.

The Avista Energy credit agreement contains customary covenants and default provisions, including covenants to maintain “minimum net working capital” and “minimum net worth”, as well as a covenant limiting the amount of indebtedness which the co-borrowers may incur. The credit agreement also contains covenants and other restrictions related to Avista Energy’s trading limits and positions, including VAR limits, restrictions with respect to changes in risk management policies or volumetric limits, and limits on exposure related to hourly and daily trading of electricity. Also, a reduction in the credit rating of Avista Corp. would represent an event of default under Avista Energy’s credit agreement. Avista Energy was in compliance with the covenants of its credit agreement as of September 30, 2003.

Avista Capital provides guarantees for Avista Energy’s credit agreement and, in the course of business, may provide guarantees to other parties with whom Avista Energy may be doing business. At any point in time, Avista Capital is only liable for the outstanding portion of the guarantee, which was $34.9 million as of September 30, 2003. The face value of all performance guarantees issued by Avista Capital for energy trading contracts at Avista Energy was $436.2 million as of September 30, 2003.

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Avista Energy manages collateral requirements with counterparties by providing letters of credit, providing guarantees from Avista Capital, depositing cash with counterparties and offsetting transactions with counterparties. Cash deposited with counterparties totaled $50.5 million as of September 30, 2003, which is included in prepayments and other current assets on the Consolidated Balance Sheet. Avista Energy held cash deposits from other parties in the amount of $86.7 million as of September 30, 2003, which is included in cash and cash equivalents with a corresponding amount in other current liabilities on the Consolidated Balance Sheet. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral.

As of September 30, 2003, Avista Energy had $152.9 million in cash, including the $86.7 million of cash deposits from other parties. In addition, Avista Energy had $18.9 million of short-term investments held for trading as of September 30, 2003. Covenants in Avista Energy’s credit agreement as well as certain counterparty agreements result in Avista Energy maintaining certain levels of cash and therefore inherently limiting the amount of cash dividends that are available for distribution to Avista Capital and ultimately to Avista Corp. During the nine months ended September 30, 2003 Avista Energy paid $2.1 million in dividends to Avista Capital. During October 2003, Avista Energy paid $10.0 million in dividends to Avista Capital.

Avista Advantage Operations

As of September 30, 2003, Avista Advantage had $0.1 million of cash and cash equivalents and $2.4 million in debt was outstanding. Avista Advantage’s outstanding debt is related to capital leases.

Other Operations

As of September 30, 2003, this line of business had $1.3 million of cash and cash equivalents and $0.7 million in debt was outstanding. The outstanding debt includes short-term borrowings and capital leases.

Contractual Obligations

The Company’s future contractual obligations have not changed materially from the amounts disclosed in the 2002 Form 10-K with the following exceptions:

In September 2003, the Company issued $45.0 million of 6.125 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.

The following table details the Company’s debt repurchases prior to scheduled maturity from January 1, 2003 through September 30, 2003 (dollars in thousands):

Repurchase		Interest			Maturity		Principal
Date	Description	Rate			Year		Amount
January 2003	Unsecured Senior Notes		9.75	%		2008	$	10,000
February 2003	Unsecured Senior Notes		9.75	%		2008		505
March 2003	Unsecured Medium-Term Notes		8.23	%		2022		5,000
April 2003	Unsecured Medium-Term Notes		6.88	%		2028		10,000
May 2003	Unsecured Medium-Term Notes		5.99	%		2007		150
June 2003	Unsecured Medium-Term Notes		7.42	%		2004		1,500
July 2003	Unsecured Medium-Term Notes		8.05	%		2012		12,000
July 2003	Unsecured Senior Notes		9.75	%		2008		3,000
August 2003	Unsecured Senior Notes		9.75	%		2008		10,330
	Total debt repurchases						$	52,485

Short-term debt of Avista Utilities increased from $95.0 million as of December 31, 2002 to $125.0 million as of September 30, 2003. The amount outstanding as of September 30, 2003 included $85.0 million under Avista Corp.’s $245.0 million committed line of credit and $40.0 million under a $100.0 million accounts receivable financing facility as discussed under “Off-Balance Sheet Arrangements.” Amounts outstanding under the accounts receivable financing facility are accounted for as sales of accounts receivable on the Consolidated Balance Sheet.

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Avista Energy’s contractual commitments to purchase energy commodities in future periods were as follows as of September 30, 2003 (dollars in millions):

Year ended September 30,	2004		2005		2006		2007		2008		Thereafter
Physical energy contracts	$	864	$	278	$	232	$	155	$	160	$	342
Financial energy contracts		32		4		1		—		—		—

Avista Energy also has sales commitments related to energy commodities in future periods.

As of September 30, 2003, Avista Corp. did not have any commitments outstanding with equity triggers. When the Company’s corporate credit rating was reduced to below investment grade in October 2001, additional collateral requirements due to rating triggers were met and further requirements are not currently anticipated. Avista Corp. does not expect any material impact from rating triggers; remaining triggers for Avista Corp. primarily relate to changes in pricing under certain financing agreements. A reduction in the credit rating of Avista Corp. would represent an event of default under Avista Energy’s credit agreement.

Future Outlook

Business Strategy

Avista Corp. continues to implement its business strategy of focusing on fundamentals with a concentrated effort on its core energy-related businesses. Avista Corp. intends to focus on improving cash flows and earnings, controlling costs and reducing debt while working to restore an investment grade credit rating. Avista Utilities seeks to maintain a strong, low-cost and efficient electric and natural gas utility business focused on providing reliable, high quality service to its customers. The utility business is expected to grow modestly, consistent with historical trends. Expansion is expected to result primarily from economic and population growth in its service territory. It is Avista Utilities’ strategy to own or have contracts for a sufficient amount of resources to meet its retail and wholesale energy requirements under a range of operating conditions. Avista Energy operates primarily within the WECC and focuses on asset-backed optimization of combustion turbines and hydroelectric assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric and natural gas transmission and transportation arrangements. Avista Energy is also involved in the trading of electricity and natural gas, including derivative commodity instruments. Avista Energy’s marketing efforts are driven by its base of knowledge and experience in the operation of both electric energy and natural gas physical systems in the WECC, as well as its relationship-focused approach with its customers. The Company’s strategy may include the acquisition or management of generation assets that become available with partners that have capital resources. Avista Advantage remains focused on growing revenue, improving margins, reducing fixed and variable costs and continuously enhancing client satisfaction. Over time as opportunities arise, the Company plans to dispose of assets and phase out operations in the Other business segment.

Competition

Avista Utilities competes to provide service to new retail electric customers with various rural electric cooperatives and public utility districts in and adjacent to its service territories. Alternate providers of power may also compete for sales to existing customers, including new market entrants as a result of deregulation. Competition for available electric resources can be critical to utilities as surplus power resources are absorbed by load growth. Avista Utilities’ natural gas distribution operations compete with other energy sources; however, natural gas continues to maintain a price advantage compared to heating oil, propane and other fuels, provided that the natural gas distribution system is proximate to prospective customers.

The Energy Policy Act of 1992 (Energy Act) amended provisions of the Public Utility Holding Company Act of 1935 (PUHCA) and the Federal Power Act to remove certain barriers to a competitive wholesale market. The Energy Act expanded the authority of the FERC to issue orders requiring electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and to require electric utilities to enlarge or construct additional transmission capacity for the purpose of providing these services. It also created “exempt wholesale generators,” a class of independent power plant owners that are able to sell generation only at the wholesale level. This permits public utilities and other entities to participate through subsidiaries in the development of independent electric generating plants for sales to wholesale customers without being required to register under the PUHCA.

Participants in the wholesale market include other utilities, federal marketing agencies and energy trading and marketing companies. The wholesale market has changed significantly over the last few years with respect to market

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participants involved, level of activity, variability in market prices, liquidity, FERC-imposed price caps and counterparty credit issues. During 2000 and the first half of 2001, the electric wholesale market in the WECC region was more turbulent than previously experienced and marked by significant volatility, service disruptions and defaults by certain participants. During the second half of 2001 and 2002, wholesale market prices decreased to levels similar to those experienced before 2000. Wholesale market prices increased in 2003 compared to 2002; however, prices have not increased to levels experienced during 2000 and the first half of 2001. Many energy companies are facing liquidity issues, and counterparty credit exposure is of concern to market participants. During 2002 and 2003 as compared to 2000 and the first half of 2001, electric and natural gas trading volumes have decreased, the energy markets are less volatile and fewer creditworthy counterparties are currently participating in the energy markets. Avista Corp. is actively monitoring energy industry developments with a focus on liquidity, volatility of energy trading markets and counterparty credit exposure.

The Avista Capital subsidiaries, particularly Avista Advantage, are subject to competition as they develop products and services and enter new markets. Competition from other companies in these emerging industries may mean challenges for a company to be the first to market a new product or service to gain the advantage in market share. In order for these new businesses to grow as planned, one significant challenge will be the availability of funding and resources to meet the capital needs. Other challenges will be rapidly advancing technologies, possibly making some of the current technology quickly obsolete, and requiring continual research and development for product advancement. In order for some of these subsidiaries to succeed, they will need to reduce costs of these emerging technologies to make them affordable to future customers.

Pending Energy Legislation

The United States Congress is currently considering broad energy legislation which reportedly may, among other things, promote investment in critical transmission capacity and efficiency measures; expedite transmission facility siting; improve system reliability, including through improved enforcement of reliability standards and expanded open access requirements; repeal the PUHCA; grant the FERC authority to order refunds from otherwise non-jurisdictional sellers of electricity in certain markets; require the FERC to meet a public interest standard before abrogating contracts; expand the FERC’s merger authority; and stimulate investment in and use of renewable energy. The Company cannot predict whether or not any such legislation will be enacted or, if enacted the exact substance of the legislation or the effects on the Company.

Business Risk

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 recovery of power and natural gas costs, 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. See further reference to risks and uncertainties under “Safe Harbor for Forward-Looking Statements.”

Avista Utilities has mechanisms in place in each regulatory jurisdiction, which provide for the recovery of the majority of the changes in its power and natural gas costs. The majority of power and natural gas costs that exceed the amount currently recovered through retail rates are deferred on the balance sheet for the opportunity for recovery through future retail rates. These deferred power and natural gas costs are subject to review for prudence and recoverability and as such certain deferred costs may be disallowed by the respective regulatory agencies.

Hydroelectric conditions in 2001 were significantly below normal, leading to a greater than normal reliance on purchased power. Hydroelectric generation was slightly above normal in 2002 and current forecasts indicate that hydroelectric generation will be approximately 90 percent of normal in 2003. The earnings impact of these factors is mitigated by regulatory mechanisms that are intended to defer increased power supply costs for recovery in future periods. Avista Utilities is not able to predict how the combination of energy resources, energy loads, prices, rate recovery and other factors will ultimately drive deferred power costs and the timing of recovery of these costs in future periods. See further information at “Avista Utilities - Regulatory Matters.”

Challenges facing Avista Utilities’ electric operations include, among other things, the timing of the recovery of deferred power and natural gas costs, changes in the availability of and volatility in the prices of power and fuel, generating unit availability, legislative and governmental regulations, potential tax law changes, customer response to price increases and surcharges, streamflows and weather conditions.

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Natural gas commodity prices increased dramatically during 2000 and remained at relatively high levels during the first half of 2001 before declining in the second half of the year. Natural gas commodity prices during 2002 were generally lower than during 2000 and the first half of 2001. Natural gas commodity prices increased towards the end of 2002 and into the first half of 2003 before declining somewhat during the third quarter of 2003. Market prices for natural gas continue to be competitive compared to alternative fuel sources for residential, commercial and industrial customers. Avista Utilities believes that natural gas should sustain its market advantage based on the levels of existing reserves and the potential for natural gas development in the future. Growth has occurred in the natural gas business in recent years due to increased demand for natural gas in new construction, as well as conversions from electric space, oil space and electric water heating to natural gas. Challenges facing Avista Utilities’ natural gas operations include, among other things, volatility in the price of natural gas, changes in the availability of natural gas, legislative and governmental regulations, weather conditions and the timing of recovery for increased commodity costs. Avista Utilities’ natural gas business also faces the potential for certain natural gas customers to by-pass its natural gas system. To reduce the potential for such by-pass, Avista Utilities prices its natural gas services, including transportation contracts, competitively and has varying degrees of flexibility to price its transportation and delivery rates by means of individual contracts, subject to state regulatory review and approval. Avista Utilities has long-term transportation contracts with several of its largest industrial customers, which reduces the risk of these customers by-passing the system in the foreseeable future.

In addition to its asset management activities, Avista Energy trades electricity and natural gas, along with derivative commodity instruments, including futures, options, swaps and other contractual arrangements. As a result of these trading activities, Avista Energy is subject to various risks, including commodity price risk and credit risk, as well as possible new risks resulting from the imposition of market controls by federal and state agencies. The FERC is conducting proceedings and investigations related to market controls within the western United States that include proposals by certain parties to impose refunds. As a result, certain parties have asserted claims for significant refunds from Avista Energy and lesser refunds from Avista Utilities which could result in liabilities for refunding revenues recognized in prior periods. Avista Energy and Avista Utilities have joined other parties in opposing these proposals. The refund proceedings provide that any refunds owed could be offset against unpaid energy debts due to the same party. Avista Energy has fully reserved for all defaulted obligations from California parties and believes that any refunds imposed would not exceed its uncollected receivables. On June 25, 2003, the FERC denied the request of certain parties for retroactive refunds for spot market sales in the Pacific Northwest during the period from December 25, 2000 to June 20, 2001. However, the FERC has granted a request for rehearing in the Pacific Northwest refund proceedings. See “Power Market Issues” for further information with respect to the refund proceedings.

In connection with matching loads and resources, Avista Utilities engages in wholesale sales and purchases of electric capacity and energy and, accordingly, is also subject to commodity price risk, credit risk and other risks associated with these activities.

Commodity Price Risk. Both Avista Utilities and Avista Energy are subject to energy commodity price risk. The price of power in wholesale markets is affected primarily by production costs and by other factors including streamflows, the availability of hydroelectric and thermal generation and transmission capacity, weather and the resulting retail loads, and the price of coal, natural gas and oil to operate thermal generating units. Any combination of these factors that results in a shortage of energy generally causes the market price of power to move upward. The FERC imposed a price mitigation plan in the western United States in June 2001.

Price risk is, in general, the risk of fluctuation in the market price of the commodity needed, held or traded. In the case of electricity, prices can be affected by the adequacy of generating reserve margins, scheduled and unscheduled outages of generating facilities, availability of streamflows for hydroelectric generation, the price of thermal generating plant fuel, and disruptions or constraints to transmission facilities. Demand changes (caused by variations in the weather and other factors) can also affect market prices. Price risk also includes the risk of fluctuation in the market price of associated derivative commodity instruments (such as options and forward contracts). Price risk may also be influenced to the extent that the performance or non-performance by market participants of their contractual obligations and commitments affect the supply of, or demand for, the commodity. Wholesale market prices for power and natural gas in the western United States and western Canada were significantly higher in 2000 and the first half of 2001 than at any time in history, with unprecedented levels of volatility. Prices and volatility decreased considerably during the second half of 2001, 2002 and 2003 relative to 2000 and the first half of 2001.

Credit Risk. Credit risk relates to the risk of loss that Avista Utilities and/or Avista Energy would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy and make financial settlements. Credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances that relate to other market participants that have a

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direct or indirect relationship with such counterparty. Avista Utilities and Avista Energy seek to mitigate credit risk by applying specific eligibility criteria to existing and prospective counterparties and by actively monitoring current credit exposures. These policies include an evaluation of the financial condition and credit ratings of counterparties, collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees, and the use of standardized agreements that allow for the netting or offsetting of positive and negative exposures associated with a single counterparty. However, despite mitigation efforts, defaults by counterparties periodically occur. Avista Energy experienced payment receipt defaults from certain parties impacted by the California energy crisis. Both Avista Corp. and Avista Energy engaged in considerable business and had short-term and long-term contracts with entities that have filed for bankruptcy protection. These bankruptcies and other changes, uncertainties and regulatory proceedings have resulted in reduced liquidity in the energy markets.

A trend of declining credit quality was evident during 2002 and has continued into 2003, particularly throughout the energy industry. Rating agencies have downgraded the credit ratings of several of the counterparties of Avista Energy and Avista Utilities. Avista Energy and Avista Utilities regularly evaluate counterparties’ credit exposure for future settlements and delivery obligations. Avista Energy and Avista Utilities have taken a conservative position by reducing or eliminating open (unsecured) credit limits for parties perceived to have increased default risk. Counterparty collateral is used to offset the Company’s credit risk where unsettled net positions and future obligations by counterparties to pay Avista Utilities and/or Avista Energy or deliver to Avista Utilities and/or Avista Energy warrant.

Avista Energy has concentrations of suppliers and customers in the electric and natural gas industries including electric utilities, natural gas distribution companies, and other energy marketing and trading companies. In addition, Avista Energy has concentrations of credit risk related to geographic location as Avista Energy operates in the western United States and western Canada. These concentrations of counterparties and concentrations of geographic location may impact Avista Energy’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

Credit risk also involves the exposure that counterparties perceive related to performance by Avista Utilities and Avista Energy to perform deliveries and settlement of energy transactions. These counterparties may seek assurance of performance in the form of letters of credit, prepayment or cash deposits, and, in the case of Avista Energy, parent company (Avista Capital) performance guarantees. In periods of price volatility, the level of exposure can change significantly, with the result that sudden and significant demands may be made against the Company’s capital resource reserves (credit facilities and cash). Avista Utilities and Avista Energy actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements.

In conjunction with the valuation of their commodity derivative instruments and accounts receivable, Avista Utilities and Avista Energy maintain credit reserves that are based on management’s evaluation of the credit risk of the overall portfolio. Based on these policies, exposures and credit reserves, the Company does not anticipate a materially adverse effect on its financial condition or results of operations as a result of counterparty nonperformance.

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, a change in regulatory requirements, forced outages at generating plants and disruptions to information systems and other administrative tools required for normal operations. Avista Utilities also has exposure to weather conditions and natural disasters that can cause physical damage to property, requiring immediate repairs to restore utility service. The emergence of terrorism threats, both domestic and foreign, is a risk to the entire utility industry, including Avista 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 in the event that its facilities are targeted.

Interest Rate Risk. The Company is subject to the risk of fluctuating interest rates in the normal course of business. The Company manages interest rate risk by taking advantage of market conditions when timing the issuance of long-term financings and optional debt redemptions and through the use of fixed rate long-term debt with varying maturities. The interest rate on $40 million of Company-Obligated Mandatorily Redeemable Preferred Trust Securities - Series B is adjusted quarterly, reflecting current market conditions. In order to lower interest payments during a period of declining interest rates, Avista Corp. entered into an interest rate swap agreement, effective July 17, 2002, that was terminated on May 7, 2003. This interest rate swap 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 LIBOR. Additionally, amounts borrowed under the Company’s committed line of credit have a variable interest rate.

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The Company’s credit ratings were downgraded during the fourth quarter of 2001 resulting in an overall corporate credit rating that is below investment grade. These downgrades increased the cost of debt and other securities going forward and may affect the Company’s ability to issue debt and equity securities at reasonable interest rates and prices. The downgrades also required the Company to provide letters of credit and/or collateral to certain parties.

Foreign Currency Risk. The Company has investments in Canadian companies through Avista Energy Canada, Ltd. and its subsidiary, Copac Management, Inc. The Company’s exposure to foreign currency risk and other foreign operations risk was immaterial to the Company’s consolidated results of operations and financial position during the nine months ended September 30, 2003 and is not expected to change materially in the near future.

Risk Management

Risk Policies and Oversight. Avista Utilities and Avista Energy use a variety of techniques to manage risks. The Company has risk management oversight for these risks for each area of the Company’s energy-related businesses. The Company has a Risk Management Committee, separate from the units tasked with managing this risk exposure and that is overseen by the Audit Committee of the Company’s Board of Directors, to monitor compliance with the Company’s risk management policies and procedures. Avista Utilities and Avista Energy have policies and procedures in place to manage the risks, both quantitative and qualitative, inherent in their businesses. The Company’s Risk Management Committee reviews the status of risk exposures through regular reports and meetings and it monitors compliance with the Company’s risk management policies and procedures on a regular basis. Nonetheless, adverse changes in commodity prices, generating capacity, customer loads, regulation and other factors may result in losses in earnings, cash flows and/or fair values.

Quantitative Risk Measurements. Avista Utilities has volume limits for its imbalance between projected loads and resources. Normal operations result in seasonal mismatches between power loads and available resources. Avista Utilities is able to vary the operation of its generating resources to match hourly, daily and weekly load fluctuations. Avista Utilities uses the wholesale power markets to sell projected resource surpluses and obtain resources when deficits are projected. Any imbalance is required to remain within limits, or management action or decisions are triggered to address larger imbalance situations. Volume limits for forward periods are based on monthly and quarterly averages that may vary materially from the actual load and resource variations within any given month or operating day. Future projections of resources are updated as forecasted streamflows and other factors differ from prior estimates. Forward power markets may be illiquid, and market products available may not match Avista Utilities’ desired transaction size and shape. Therefore, open imbalance positions exist at any given time.

Avista Energy measures the risk in its power and natural gas portfolio daily utilizing a Value-at-Risk (VAR) model, monitoring its risk in comparison to established thresholds. VAR measures the expected portfolio loss under hypothetical adverse price movements, over a given time interval within a given confidence level. Avista Energy also measures its open positions in terms of volumes at each delivery location for each forward time period. The extent of open positions is included in the risk management policy and is measured with stress tests and VAR modeling.

The VAR computations are based on a historical simulation, utilizing price movements over a specified period to simulate forward price curves in the energy markets to estimate the potential unfavorable impact of price movement in the portfolio of transactions scheduled to settle within the following eight calendar quarters. The quantification of market risk using VAR provides a consistent measure of risk across Avista Energy’s continually changing portfolio. VAR represents an estimate of reasonably possible net losses in earnings that would be recognized on its portfolio assuming hypothetical movements in future market rates and is not necessarily indicative of actual results that may occur. Avista Energy’s VAR computations utilize several key assumptions, including a 95 percent confidence level for the resultant price movement and holding periods of one and three days. The calculation includes derivative commodity instruments held for trading purposes and excludes the effects of embedded physical options in the trading portfolio.

As of September 30, 2003, Avista Energy’s estimated potential one-day unfavorable impact on gross margin was $0.7 million, as measured by VAR, related to its commodity trading and marketing business, compared to $0.7 million as of December 31, 2002. The average daily VAR for the nine months ended September 30, 2003 was $0.7 million. The high daily VAR was $1.2 million and the low daily VAR was $0.4 million during the nine months ended September 30, 2003. Avista Energy was in compliance with its one-day VAR limits during the nine months ended September 30, 2003. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits. For forward transactions that settle beyond the next eight calendar quarters, Avista Energy applies other risk measurement techniques, including price sensitivity stress tests, to assess the future market risk. Volatility in longer-dated forward markets tends to be significantly less than near-term markets.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations: Future Outlook: Business Risk and Risk Management.”

Item 4. Controls and Procedures

The Company has disclosure controls and procedures (as defined in Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934, as amended) to ensure that material information contained in its filings with the Securities and Exchange Commission is recorded, processed, summarized and reported on a timely and accurate basis. The Company’s principal executive officer and principal financial officer have reviewed and evaluated the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on such evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at ensuring that material information is recorded, processed, summarized and reported on a timely and accurate basis in the Company’s filings with the Securities and Exchange Commission. Since such evaluation there have not been any significant changes in the Company’s internal controls, or in other factors that could significantly affect these controls.

There have been no changes in the Company’s internal control over financial reporting identified in connection with the evaluation required by Exchange Act rules 13a-15(d) and 15d-15(d) that occurred during the Company’s last fiscal quarter (the Company’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

See “Note 12 of the Notes to Consolidated Financial Statements” which is incorporated by reference.

Item 6. Exhibits and Reports on Form 8-K

(a)	Exhibits.
	Exhibits Filed:

4(f)	Thirty-Second Supplemental Indenture, dated as of September 1, 2003.
12	Computation of ratio of earnings to fixed charges and preferred dividend requirements.
31(a)	Certification of Chief Executive Officer
31(b)	Certification of Chief Financial Officer

      Exhibits Furnished:

32 Certification of Corporate Officers (Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

(b) Reports on Form 8-K.

Dated July 10, 2003 with respect to the Company’s appeal of the FERC administrative law judge’s decision to deny the request for certification of the agreement in resolution, as well as the disclosure of outside equity investment in Avista Labs.

Dated July 24, 2003 with respect to 2003 second quarter earnings as well as the FERC administrative law judge’s certification of the agreement in resolution between Avista Corp., Avista Energy and the FERC staff.

Dated August 19, 2003 to disclose a stipulation agreement in the Oregon natural gas general rate case and the filing of an amended and consolidated class action shareholder lawsuit.

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SIGNATURE

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	AVISTA CORPORATION
	(Registrant)
Date: November 10, 2003	/s/ Malyn K. Malquist
	Malyn K. Malquist Senior Vice President and Chief Financial Officer (Principal Accounting and Financial Officer)

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