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, 2005

OR

¨ 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  ¨

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

Yes  x    No  ¨

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):

Yes  ¨    No  x

As of November 1, 2005, 48,562,408 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

AVISTA CORPORATION

Index

	Page No.
Part I. Financial Information:
Item 1. Consolidated Financial Statements
Consolidated Statements of Income - Three Months Ended September 30, 2005 and 2004	3
Consolidated Statements of Income - Nine Months Ended September 30, 2005 and 2004	4
Consolidated Statements of Comprehensive Income (Loss) - Three and Nine Months Ended September 30, 2005 and 2004	5
Consolidated Balance Sheets - September 30, 2005 and December 31, 2004	6
Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2005 and 2004	8
Notes to Consolidated Financial Statements	9
Report of Independent Registered Public Accounting Firm	34
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3. Quantitative and Qualitative Disclosures About Market Risk	66
Item 4. Controls and Procedures	66
Part II. Other Information:
Item 1. Legal Proceedings	66
Item 6. Exhibits	66
Signature	67

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements, which should be read with the cautionary statements and important factors included in this Quarterly Report on Form 10-Q at “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements.” 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,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “projects,” “predicts,” and similar expressions. Such statements are subject to a variety of risks, uncertainties and other factors, most of which are beyond the control of Avista Corporation and many of which could have a significant impact on Avista Corporation’s operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

Avista Corporation

For the Three Months Ended September 30

Dollars in thousands, except per share amounts

	2005			2004
OPERATING REVENUES	$	265,679		$	241,552
OPERATING EXPENSES:
Resource costs		167,025			136,000
Operations and maintenance		35,828			39,900
Administrative and general		23,156			26,479
Depreciation and amortization		21,368			20,458
Taxes other than income taxes		14,375			14,170
Total operating expenses		261,752			237,007
GAIN ON SALE OF UTILITY PROPERTIES		884			—
INCOME FROM OPERATIONS		4,811			4,545
OTHER INCOME (EXPENSE):
Interest expense		(21,583	)		(21,481	)
Interest expense to affiliated trusts		(1,582	)		(1,314	)
Capitalized interest		392			417
Net interest expense		(22,773	)		(22,378	)
Other income - net		3,511			2,356
Total other income (expense)-net		(19,262	)		(20,022	)
LOSS BEFORE INCOME TAXES		(14,451	)		(15,477	)
INCOME TAXES		(5,414	)		(5,695	)
NET LOSS	$	(9,037	)	$	(9,782	)
Weighted-average common shares outstanding (thousands), Basic		48,538			48,416
Weighted-average common shares outstanding (thousands), Diluted		48,538			48,416
LOSS PER COMMON SHARE, BASIC AND DILUTED (Note 11):	$	(0.19	)	$	(0.20	)
Dividends paid per common share	$	0.135		$	0.130

The Accompanying Notes are an Integral Part of These Statements.

3

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

Avista Corporation

For the Nine Months Ended September 30

Dollars in thousands, except per share amounts

	2005			2004
OPERATING REVENUES	$	901,175		$	811,172
OPERATING EXPENSES:
Resource costs		520,157			434,761
Operations and maintenance		103,874			106,919
Administrative and general		72,490			76,745
Depreciation and amortization		65,462			58,770
Taxes other than income taxes		51,072			49,638
Total operating expenses		813,055			726,833
GAIN ON SALE OF UTILITY PROPERTIES		4,093			—
INCOME FROM OPERATIONS		92,213			84,339
OTHER INCOME (EXPENSE):
Interest expense		(64,723	)		(65,584	)
Interest expense to affiliated trusts		(4,548	)		(4,399	)
Capitalized interest		979			1,393
Net interest expense		(68,292	)		(68,590	)
Other income - net		7,173			6,728
Total other income (expense)-net		(61,119	)		(61,862	)
INCOME BEFORE INCOME TAXES		31,094			22,477
INCOME TAXES		11,338			9,443
NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		19,756			13,034
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (net of tax)		—			(460	)
NET INCOME	$	19,756		$	12,574
Weighted-average common shares outstanding (thousands), Basic		48,508			48,384
Weighted-average common shares outstanding (thousands), Diluted		49,046			48,899
EARNINGS PER COMMON SHARE, BASIC (Note 11):
Earnings per common share before cumulative effect of accounting change	$	0.41		$	0.27
Loss per common share from cumulative effect of accounting change		—			(0.01	)
Total earnings per common share, basic	$	0.41		$	0.26
EARNINGS PER COMMON SHARE, DILUTED (Note 11):
Earnings per common share before cumulative effect of accounting change	$	0.40		$	0.27
Loss per common share from cumulative effect of accounting change		—			(0.01	)
Total earnings per common share, diluted	$	0.40		$	0.26
Dividends paid per common share	$	0.405		$	0.385

The Accompanying Notes are an Integral Part of These Statements.

4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

Avista Corporation

Dollars in thousands

For the Three Months Ended September 30

	2005			2004
NET LOSS	$	(9,037	)	$	(9,782	)
OTHER COMPREHENSIVE INCOME (LOSS):
Foreign currency translation adjustment		414			362
Unrealized gains (losses) on interest rate swap agreements - net of taxes of $2,698 and $(1,563), respectively		5,011			(2,902	)
Unrealized gains on securities available for sale - net of taxes of $52		96			—
Unrealized gains (losses) on derivative commodity instruments - net of taxes of $(253) and $517, respectively		(470	)		961
Reclassification adjustment for realized gains on derivative commodity instruments included in net income - net of taxes of $(477) and $(81), respectively		(887	)		(150	)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		4,164			(1,729	)
COMPREHENSIVE LOSS	$	(4,873	)	$	(11,511	)
For the Nine Months Ended September 30
	2005			2004
NET INCOME	$	19,756		$	12,574
OTHER COMPREHENSIVE INCOME (LOSS):
Foreign currency translation adjustment		301			165
Unrealized losses on interest rate swap agreements - net of taxes of $(601) and $(1,481), respectively		(1,116	)		(2,750	)
Unrealized losses on securities available for sale - net of taxes of $(33)		(61	)		—
Unrealized gains (losses) on derivative commodity instruments - net of taxes of $663 and $(156), respectively		1,232			(278	)
Reclassification adjustment for realized gains on derivative commodity instruments included in net income - net of taxes of $(705) and $(49), respectively		(1,309	)		(101	)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(953	)		(2,964	)
COMPREHENSIVE INCOME	$	18,803		$	9,610

The Accompanying Notes are an Integral Part of These Statements.

5

CONSOLIDATED BALANCE SHEETS

(Unaudited)

Avista Corporation

Dollars in thousands

	September 30, 2005		December 31, 2004
ASSETS:
CURRENT ASSETS:
Cash and cash equivalents	$	62,965	$	88,317
Restricted cash		39,466		26,175
Accounts and notes receivable-less allowances of $44,447 and $44,193, respectively		334,845		308,459
Energy commodity assets		1,522,517		284,231
Current utility energy commodity derivative assets		139,794		12,557
Deposits with counterparties		26,329		30,667
Materials and supplies, fuel stock and natural gas stored		50,013		43,404
Deferred income taxes		13,094		12,288
Assets held for sale		12,970		28,479
Other current assets		86,053		68,123
Total current assets		2,288,046		902,700
NET UTILITY PROPERTY:
Utility plant in service		2,776,895		2,666,445
Construction work in progress		83,113		51,260
Total		2,860,008		2,717,705
Less: Accumulated depreciation and amortization		780,033		761,642
Total net utility property		2,079,975		1,956,063
OTHER PROPERTY AND INVESTMENTS:
Investment in exchange power-net		34,096		35,933
Non-utility properties and investments-net		77,790		78,564
Non-current energy commodity assets		583,796		254,657
Investment in affiliated trusts		13,403		13,403
Other property and investments-net		18,594		19,721
Total other property and investments		727,679		402,278
DEFERRED CHARGES:
Regulatory assets for deferred income tax		121,151		123,159
Other regulatory assets		22,061		43,428
Non-current utility energy commodity derivative assets		108,835		55,825
Power and natural gas deferrals		139,600		148,206
Unamortized debt expense		48,647		53,413
Other deferred charges		23,041		21,109
Total deferred charges		463,335		445,140
TOTAL ASSETS	$	5,559,035	$	3,706,181

The Accompanying Notes are an Integral Part of These Statements.

6

CONSOLIDATED BALANCE SHEETS (continued)

(Unaudited)

Avista Corporation

Dollars in thousands

	September 30, 2005			December 31, 2004
LIABILITIES AND STOCKHOLDERS’ EQUITY:
CURRENT LIABILITIES:
Accounts payable	$	358,757		$	325,194
Energy commodity liabilities		1,511,624			253,527
Deposits from counterparties		31,741			6,015
Current portion of long-term debt		51,516			85,432
Current portion of preferred stock-cumulative (17,500 shares outstanding)		1,750			1,750
Short-term borrowings		157,498			68,517
Interest accrued		24,074			18,632
Current regulatory liability for utility derivatives		132,034			4,486
Other current liabilities		104,347			112,845
Total current liabilities		2,373,341			876,398
LONG-TERM DEBT		844,291			901,556
LONG-TERM DEBT TO AFFILIATED TRUSTS		113,403			113,403
PREFERRED STOCK-CUMULATIVE (subject to mandatory redemption):
10,000,000 shares authorized: $6.95 Series K 262,500 and 280,000 shares outstanding ($100 stated value)		26,250			28,000
OTHER NON-CURRENT LIABILITIES AND DEFERRED CREDITS:
Non-current energy commodity liabilities		559,631			215,055
Regulatory liability for utility plant retirement costs		184,021			175,575
Non-current utility energy commodity derivative liabilities		41,212			33,490
Non-current regulatory liability for utility derivatives		67,623			22,335
Deferred income taxes		498,612			488,471
Other non-current liabilities and deferred credits		96,693			98,693
Total other non-current liabilities and deferred credits		1,447,792			1,033,619
TOTAL LIABILITIES		4,805,077			2,952,976
COMMITMENTS AND CONTINGENCIES (See Notes to Consolidated Financial Statements)
STOCKHOLDERS’ EQUITY:
Common stock, no par value; 200,000,000 shares authorized; 48,561,216 and 48,471,511 shares outstanding		630,542			629,056
Note receivable from employee stock ownership plan		—			(495	)
Capital stock expense and other paid in capital		(10,364	)		(10,677	)
Accumulated other comprehensive loss		(21,486	)		(20,533	)
Retained earnings		155,266			155,854
TOTAL STOCKHOLDERS’ EQUITY		753,958			753,205
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	5,559,035		$	3,706,181

The Accompanying Notes are an Integral Part of These Statements.

7

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Avista Corporation

For the Nine Months Ended September 30

Dollars in thousands

	2005			2004
OPERATING ACTIVITIES:
Net income	$	19,756		$	12,574
Cumulative effect of accounting change		—			460
Purchases of securities held for trading		—			(15,260	)
Sales of securities held for trading		—			34,192
Non-cash items included in net income:
Depreciation and amortization		65,462			58,770
Write-offs and impairments of assets		285			19,807
Provision for deferred income taxes		11,934			3,160
Power and natural gas cost amortizations, net of deferrals		15,753			1,369
Amortization of debt expense		5,864			6,183
Gain on sale of utility properties		(4,093	)		—
Energy commodity assets and liabilities		35,130			6,574
Other		(12,870	)		(150	)
Changes in working capital components:
Sale of customer accounts receivable under revolving agreement-net		(29,000	)		(33,000	)
Accounts and notes receivable		1,486			123,966
Materials and supplies, fuel stock and natural gas stored		(6,532	)		(8,307	)
Deposits with counterparties		4,338			17,432
Other current assets		(15,605	)		(461	)
Accounts payable		34,604			(66,473	)
Deposits from counterparties		25,726			(89,919	)
Other current liabilities		(1,350	)		(2,789	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		150,888			68,128
INVESTING ACTIVITIES:
Utility property capital expenditures (excluding AFUDC)		(148,844	)		(77,335	)
Other capital expenditures		(3,265	)		(1,914	)
Increase in restricted cash		(13,291	)		(9,376	)
Proceeds from sale of natural gas properties		16,609			—
Changes in other property and investments		(2,321	)		1,808
Repayments received on notes receivable		88			1,036
NET CASH USED IN INVESTING ACTIVITIES		(151,024	)		(85,781	)
FINANCING ACTIVITIES:
Increase in short-term borrowings		88,981			89,988
Redemption and maturity of long-term debt		(91,452	)		(66,453	)
Premiums paid for the redemption of long-term debt		(826	)		(6,710	)
Proceeds from issuance of long-term debt to affiliated trusts		—			61,856
Redemption of long-term debt to affiliated trusts		—			(61,856	)
Redemption of preferred stock		(1,750	)		(1,750	)
Cash dividends paid		(19,644	)		(18,615	)
Issuance of common stock		1,518			3,100
Distribution to minority interests		(1,688	)		—
Long-term debt and short-term borrowing issuance costs		(355	)		(3,487	)
NET CASH USED IN FINANCING ACTIVITIES		(25,216	)		(3,927	)
NET DECREASE IN CASH AND CASH EQUIVALENTS		(25,352	)		(21,580	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		88,317			128,126
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	62,965		$	106,546
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period:
Interest	$	58,257		$	58,362
Income taxes		14,865			11,677

The Accompanying Notes are an Integral Part of These Statements.

8

AVISTA CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

The accompanying consolidated financial statements of Avista Corporation (Avista Corp. or the Company) for the interim periods ended September 30, 2005 and 2004 are unaudited; however, in the opinion of management, the statements 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 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, 2004 (2004 Form 10-K). Please refer to the section “Acronyms and Terms” in the 2004 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 is an operating division of Avista Corp., comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity in parts of eastern Washington and northern Idaho. In addition, Avista Utilities has electric generating facilities in western Montana and northern Oregon. Avista Utilities also provides natural gas distribution service in parts of eastern Washington, northern Idaho, as well as northeast and southwest Oregon. In April 2005, the Company completed the sale of its South Lake Tahoe, California natural gas distribution properties (see Note 13 for further information). This was the Company’s only regulated utility operation in California. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility business segments. See Note 14 for business segment information.

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 and capital investments, streamflow and weather conditions, the effects of changes in legislative and governmental regulations, changes in regulatory requirements, availability of generation facilities, competition, technology and availability of funding. Also, like other utilities, the Company’s facilities and operations may be exposed to terrorism risks or other malicious acts. In addition, the energy business exposes the Company to the financial, liquidity, credit and price risks associated with wholesale purchases and sales of energy commodities.

Basis of Reporting

The consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries, including variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. All significant intercompany balances have been eliminated in consolidation. 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. Significant estimates include determining the market value of energy commodity assets and liabilities, pension and other postretirement benefit plan obligations, contingent liabilities, recoverability of regulatory assets and unbilled revenues. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein.

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 calendar 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.

9

AVISTA CORPORATION

Avista Energy Operating Revenues

Avista Energy follows Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149, with respect to the majority of its contracts. Avista Energy reports the net margin on derivative commodity instruments held for trading as operating revenues. Revenues from contracts that are not derivatives under SFAS No. 133, as well as derivative commodity instruments not held for trading, are reported on a gross basis in operating revenues. Revenues from Canadian contracts through Avista Energy Canada, which are not held for trading, and are reported on a gross basis in operating revenues, totaled $27.9 million and $21.9 million for the three months ended September 30, 2005 and 2004, respectively. Revenues from Canadian contracts through Avista Energy Canada totaled $94.1 million and $82.3 million for the nine months ended September 30, 2005 and 2004, respectively.

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,
	2005			2004			2005			2004
Interest income	$	2,255		$	736		$	4,261		$	2,939
Interest on power and natural gas deferrals		1,786			1,973			5,567			5,917
Net gain on disposition of non-operating assets		—			7			13			379
Net gain (loss) on investments		55			354			(285	)		141
Other expense		(1,683	)		(1,434	)		(4,613	)		(4,418	)
Other income		1,098			720			2,230			1,770
Total	$	3,511		$	2,356		$	7,173		$	6,728

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. However, the Company has recognized compensation expense related to the initial grant (2003) of performance-based share awards. See Note 2 with respect to the revision of SFAS No. 123, which will result in changes to stock compensation recognition beginning in 2006.

If compensation expense for the Company’s stock-based employee compensation plans were determined consistent with SFAS No. 123, net income (loss) and earnings (loss) 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,
	2005			2004			2005			2004
Net income (loss) (dollars in thousands):
As reported	$	(9,037	)	$	(9,782	)	$	19,756		$	12,574
Add: Total stock-based employee compensation expense included in net income, net of tax		463			—			1,723			—
Deduct: Total stock-based employee compensation expense determined under the fair value method for all awards, net of tax		(714	)		(409	)		(2,475	)		(1,523	)
Pro forma	$	(9,288	)	$	(10,191	)	$	19,004		$	11,051
Basic and diluted earnings (loss) per common share:
Basic as reported	$	(0.19	)	$	(0.20	)	$	0.41		$	0.26
Diluted as reported	$	(0.19	)	$	(0.20	)	$	0.40		$	0.26
Basic and diluted pro forma	$	(0.19	)	$	(0.21	)	$	0.39		$	0.23

Comprehensive Income (Loss)

The Company’s comprehensive income (loss), which is reported net of tax, is comprised of net income, foreign currency translation adjustments, changes in the unfunded accumulated benefit obligation for the pension plan, unrealized gains and losses on interest rate swap agreements, unrealized gains and losses on securities available for sale, and unrealized gains and losses on derivative commodity instruments.

10

AVISTA CORPORATION

Accumulated other comprehensive income (loss), net of tax, consisted of the following as of September 30, 2005 and December 31, 2004 (dollars in thousands):

	September 30, 2005			December 31, 2004
Foreign currency translation adjustment	$	1,440		$	1,139
Unfunded accumulated benefit obligation for the pension plan		(16,944	)		(16,944	)
Unrealized loss on interest rate swap agreements		(5,936	)		(4,820	)
Unrealized loss on securities available for sale		(61	)		—
Unrealized gain on derivative commodity instruments		15			92
Total accumulated other comprehensive loss	$	(21,486	)	$	(20,533	)

Restricted Cash

Restricted cash includes bank deposits of $31.1 million and $21.5 million as collateral for letters of credit issued under Avista Energy’s credit agreement as of September 30, 2005 and December 31, 2004, respectively. See Note 9 for further information with respect to Avista Energy’s credit agreement. Restricted cash also includes deposits held in trust of $1.1 million and $1.6 million for certain employees of Avista Energy as part of a bonus retention plan as of September 30, 2005 and December 31, 2004, respectively. Restricted cash as of September 30, 2005 and December 31, 2004, includes $2.5 million of deposits related to forward contracts at Avista Energy. In addition, restricted cash includes $4.8 million and $0.6 million of deposits related to Avista Corp.’s interest rate swap agreements as of September 30, 2005 and December 31, 2004, respectively. See Note 10 for further information with respect to Avista Corp.’s interest rate swap agreements.

Assets Held for Sale

Assets held for sale are recorded at the lower of cost or estimated fair value less selling costs. As of September 30, 2005 assets held for sale included $13.0 million of turbines and related equipment. As of December 31, 2004 assets held for sale included $15.2 million of assets related to Avista Utilities’ South Lake Tahoe natural gas distribution properties and $13.3 million of turbines and related equipment. Liabilities held for sale were not significant as of September 30, 2005 and December 31, 2004.

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 using a discounted cash flow model on at least an annual basis or more frequently if impairment indicators arise. Goodwill is included in non-utility properties and investments-net on the Consolidated Balance Sheets and totaled $6.2 million ($5.2 million in the Other business segment and $1.0 million in Energy Marketing and Resource Management) as of September 30, 2005 and December 31, 2004.

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 or credits on the Consolidated Balance Sheets. 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 are incurred, even if the Company expected to recover such costs in the future.

The Company’s primary regulatory assets include power and natural gas deferrals (see “Power Cost Deferrals and Recovery Mechanisms” and “Natural Gas Cost Deferrals and Recovery Mechanisms” below for further information), investment in exchange power, regulatory asset for deferred income taxes, unamortized debt expense, regulatory asset for consolidation of variable interest entity, 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.

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Other regulatory assets consisted of the following as of September 30, 2005 and December 31, 2004 (dollars in thousands):

	September 30, 2005		December 31, 2004
Regulatory asset for consolidation of variable interest entity	$	—	$	19,167
Regulatory asset for postretirement benefit obligation		3,427		3,782
Demand side management and conservation programs		12,052		13,792
Other		6,582		6,687
Total	$	22,061	$	43,428

Regulatory liabilities include utility plant retirement costs. Deferred credits include, among other items, regulatory liabilities created when the Centralia Power Plant was sold, regulatory liabilities offsetting net energy commodity derivative assets (see Note 4 for further information) and the gain on the general office building sale/leaseback, which is being amortized over the life of the lease. Those items without a specific line on the Consolidated Balance Sheets are included in other current liabilities and 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 Utility Commission (OPUC) approved Avista Utilities’ Natural Gas Benchmark Mechanism in 1999. The mechanism eliminated the majority of natural gas procurement operations within Avista Utilities and placed responsibility for natural gas procurement operations with Avista Energy, the Company’s non-regulated subsidiary. The ownership of the natural gas assets remained with Avista Utilities; however, the assets were managed by Avista Energy through an Agency Agreement. Avista Utilities always managed natural gas procurement for its California operations, which the Company sold in April 2005 (see Note 13).

Effective April 1, 2005, the Natural Gas Benchmark Mechanism and related Agency Agreement were terminated and the management of natural gas procurement functions was moved from Avista Energy back to Avista Utilities. This was required for Washington customers by WUTC orders issued in February 2004, and Avista Utilities’ resulting transition plan approved by the WUTC in April 2004. The Company also elected to move these functions back to Avista Utilities for Idaho and Oregon natural gas customers.

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 Avista Utilities expects to recover the costs of natural gas purchases to serve retail customers and for fuel for electric generation through future retail rates.

Power Cost Deferrals and Recovery Mechanisms

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 Consolidated Balance Sheets 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 8.1 percent as of September 30, 2005. Total deferred power costs for Washington customers were $97.7 million and $113.2 million as of September 30, 2005 and December 31, 2004, respectively.

In Washington, the Energy Recovery Mechanism (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 makes an annual filing to provide the opportunity for the WUTC and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior

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calendar year. The ERM provides 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 annual filing with the WUTC on March 30, 2005 related to $10.8 million of deferred power costs incurred for 2004. On June 29, 2005, the WUTC issued an order, which approved the recovery of the $10.8 million of deferred power costs incurred for 2004.

Avista Utilities has a power cost adjustment (PCA) mechanism in Idaho that allows it to modify electric rates periodically with IPUC approval. Under the PCA mechanism, Avista Utilities defers 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. 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, 2005. Total deferred power costs for Idaho customers were $7.7 million and $9.5 million as of September 30, 2005 and December 31, 2004, 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 $34.2 million and $28.6 million as of September 30, 2005 and December 31, 2004, respectively.

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 stockholders’ equity. In particular, the net change in restricted cash for the nine months ended September 30, 2004 was reclassified from operating activities to investing activities in the Consolidated Statements of Cash Flows to conform to the Company’s 2005 presentation. This resulted in a $9.4 million increase to operating cash flows and a corresponding decrease to investing cash flows from the amounts previously reported for the nine months ended September 30, 2004.

NOTE 2. NEW ACCOUNTING STANDARDS

In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, “Consolidation of Variable Interest Entities,” which was revised in December 2003 (collectively referred to as FIN 46). 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, FIN 46 applies to a broader group of entities. FIN 46 requires a variable interest entity to be consolidated by the primary beneficiary of that entity. The primary beneficiary is subject to a majority of the risk of loss from the variable interest entity’s activities or it is entitled to receive a majority of the entity’s residual returns. FIN 46 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 FIN 46 applied immediately to variable interest entities created after January 31, 2003 and applied to certain existing variable interest entities for the first fiscal year or interim period ending after December 15, 2003. Application for all other types of entities was required for periods ending after March 15, 2004.

Please refer to the 2004 Form 10-K for the effects of the application of FIN 46 prior to the first quarter of 2004, which resulted in the consolidation of WP Funding, Limited Partnership (WP Funding LP) and the deconsolidation of capital trusts. The implementation of FIN 46, as revised in December 2003, resulted in the Company including a partnership as well as several low-income housing project investments held in the Other business segment in its consolidated financial statements beginning in the first quarter of 2004. This resulted in a charge of $0.5 million recorded as a cumulative effect of accounting change for the nine months ended September 30, 2004.

In December 2004, the FASB issued SFAS No. 123R, “Accounting for Stock-Based Compensation,” which supersedes APB No. 25 and its related implementation guidance. This statement establishes revised standards for the accounting for transactions in which the Company exchanges its equity instruments for goods or services with a primary focus on transactions in which the Company obtains employee services in share-based payment transactions. The statement requires that the compensation cost relating to share-based payment transactions be recognized in financial statements based on the fair value of the equity or liability instruments issued. In April 2005, the Securities and Exchange Commission issued a rule, which delays the Company’s implementation of the provisions of this statement from the third quarter of 2005 to the first quarter of 2006. The Company expects to record compensation

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expense (net of tax) of approximately $0.4 million in 2006 related to the periodic vesting of stock options granted to employees prior to 2005. The Company is evaluating the effect this statement may have on the valuation and expense of certain other forms of stock-based compensation (including performance share awards) that have been and may be granted to employees.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” This interpretation clarifies that the term “conditional asset retirement obligation” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the Company. The Company will be required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. This interpretation also clarifies when the Company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The Company will be required to adopt this interpretation by the end of 2005. The Company is evaluating the impact this statement will have on its financial condition and results of operations.

NOTE 3. ACCOUNTS RECEIVABLE SALE

Avista Receivables Corporation (ARC) is a wholly owned, bankruptcy-remote subsidiary of Avista Corp. formed for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On March 22, 2005, Avista Corp., ARC and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment was to extend the termination date from May 29, 2005 to March 21, 2006. Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 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 Avista Corp. As of September 30, 2005 and December 31, 2004, $43.0 million and $72.0 million in accounts receivables were sold, respectively, under this revolving agreement.

NOTE 4. UTILITY ENERGY COMMODITY DERIVATIVE ASSETS AND LIABILITIES

SFAS No. 133, as amended by SFAS No. 138 and SFAS No. 149, 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 derivative commodity assets and liabilities for over-the-counter and exchange-traded derivative instruments as well as certain long-term contracts. These contracts are entered into as part of Avista Utilities’ management of its loads and resources as discussed in Note 5. In conjunction with the issuance of 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 orders provide for Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates 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 elected the normal purchases and sales exception for substantially all of its contracts for both capacity and energy under SFAS No. 133. As such, Avista Utilities was not required to record these contracts as derivative commodity assets and liabilities. Under SFAS No. 149, substantially all new forward contracts to purchase or sell power and natural gas used for generation, which were entered into on or after July 1, 2003, are recorded as assets or liabilities at market value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives under SFAS No. 133 are generally accounted for at cost until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other than temporary.

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Utility energy commodity derivatives consisted of the following as of September 30, 2005 and December 31, 2004 (dollars in thousands):

	September 30, 2005		December 31, 2004
Current utility energy commodity derivative asset	$	139,794	$	12,557
Current utility energy commodity derivative liability		7,760		8,071
Net current regulatory liability		132,034		4,486
Non-current utility energy commodity derivative asset		108,835		55,825
Non-current utility energy commodity derivative liability		41,212		33,490
Net non-current regulatory liability		67,623		22,335

Current utility energy commodity derivative liabilities are included in other current liabilities on the Consolidated Balance Sheets.

NOTE 5. ENERGY COMMODITY TRADING

The Company’s energy-related businesses are exposed to risks relating to, but not limited to, changes in certain commodity prices, interest rates, foreign currency and counterparty performance. Avista Utilities utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these exposures, and Avista Energy engages in the trading of such instruments. Avista Utilities and Avista Energy use a variety of techniques to manage risks for their energy resources and wholesale energy market activities. The Company has risk management policies and procedures to manage these risks, both qualitative and quantitative, for Avista Utilities and Avista Energy. The Company’s Risk Management Committee establishes the Company’s risk management policies and procedures and monitors compliance. The Risk Management Committee is comprised of certain Company officers and other individuals and is overseen by the Audit Committee of the Company’s Board of Directors.

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 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 electric 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 entering into financial and physical hedging transactions as a means of managing risks.

As part of its resource optimization process described above, Avista Utilities manages the impact of fluctuations in electric energy prices by measuring and controlling the volume of energy imbalance between projected loads and resources and through the use of derivative commodity instruments for hedging purposes. Load/resource imbalances within a rolling 18-month planning horizon are compared against established volumetric guidelines and management determines the timing and specific actions to manage the imbalances. Management also assesses available resource decisions and actions that are appropriate for longer-term planning periods. Avista Energy was 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. Effective April 1, 2005, the management of natural gas procurement functions was moved from Avista Energy back to Avista Utilities. This was required for Washington customers by WUTC orders issued in February 2004, and Avista Utilities’ resulting transition plan approved by the WUTC in April 2004. The Company also elected to move these functions back to Avista Utilities for Idaho and Oregon natural gas customers. As part of the transition plan, Avista Utilities began procuring natural gas for load service during the second half of 2004 and the first quarter of 2005. This procurement process includes entering into financial and physical hedging transactions as a means of managing risks. Avista Utilities always managed natural gas procurement for its California operations, which the Company sold in April 2005 (see Note 13).

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Avista Energy

Avista Energy is an electricity and natural gas marketing, trading and resource management business. Avista Energy focuses on optimization of generation assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric transmission and natural gas transportation arrangements. Avista Energy is also involved in trading electricity and natural gas, including derivative commodity instruments. 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 exchanges and brokers, 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 positions are actively managed with policies designed to limit the exposure to market risk and requiring 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, which monitors 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 permissible 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 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 Consolidated Statements of Income in the period of change. Market prices are utilized in determining the value of electric, natural gas and related derivative commodity instruments, which are reported as assets and liabilities on the Consolidated Balance Sheets. These market prices are used through 36 months. 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 held for trading as operating revenues. Revenues from contracts that are not derivatives under SFAS No. 133, as well as derivative commodity instruments not held for trading, are reported on a gross basis in operating revenues. Costs from contracts, which are not derivatives under SFAS No. 133 and derivative instruments not held for trading, 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 has implemented hedge accounting in accordance with SFAS No. 133. 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 a 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 changes in the fair value of the designated derivative that are effective are recorded in accumulated other comprehensive income or loss, while changes in fair value that are not effective are recognized currently in earnings as operating revenues. Amounts recorded in

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accumulated other comprehensive income or loss are recognized in earnings during the period that the hedged items are recognized in earnings. The following table presents activity related to Avista Energy’s hedge accounting during the three and nine months ended September 30 (dollars in thousands):

	Three months ended September 30,					Nine months ended September 30,
	2005		2004			2005		2004
Gain (loss) related to hedge ineffectiveness recorded in operating revenues	$	5,808	$	(302	)	$	6,534	$	635
Gain reclassified from accumulated other comprehensive income (loss) and recognized in earnings (pre-tax)		1,364		231			2,014		155

The following table presents the net gain (loss), net of tax, related to Avista Energy’s cash flow hedges as of September 30, 2005 and December 31, 2004 (dollars in thousands):

	September 30, 2005			December 31, 2004
Accumulated other comprehensive income related to natural gas derivatives	$	20,455		$	1,556
Accumulated other comprehensive loss related to electric derivatives		(20,440	)		(1,464	)
Total accumulated other comprehensive income	$	15		$	92

Avista Energy expects to recognize a loss of $0.3 million in earnings during the next 12 months, related to amounts currently in accumulated other comprehensive income. 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 12 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, (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, (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 instruments outstanding as of September 30, 2005 are set forth below (in thousands of MWhs and mmBTUs):

	Fixed Price Payor	Fixed Price Receiver	Maximum Terms in Years	Index Price Payor	Index Price Receiver	Maximum Terms in Years
Energy commodities (volumes)
Electric	29,606	32,149	12	2,313	2,309	3
Natural gas	276,227	263,658	4	1,685,310	1,695,163	2

The weighted average term of Avista Energy’s electric derivative commodity instruments as of September 30, 2005 was approximately 6 months. The weighted average term of Avista Energy’s natural gas derivative commodity instruments as of September 30, 2005 was approximately 3 months.

Estimated Fair Value The estimated fair value of Avista Energy’s derivative commodity instruments outstanding as of September 30, 2005, and the average estimated fair value of those instruments held during the nine months ended September 30, 2005, are set forth below (dollars in thousands):

	Estimated Fair Value as of September 30, 2005								Average Estimated Fair Value for the nine months ended September 30, 2005
	Current Assets		Long-term Assets		Current Liabilities		Long-term Liabilities		Current Assets		Long-term Assets		Current Liabilities		Long-term Liabilities
Electric	$	530,740	$	508,533	$	548,363	$	501,830	$	277,617	$	335,128	$	261,271	$	313,037
Natural gas		991,777		75,263		963,261		57,801		296,515		34,432		287,014		27,967
Total	$	1,522,517	$	583,796	$	1,511,624	$	559,631	$	574,132	$	369,560	$	548,285	$	341,004

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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, 2005 was an unrealized loss of $35.1 million and is included in the Consolidated Statements of Income in operating revenues. The change in the fair value position for the nine months ended September 30, 2004 was an unrealized loss of $6.6 million.

NOTE 6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

The Company has a defined benefit pension plan covering substantially all of its regular full-time employees at Avista Utilities and Avista Energy. Individual benefits under this plan are based upon the employee’s years of service and average compensation as specified in the plan. The Company’s funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. The Company made $15 million in cash contributions to the pension plan in 2004. The Company has contributed $15 million to the pension plan in 2005.

The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services.

The Company uses a December 31 measurement date for its pension and postretirement plans. The following table sets forth the components of net periodic benefit costs for the three and nine months ended September 30 (dollars in thousands):

	Pension Benefits						Post- retirement Benefits
	2005			2004			2005			2004
Three months ended September 30:
Service cost	$	2,325		$	2,431		$	115		$	115
Interest cost		4,046			4,041			414			390
Expected return on plan assets		(4,000	)		(3,293	)		(342	)		(253	)
Transition (asset)/obligation recognition		(272	)		(268	)		126			3
Amortization of prior service cost		164			227			—			—
Net loss recognition		1,078			587			(71	)		297
Net periodic benefit cost	$	3,341		$	3,725		$	242		$	552
Nine months ended September 30:
Service cost	$	6,975		$	6,481		$	379		$	365
Interest cost		12,138			12,365			1,439			1,630
Expected return on plan assets		(12,000	)		(10,143	)		(980	)		(853	)
Transition (asset)/obligation recognition		(816	)		(818	)		378			503
Amortization of prior service cost		492			427			—			—
Net loss recognition		3,243			2,863			226			707
Net periodic benefit cost	$	10,032		$	11,175		$	1,442		$	2,352

NOTE 7. ACCOUNTING FOR INCOME TAXES

In August 2005, the Internal Revenue Service (IRS) and Treasury Department issued a revenue ruling, and proposed temporary regulations that may potentially impact the tax treatment by Avista Corp. of certain indirect overhead expenses. Avista Corp. had previously made a tax election in 2002 to deduct overhead costs on the tax return that were capitalized for financial accounting purposes. This election allowed Avista Corp. to accelerate tax deductions resulting in a reduction of approximately $40 million in current tax liabilities. This current tax benefit was deferred on the balance sheet in accordance with provisions of SFAS No. 109, “Accounting for Income Taxes” and did not have any effect on net income.

It is not yet clear whether the IRS revenue ruling will result in retroactively overturning any of the original tax deduction. Should the original tax deduction be overturned, the resulting $40 million current tax liability would become payable, with a corresponding reversal of the associated tax deferral for financial accounting purposes. The amount would be paid to the IRS over a two-year period (in 2006 and 2007) and would not have any direct impact on the Company’s results of operations.

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NOTE 8. LONG-TERM DEBT

The following details the interest rate and maturity dates of long-term debt outstanding as of September 30, 2005 and December 31, 2004 (dollars in thousands):

Maturity Year	Description	Interest Rate	September 30, 2005			December 31, 2004
2005	Secured Medium-Term Notes	6.39%-6.68%	$	20,000		$	29,500
2005	WP Funding LP Note	8.38%		—			54,572
2006	Secured Medium-Term Notes	7.89%-7.90%		30,000			30,000
2007	First Mortgage Bonds	7.75%		150,000			150,000
2007	Secured Medium-Term Notes	5.99%		13,850			13,850
2008	Secured Medium-Term Notes	6.06%-6.95%		45,000			45,000
2010	Secured Medium-Term Notes	6.67%-8.02%		35,000			35,000
2012	Secured Medium-Term Notes	7.37%		7,000			7,000
2013	First Mortgage Bonds	6.13%		45,000			45,000
2018	Secured Medium-Term Notes	7.26%-7.45%		22,500			27,500
2019	First Mortgage Bonds	5.45%		90,000			90,000
2023	Secured Medium-Term Notes	7.18%-7.54%		13,500			24,500
2028	Secured Medium-Term Notes	6.37%		25,000			25,000
2032	Pollution Control Bonds	5.00%		66,700			66,700
2034	Pollution Control Bonds	5.13%		17,000			17,000
	Total secured long-term debt			580,550			660,622
2006	Unsecured Medium-Term Notes	8.14%		8,000			8,000
2007	Unsecured Medium-Term Notes	7.90%-7.94%		12,000			12,000
2008	Unsecured Senior Notes	9.75%		280,613			280,827
2022	Unsecured Medium-Term Notes	8.15%		—			5,000
2023	Unsecured Medium-Term Notes	7.99%		—			5,000
2023	Pollution Control Bonds	6.00%		4,100			4,100
	Total unsecured long-term debt			304,713			314,927
	Other long-term debt and capital leases			11,882			13,047
	Unamortized debt discount			(1,338	)		(1,608	)
	Total			895,807			986,988
	Current portion of long-term debt			(51,516	)		(85,432	)
	Total long-term debt		$	844,291		$	901,556

In January and February 2005, the Company redeemed the following debt securities: $5.0 million of Secured Medium-Term Notes scheduled to mature in 2018; $11.0 million of Secured Medium-Term Notes scheduled to mature in 2023; $5.0 million Unsecured Medium-Term Notes scheduled to mature in 2022; and $5.0 million of Unsecured Medium-Term Notes scheduled to mature in 2023. In accordance with regulatory accounting practices, the total net premium on the redemption of debt of $0.8 million will be amortized over the average remaining maturity of outstanding debt.

In September 2005, Avista Corp. terminated (by exercise of a purchase option) the lease agreement with, and acquired the natural gas-fired combustion turbine generating facility in Rathdrum, Idaho (Rathdrum CT) from, WP Funding LP. As a result of this transaction, the $54.6 million WP Funding LP Note has been redeemed.

NOTE 9. SHORT-TERM BORROWINGS

On December 17, 2004, the Company entered into a five-year committed line of credit with various banks in the amount of $350.0 million with an expiration date of December 16, 2009. This committed line of credit replaced a $350.0 million committed line of credit with a 364-day term that had an expiration date of May 5, 2005. As of September 30, 2005 and December 31, 2004, the Company had $157.0 million and $68.0 million, respectively, of borrowings outstanding under this committed line of credit. The Company can request the issuance of up to $150.0 million in letters of credit under the committed line of credit. As of September 30, 2005 and December 31, 2004, there were $21.3 million and $32.8 million in letters of credit outstanding, respectively. The committed line of credit is secured by $350.0 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.

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The committed line of credit agreement contains customary covenants and default provisions, including covenants not to permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 70 percent at the end of any fiscal quarter. As of September 30, 2005, the Company was in compliance with this covenant with a ratio of 59.9 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, 2005 to be greater than 1.6 to 1. As of September 30, 2005, the Company was in compliance with this covenant with a ratio of 2.49 to 1.

On July 13, 2005, Avista Energy and its subsidiary, Avista Energy Canada, as co-borrowers, amended its committed credit agreement with a group of banks to increase the aggregate amount from $110.0 million to $145.0 million and to extend the expiration date to July 12, 2007. This committed credit facility provides for the issuance of letters of credit to secure contractual obligations to counterparties and for cash advances. This facility is secured by the assets of Avista Energy and Avista Energy Canada and guaranteed by Avista Capital and by CoPac Management, Inc., a wholly owned subsidiary of Avista Energy Canada. 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 amendment to the credit agreement increased the maximum amount for cash advances from $30.0 million to $50.0 million. No cash advances were outstanding as of September 30, 2005 and December 31, 2004. Letters of credit in the aggregate amount of $106.3 million and $91.3 million were outstanding as of September 30, 2005 and December 31, 2004, respectively. The cash deposits of Avista Energy at the respective banks collateralized $31.1 million and $21.5 million of these letters of credit as of September 30, 2005 and December 31, 2004, respectively, which is reflected as restricted cash on the Consolidated Balance Sheets.

The Avista Energy credit agreement continues to contain 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 that the co-borrowers may incur. The credit agreement also continues to contain covenants and other restrictions related to the co-borrowers’ 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. These covenants, certain counterparty agreements and current market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively limit 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, 2005. Prior to the July 13, 2005 amendment, a reduction in the credit rating of Avista Corp. would have represented an event of default under Avista Energy’s credit agreement. The July 13, 2005 amendment to the credit agreement removed this covenant.

NOTE 10. INTEREST RATE SWAP AGREEMENTS

In 2004, Avista Corp. entered into three forward-starting interest rate swap agreements, totaling $200.0 million, to manage the risk that changes in interest rates may affect the amount of future interest payments. These interest rate swap agreements relate to the anticipated issuances of debt to fund debt that matures in 2007 and 2008. Under the terms of these agreements, the value of the interest rate swaps are determined based upon Avista Corp. paying a fixed rate and receiving a variable rate based on LIBOR for a term of seven years beginning in 2007 and a term of ten years beginning in 2008. The interest rate swap agreements entered in 2004 provide for mandatory cash settlement of these contracts in 2008 and 2009. In June 2005, Avista Corp. entered into a forward-starting interest rate swap agreement in the amount of $50.0 million related to the anticipated issuance of debt to fund debt that matures during the second half of 2005. The value of the interest rate swap is determined based upon Avista Corp. paying a fixed rate and receiving a variable rate based on LIBOR for a term of thirty years beginning in December 2005. The interest rate swap agreement provides for mandatory cash settlement of the contract in 2006.

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. As of September 30, 2005, Avista Corp. had a long-term derivative liability of $11.1 million and a current derivative asset of $2.3 million. An unrealized loss of $1.5 million (net of taxes of $0.8 million) was recorded in other comprehensive loss for the nine months ended September 30, 2005. As of September 30, 2005, there was an unrealized loss of $5.7 million recorded as accumulated other comprehensive loss on the Consolidated Balance Sheets. The Company may request regulatory accounting orders to defer the impact of unrealized gains and losses. If such accounting orders were obtained, the Company would record a regulatory asset or liability, which would eliminate the effect of any unrealized gains and losses on these interest rate swap agreements in the Consolidated Statements of Comprehensive Income. If regulatory accounting orders are not obtained prior to the mandatory cash settlements, the amount included in accumulated other comprehensive income or loss at the cash settlement date will be reclassified to unamortized debt expense in accordance with

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regulatory accounting practices under SFAS No. 71. This gain or loss will be amortized over the remaining life of the forecasted debt issued.

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). Avista Power’s investment in RP LLC, which is included in non-utility properties and investments-net on the Consolidated Balance Sheets, is accounted for under the equity method and totaled $18.2 million as of September 30, 2005. As of September 30, 2005, RP LLC had $113.5 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. As of September 30, 2005, there was an unrealized loss of $0.2 million recorded as accumulated other comprehensive loss on the Consolidated Balance Sheets.

NOTE 11. EARNINGS (LOSS) PER COMMON SHARE

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005		2004
Numerator:
Net income (loss) before cumulative effect of accounting change	$	(9,037	)	$	(9,782	)	$	19,756	$	13,034
Cumulative effect of accounting change		—			—			—		(460	)
Net income (loss)	$	(9,037	)	$	(9,782	)	$	19,756	$	12,574
Denominator:
Weighted-average number of common shares outstanding-basic		48,538			48,416			48,508		48,384
Effect of dilutive securities:
Contingent stock awards *		—			—			285		234
Stock options *		—			—			253		281
Weighted-average number of common shares outstanding-diluted		48,538			48,416			49,046		48,899
Earnings (loss) per common share, basic:
Earnings (loss) per common share before cumulative effect of accounting change	$	(0.19	)	$	(0.20	)	$	0.41	$	0.27
Loss per common share from cumulative effect of accounting change		—			—			—		(0.01	)
Total earnings (loss) per common share, basic	$	(0.19	)	$	(0.20	)	$	0.41	$	0.26
Earnings (loss) per common share, diluted:
Earnings (loss) per common share before cumulative effect of accounting change	$	(0.19	)	$	(0.20	)	$	0.40	$	0.27
Loss per common share from cumulative effect of accounting change		—			—			—		(0.01	)
Total earnings (loss) per common share, diluted	$	(0.19	)	$	(0.20	)	$	0.40	$	0.26

* Due to the net loss for the three months ended September 30, 2005 and 2004, the common stock equivalents from outstanding contingent stock awards 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. If such shares were included in the calculation, the total weighted average number of common shares outstanding would be increased by 574,000 and 519,000 for the three months ended September 30, 2005 and 2004, respectively.

Total stock options outstanding that were not included in the calculation of diluted earnings per common share were 693,900 for the nine months ended September 30, 2005. Total stock options outstanding that were not included in the calculation of diluted earnings per common share were 737,300 for the nine months ended September 30, 2004. These stock options were excluded from the calculation because they were antidilutive based on the fact that the exercise price of the stock options was higher than the average market price of Avista Corp. common stock during each quarter.

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NOTE 12. COMMITMENTS AND CONTINGENCIES

In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. With respect to these proceedings, the Company intends to vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. In addition to issues specifically identified in this Note and with respect to matters that affect the regulated utility operations, the Company intends to seek, to the extent appropriate, regulatory approval of recovery of incurred costs through the ratemaking process.

Federal Energy Regulatory Commission Inquiry

On April 19, 2004, the Federal Energy Regulatory Commission (FERC) issued an order approving the contested Agreement in Resolution of Section 206 Proceeding (Agreement in Resolution) reached by Avista Corp. doing business as Avista Utilities, Avista Energy and the FERC’s Trial Staff with respect to an investigation into the activities of Avista Utilities and Avista Energy in western energy markets during 2000 and 2001. In the Agreement in Resolution, the FERC Trial Staff stated that its investigation found: (1) no evidence that any executives or employees of Avista Utilities or Avista Energy knowingly engaged in or facilitated any improper trading strategy; (2) no evidence that Avista Utilities or Avista Energy engaged in any efforts to manipulate the western energy markets during 2000 and 2001; and (3) that Avista Utilities and Avista Energy did not withhold relevant information from the FERC’s inquiry into the western energy markets for 2000 and 2001. As part of the Agreement in Resolution, Avista Utilities agreed to continue to record conversations of energy traders for two years and to improve its account settlement process. Avista Utilities and Avista Energy agreed to maintain an annual training program on the applicable FERC Code of Conduct for all employees engaged in the trading of electric energy and capacity. The Agreement in Resolution imposes no monetary remedies or penalties against Avista Utilities or Avista Energy. On May 19, 2004, the City of 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 requests for rehearing with respect to the FERC’s April 19, 2004 order. On September 28, 2004, the State of Montana filed a motion to intervene in these proceedings. On April 19, 2005, the FERC denied the rehearing requests of the City of Tacoma and California Parties, and denied the State of Montana’s motion to intervene. On April 28, 2005 and June 14, 2005, the California Parties and the City of Tacoma, respectively, filed appeals with the United States Court of Appeals for the Ninth Circuit in response to the FERC’s denial of rehearing requests. Based on the FERC’s order approving the Agreement in Resolution and the FERC’s denial of rehearing requests and motion to intervene, the Company does not expect that this proceeding will have any material adverse effect on its financial condition, results of operations or cash flows.

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. In October and November 2002, Gail West, Michael Atlas and Peter Arnone filed similar class action lawsuits in the same court against the same parties. On February 3, 2003, the court issued an order consolidating the complaints under the name “In re Avista Corp. Securities Litigation,” and on February 7, 2003 appointed the lead plaintiff and co-lead counsel. On August 19, 2003, the plaintiffs filed their consolidated amended class action complaint in the same court against the same parties. In their complaint, the plaintiffs continue to assert violations of the federal securities laws in connection with alleged misstatements and omissions of material fact in documents filed with 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 regarding these matters were made 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 the plaintiffs filed an answer to this motion in January 2004. Arguments before the Court on the motion were held on March 19, 2004.

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On April 15, 2004, the Court called for additional briefing on what effect, if any, the FERC proceedings (see “Federal Energy Regulatory Commission Inquiry” above) have on this case. On July 30, 2004, the Court denied the Company’s motion to dismiss this complaint, holding, among other things, that the FERC proceedings may ultimately have some evidentiary value relevant to the disclosure issues raised in this case, but they do not preclude the resolution of those issues by the Court. In November 2004, the Company filed its answer to the complaint denying the plaintiffs’ allegations. On June 13, 2005, the Company filed a motion for reconsideration of its earlier motion to dismiss this complaint, based, in part, on a recent United States Supreme Court decision with respect to the pleading requirements surrounding a sufficient showing of loss causation. On October 19 2005, the Court granted the Company’s motion for reconsideration and granted the Company’s motion to dismiss. The order to dismiss was issued without prejudice, and the Court has allowed the plaintiffs until November 10, 2005 to amend their complaint. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Counterparty Defaults

In 2001, Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) defaulted on payment obligations to the California Power Exchange (CalPX) and the California Independent System Operator (CalISO). As a result, the CalPX and the CalISO failed to pay various energy sellers, including Avista Energy. Both PG&E and the CalPX declared bankruptcy in 2001. In March 2002, SCE paid its defaulted obligations; however the funds SCE paid to the CalPX have yet to be released to energy sellers. In April 2004, PG&E paid its defaulted obligations into an escrow fund in accordance with its bankruptcy reorganization. Funds held by the CalPX and in the PG&E escrow fund are not subject to release until the FERC issues an order directing such release in the California Refund Proceeding (see discussion below). As of September 30, 2005, Avista Energy’s accounts receivable outstanding related to defaulting parties in California were fully offset by reserves for uncollected amounts and funds collected from defaulting parties. Avista Energy continues to defend itself in the California Refund Proceeding and pursue recovery of the defaulted obligations. Because the resolution of these defaulted obligations by counterparties remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability for potential refunds beyond the defaulted obligations. However, based on information currently known to the Company’s management, the Company does not expect that the resolution of these defaulted obligations will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

California Refund Proceeding

In July 2001, the FERC ordered an evidentiary hearing to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the CalISO and the CalPX during the period from October 2, 2000 to June 20, 2001 (Refund Period) in the California spot power market. The refunds were based on the development of a mitigated market clearing price methodology. If the refunds required by the formula would cause a seller to recover less than its actual costs for the refund period, the FERC has held that the seller would be allowed to document these costs and limit its refund liability commensurately. The FERC administrative law judge’s findings were certified in December 2002. In March 2003, the FERC reviewed the administrative law judge’s rulings, adopting many of his findings. The CalISO continues its efforts to prepare revised settlement statements based on newly recalculated costs and charges for spot market sales to California during the refund period and currently estimates that it will make its compliance filing showing “who owes what to whom” in 2006. In September 2005, Avista Energy submitted its cost filing claim pursuant to the FERC’s August 2005 order and demonstrated an overall revenue shortfall for sales into the California spot markets during the Refund Period after the mitigated market clearing price methodology is applied to its transactions. In October 2005, the California Parties protested Avista Energy’s filing and Avista Energy subsequently responded to those issues. Avista Energy believes that its cost filing claim is within a reasonable range in comparison to the California Parties subsequent response. The FERC has previously indicated that it may act on Avista Energy’s cost claim by the end of 2005.

In addition, in June 2003, the FERC issued an order to review bids above $250 per MW made by participants in the short-term energy markets operated by the CalISO and the CalPX from May 1, 2000 to October 2, 2000. Market participants with bids above $250 per MW during the period described above have been 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 was subject to this review. In May 2004, the FERC

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provided notice that Avista Energy was no longer subject to this investigation. In March and April 2005, the California Parties and PG&E, respectively, appealed the FERC’s decision before the United States Court of Appeals for the Ninth Circuit. In addition, many of the other orders that the FERC has issued in the California refund proceedings are now on appeal before the Ninth Circuit. Some of those issues have been consolidated as a result of a case management conference conducted in September 2004. In October 2004, the Ninth Circuit ordered that briefing proceed in two rounds. The first round is limited to three issues: (1) which parties are subject to the FERC’s refund jurisdiction in light of the exemption for government-owned utilities in section 201(f) of the Federal Power Act (FPA); (2) the temporal scope of refunds under section 206 of the FPA; and (3) which categories of transactions are subject to refunds. Oral argument on those issues took place in April 2005. In September 2005, the Ninth Circuit held that the FERC did not have the authority to order refunds for sales made by municipal utilities in the California Refund Case; no decision has yet been issued on the other issues argued in April 2005. The second round of issues and their corresponding briefing schedules have not yet been set by the Ninth Circuit Court of Appeals. Because the resolution of the California refund proceeding remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that the California refund proceeding will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Pacific Northwest Refund Proceeding

In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market sales in the Pacific Northwest between December 25, 2000 to June 20, 2001 were just and reasonable. During the hearing, Avista Utilities and Avista Energy vigorously opposed claims that Pacific Northwest markets were dysfunctional, that rates for spot market sales were unjust and unreasonable and that the imposition of refunds would be appropriate. In September 2001, the FERC’s Administrative Law Judge presiding over the evidentiary hearing issued a decision favorable to the Company’s position and recommended that the FERC not order refunds and instead dismiss the entire proceeding. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of refunds. In November 2003, the FERC affirmed its order. Seven petitions for review, including one filed by Puget Sound Energy, Inc. (Puget), are now pending before the United States Court of Appeals for the Ninth Circuit. Opening briefs were filed in January 2005. Petitioners other than Puget challenged the merits of the FERC’s decision not to order refunds. Puget’s brief is directed to the procedural flaws in the underlying docket. Puget argues that because its complaint was withdrawn as a matter of law in July 2001, the FERC erred in relying on it to serve as the basis to initiate the preliminary investigation into whether refunds for individually negotiated bilateral transactions in the Pacific Northwest were appropriate. In February 2005, intervening parties, including Avista Energy and Avista Utilities, filed in support of Puget and also filed in opposition to the other six petitioners. Briefing was completed in May 2005. Oral arguments are expected, but have not yet been set. Because the resolution of the Pacific Northwest refund proceeding remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that the Pacific Northwest refund proceeding will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Reliant Energy, Inc. and Duke Energy Corporation Cross-Complaints

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 that 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. In June 2002, 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 was itself the subject of an appeal to the United States Court of Appeals for the Ninth Circuit. In December 2004, the Ninth Circuit issued its opinion affirming the U.S. District Court’s remand of these cases to California State Court, and a rehearing request was denied on March 3, 2005. In April 2005, the Ninth Circuit denied Powerex Corp.’s motion to recall mandate, and the case was remanded to the California State Court. In June 2005, the cross-defendants, including Avista Energy, filed a petition to dismiss (demurrer) in the

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California State Court seeking to dismiss the Duke and Reliant cross-complaints. Further briefing and hearing on the demurrer is currently set for December 23, 2005. On October 3, 2005, the Court preliminarily agreed to take Duke’s and Reliant’s demurrers to the Plaintiff’s Master Complaint off calendar, pending approval of the proposed settlements between Duke and Reliant and the plaintiffs. On November 3, 2005, both Duke and Reliant entered into a stipulation with Avista Energy, which would conditionally dismiss, with prejudice, the cross complaints that had been filed against Avista Energy, subject to reinstatement if the proposed settlements between Duke and Reliant and the plaintiffs are not approved by the Courts. The Courts must approve this stipulation of dismissal of claims against Avista Energy. Based on the stipulation of dismissal, if approved, the Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

California Attorney General Complaint

In May 2002, the FERC conditionally dismissed a complaint filed in March 2002 by the Attorney General of the State of California (California AG) that alleged violations of the Federal Power Act by the FERC and all sellers (including Avista Corp. and its subsidiaries) of electric power and energy into California. The complaint alleged that the FERC’s adoption and implementation of market-based rate authority was flawed and, as a result, individual sellers were liable for sales of energy at rates that were “unjust and unreasonable.” In May 2002, the FERC issued an order dismissing the complaint but directing sellers to re-file certain transaction summaries. It was not clear that Avista Corp. and its subsidiaries were subject to this directive but the Company took the conservative approach and re-filed certain transaction summaries in June and July of 2002. In July 2002, the California AG requested a rehearing on the FERC order, which request was denied in September 2002. Subsequently, 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 September 2004, the United States Court of Appeals for the Ninth Circuit upheld the FERC’s market-based rate authority, but found the requirement that all sales at market-based rates be contained in quarterly reports filed with the FERC to be integral to a market-based rate tariff. The California AG has interpreted the decision as providing authority to the FERC to order refunds in the California refund proceeding for an expanded refund period. The Court’s decision leaves to the FERC the determination as to whether refunds are appropriate. In October 2004, Avista Energy joined with others in seeking rehearing of the Court’s decision to remand the case back to the FERC for further proceedings. The Ninth Circuit has yet to rule on the request for rehearing. Based on information currently known to the Company’s management, the Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Port of Seattle Complaint

In May 2003, a complaint was originally filed by the Port of Seattle in the United States District Court for the Western District of Washington against numerous companies, including Avista Corp., Avista Energy, Inc. and Avista Power, LLC (collectively the Avista defendants), seeking 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 alleged 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 Western Electricity Coordinating Council (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 Avista defendants filed a motion to dismiss this complaint. A transfer order was granted, which moved this case to the United States District Court for the Southern District of California to consolidate it with other pending actions. Arguments with respect to the motions to dismiss filed by the Avista defendants and other defendants were heard on March 26, 2004. On May 12, 2004, the United States District Court for the Southern District of California granted motions to dismiss filed by the Avista defendants, as well as other defendants, with respect to this complaint. The Court dismissed the complaint because it determined that it was without jurisdiction to hear the plaintiff’s claims, based on, among other things, the exclusive jurisdiction of the FERC and the filed-rate doctrine. On May 27, 2004, the Port of Seattle filed an appeal with the United States Court of Appeals for the Ninth Circuit. On October 17, 2005, the Ninth Circuit denied the plaintiffs’ joint motion for summary disposition of the Port of Seattle’s appeal. The Port of Seattle’s appeal to the Ninth Circuit has been briefed and awaits oral argument. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

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AVISTA CORPORATION

Wah Chang Complaint

On May 5, 2004, Wah Chang, a division of TDY Industries, Inc. (a subsidiary of Allegheny Technologies, Inc.), filed a complaint in the United States District Court for the District of Oregon 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, the Racketeer Influenced and Corrupt Organization Act, as well as violations of Oregon state law. According to the complaint, from September 1997 to September 2002, the plaintiff purchased electricity from PacifiCorp pursuant to a contract that was indexed to the spot wholesale market price of electricity. The plaintiff alleges that the defendants, acting in concert among themselves and/or with Enron Corporation and certain affiliates thereof (collectively, Enron) and others, engaged in a scheme to defraud electricity customers by transmitting false market information in interstate commerce in order to artificially increase the price of electricity provided by them, to receive payment for services not provided by them and to otherwise manipulate the market price of electricity, and by executing wash trades and other forms of market manipulation techniques and sham transactions. The plaintiff also alleges that the defendants, acting in concert among themselves and/or with Enron and others, engaged in numerous practices involving the generation, purchase, sale, exchange, scheduling and/or transmission of electricity with the purpose and effect of causing a shortage (or the appearance of a shortage) in the generation of electricity and congestion (or the appearance of congestion) in the transmission of electricity, with the ultimate purpose and effect of artificially and illegally fixing and raising the price of electricity in California and throughout the Pacific Northwest. As a result of the defendants’ alleged conduct, the plaintiff allegedly suffered damages of not less than $30 million through the payment of higher electricity prices. In September 2004, this case was transferred to the United States District Court for the Southern District of California for consolidation with other pending actions. In October 2004, the Avista defendants joined with other defendants in filing a joint motion to dismiss the complaint. In February 2005, the Court dismissed the complaint because it determined that it was without jurisdiction to hear the plaintiff’s complaint, based on, among other things, the exclusive jurisdiction of the FERC and the filed-rate doctrine. In March 2005, Wah Chang filed an appeal with the United States Court of Appeals for the Ninth Circuit. During May and June of 2005, several motions were filed by Wah Chang and the defendants that were subsequently denied by the United States Court of Appeals for the Ninth Circuit in July 2005. The appeal of Wah Chang is still pending before the Ninth Circuit and awaits oral argument. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

City of Tacoma Complaint

On June 7, 2004, the City of Tacoma, Department of Public Utilities, Light Division, a Washington municipal corporation (Tacoma Power), filed a complaint in the United States District Court for the Western District of Washington against over fifty companies, including Avista Corp., Avista Energy and Avista Power. According to the complaint, Tacoma Power distributes electricity to customers in Tacoma, and Pierce County, Washington, generates electricity at several facilities in western Washington and purchases power under supply contracts and in the Northwest spot market. Tacoma Power’s complaint seeks compensatory and treble damages from alleged violations of the Sherman Act. Tacoma Power alleges that the defendants, acting in concert, engaged in a pattern of activities that had the purpose and effect of creating the impressions that the demand for power was higher, the supply of power was lower, or both, than was in fact the case. This allegedly resulted in an artificial increase of the prices paid for power sold in California and elsewhere in the western United States during the period from May 2000 through the end of 2001. Due to the alleged unlawful conduct of the defendants, Tacoma Power allegedly paid an amount estimated to be $175.0 million in excess of what it would have paid in the absence of such alleged conduct. In September 2004, this case was transferred to the United States District Court for the Southern District of California for consolidation with other pending actions. In February 2005, the Court granted the defendants’ motion to dismiss this complaint for similar reasons to those expressed by the Court in the Wah Chang complaint described above. In March 2005, Tacoma Power filed an appeal with the United States Court of Appeals for the Ninth Circuit. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

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State of Montana Proceedings

On June 30, 2003, the Attorney General of the State of Montana (Montana AG) filed a complaint in the Montana District Court on behalf of the people of Montana and the Flathead Electric Cooperative, Inc. against numerous companies, including Avista Corp. The complaint alleges that the companies illegally manipulated western electric and natural gas markets in 2000 and 2001. This case was subsequently moved to the United States District Court for the District of Montana; however, it has since been remanded back to the Montana District Court.

The Montana AG also petitioned the Montana Public Service Commission (MPSC) to 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 reasonable rates. On February 12, 2004, the MPSC issued an order initiating investigation of the Montana retail electricity market for the purpose of determining whether there is evidence of unlawful manipulation of that market. The Montana AG has requested specific information from Avista Energy and Avista Corp. regarding their transactions within the State of Montana during the period from January 1, 2000 through December 31, 2001.

Because the resolution of these proceedings remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that these proceedings will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Montana Public School Trust Fund Lawsuit

In October 2003, a lawsuit was filed by Richard Dolan and Denise Hayman 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. An Amended Complaint adding Great Falls Elementary School District No. 1 and Great Falls High School District No. 1A was filed on January 16, 2004. On February 2, 2004, the Company filed its motion to dismiss this lawsuit; PacifiCorp and PPL Montana, as the other named defendants also filed a motion to dismiss, or joined therein. On May 10, 2004, the Montana AG filed a complaint on behalf of the state to join in this lawsuit to allegedly protect and preserve state lands/school trust lands from use without compensation. On July 19, 2004, the defendants (including Avista Corp.) filed a motion to dismiss the Montana AG’s complaint. On September 29, 2004, the United States District Court granted the motion to dismiss filed with respect to plaintiffs Richard Dolan, Denise Hayman and the school districts. However, the motion to dismiss the Montana AG’s complaint was denied, citing, among other things, that the FERC does not have exclusive jurisdiction over this matter. Subsequently, in response to the motions of the defendants, the federal magistrate judge on January 19, 2005 filed recommendations that the Court’s previous decision be vacated based on lack of jurisdiction of the Court. On September 27, 2005, the U.S. District Court issued an order vacating its prior decision, except as to matters of standing and jurisdiction. On November 12, 2004, the defendants (including Avista Corp.) filed a petition for declaratory relief in Montana State Court requesting the resolution of the controversy that the plaintiffs raised in federal court. On November 24, 2004, the Montana AG filed an answer, counterclaim and motion for summary judgment. The defendants have filed responses to the Montana AG’s motion for summary judgment. On June 8, 2005, Avista Corp. moved for leave to amend its complaint to, inter alia, add two causes of action relating to breach of contract and negligent misrepresentation arising out of its Clark Fork Settlement Agreement that was entered in 1999 with the State of Montana relating to the relicensing of Avista Corp.’s Noxon Rapids Hydroelectric Generating Project. On June 28, 2005, the Montana State Court heard the motion for summary judgment of the Montana AG and took the matter under advisement. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

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 & 4 of Colstrip. 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

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profits earned from the generation of Colstrip. The owners of Colstrip have undertaken certain groundwater investigation and remediation measures to address groundwater contamination. These measures include improvements to the lakes and ponds of Colstrip. The Company intends to continue to work with the other owners of Colstrip in defense of this complaint. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Environmental Protection Agency Administrative Compliance Order

In December 2003, PPL Montana, LLC, as operator of Colstrip, received an Administrative Compliance Order (ACO) from the Environmental Protection Agency (EPA) pursuant to the Clean Air Act (CAA). The ACO alleges that Colstrip Units 3 & 4 have been in violation of the CAA permit at Colstrip since 1980. The permit required the Colstrip project operator to submit for review and approval by the EPA an analysis and proposal for reducing emissions of nitrogen oxides to address visibility concerns if, and when, EPA promulgates Best Available Retrofit Technology requirements for nitrogen oxide emissions. The EPA is asserting that regulations it promulgated in 1980 triggered this requirement. Avista Utilities and PPL Montana, LLC believe that the ACO is unfounded and PPL Montana, LLC is discussing the matter with the EPA. The ACO does not expressly seek penalties, and it is unclear at this time what, if any, additional control technology the EPA may consider to be required. Accordingly, the costs to install any additional controls for nitrogen oxides, if required, cannot be estimated at this time. The owners of Colstrip are engaged in settlement negotiations on these matters with the EPA, the Department of Environmental Quality (Montana DEQ) and the Northern Cheyenne Tribe. Because the resolution of these issues remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that these issues will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

In addition, the Montana DEQ questioned whether the permit limits for sulfur dioxide emissions from Colstrip Units 3 & 4 were too high under provisions of the CAA that limit allowable emissions from sources built after 1978. PPL Montana, LLC, completed an ambient air quality modeling demonstration and, based on that study, voluntarily proposed to the Montana DEQ that the permit include restrictions related to sulfur dioxide emissions. The Montana DEQ has accepted this proposal and has issued an amended operating permit and issued an amended air permit, which the owners of Colstrip believe will resolve this matter with respect to the Montana DEQ.

Colstrip Royalty Claim

The Western Energy Company (WECO) supplies coal to the owners of Colstrip Units 3 & 4 under a Coal Supply Agreement and a Transportation Agreement. The Minerals Management Service (MMS) of the United States Department of the Interior issued an order to WECO to pay additional royalties concerning coal delivered to Colstrip Units 3 & 4 via the conveyor belt (approximately 4.46 miles long). The owners of Colstrip Units 3 & 4 take delivery of the coal at the western end (beginning) of the conveyor belt. The order asserts that additional royalties are owed MMS as a result of WECO not paying royalties in connection with revenue received by WECO from the owners of Colstrip Units 3 & 4 under the Transportation Agreement during the period October 1, 1991 through December 31, 2001. WECO’s appeal to the MMS was substantially denied in March 2005; WECO has now appealed the order to the Board of Land Appeals of the U.S. Department of the Interior. The entire appeal process could take several years to resolve. The owners of Colstrip Units 3 & 4 are monitoring the appeal process between WECO and MMS.

WECO has indicated to the owners of Colstrip Units 3 & 4 that if WECO is unsuccessful in the appeal process, WECO will seek reimbursement of any royalty payments by passing these costs through the Coal Supply Agreement. The owners of Colstrip Units 3 & 4 advised WECO that their position would be that these claims are not allowable costs per the Coal Supply Agreement nor the Transportation Agreement in the event the owners of Colstrip Units 3 & 4 were invoiced for these claims. Because the resolution of this issue remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this issue will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

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AVISTA CORPORATION

Hamilton Street Bridge Site

A portion of the Hamilton Street Bridge Site in Spokane, Washington (including a former coal gasification plant site that operated for approximately 60 years until 1948) was acquired by the Company through a merger in 1958. The Company no longer owns the property. In January 1999, the Company received notice from the State of Washington’s Department of Ecology (DOE) that it had been designated as a potentially liable party (PLP) with respect to any hazardous substances located on this site, stemming from the Company’s past ownership of the former gas plant site. In its notice, the DOE stated that it intended to complete an on-going remedial investigation of this site, complete a feasibility study to determine the most effective means of halting or controlling future releases of substances from the site, and to implement appropriate remedial measures. The Company responded to the DOE acknowledging its listing as a PLP, but requested that additional parties also be listed as PLPs. In the spring of 1999, the DOE named two other parties as additional PLPs.

The DOE, the Company and another PLP, Burlington Northern & Santa Fe Railway Co. (BNSF), signed an Agreed Order in March 2000 that provided for the completion of a remedial investigation and a feasibility study. After responding to comments from the DOE, the remedial investigation and feasibility study were accepted by the DOE as final during 2000. After receiving input from the Company and the other PLPs, the final Cleanup Action Plan (CAP) was issued by the DOE in August 2001. During the first quarter of 2002, the Company and BNSF signed a cost sharing agreement. In September 2002, the Company, BNSF and the DOE finalized the Consent Decree to implement the CAP. The third PLP did not sign the Consent Decree. In September 2004, a Site Preparation Agreement was reached with the third PLP with respect to the logistics of the CAP. The third PLP then completed the site preparation. The selected contractor then completed construction/installation of the work under the CAP by the end of the third quarter of 2005. The Company and BNSF filed the final Cleanup Action Report with the DOE in October 2005.

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. 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.

During the fourth quarter of 2002, Avista Development and one other PLP, Kaiser Aluminum & Chemical Corporation (Kaiser), finalized the Consent Decree and Scope of Work for the remedial investigation and feasibility study of the site. The other PLPs have not been participating in the process. As directed by Avista Development and Kaiser, the field-work for the remedial investigation began in April 2003 and was completed by the end of 2003. In March 2005, the DOE issued its draft Cleanup Action Plan (CAP), which was materially consistent with the draft final feasibility study filed by the Company and Kaiser in December 2004. Based on public comments received, the DOE made minor modifications to the CAP, remedial investigation and feasibility study, which were finalized in August 2005. The Company expects that work under the CAP will be completed in 2006.

The Company has entered into a settlement with the DOE and Kaiser relating to the remediation of the site. Under the agreement, the Company will perform the selected remedial action. Kaiser, which is presently operating under Chapter 11 bankruptcy protection, has paid the Company approximately 50 percent of the current estimate of the total costs, which was approved by the Kaiser bankruptcy judge and will be used by the Company to fund the costs of the remediation. During 2004, the Company accrued its share of the total estimated costs, which was not material to the Company’s consolidated financial condition or results of operations. Because of uncertainties with respect to, among other things, any future cost sharing agreement with the non-participating PLPs and unforeseen site conditions, the Company’s estimate of its liability could change in future periods. Based on information currently known to the Company’s management, the Company does not believe that such a change would be material to its

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financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimate of the liability. Such a change, should it occur, could be significant.

Harbor Oil Inc. Site

Avista Corp. used Harbor Oil Inc. (Harbor Oil) for the recycling of waste oil and non-PCB transformer oil in the late 1980s and early 1990s. On June 29, 2005, EPA Region 10 provided notification to Avista Corp., as a customer of Harbor Oil, that the EPA had determined that hazardous substances were released at the Harbor Oil site in Portland, Oregon and that Avista Corp. may be liable for investigation and cleanup of the site under the Comprehensive Environmental Response, Compensation, and Liability Act, commonly referred to as the federal “Superfund” law. Harbor Oil’s primary business was the collection and blending of used oil for sale as fuel to ships at sea. The initial indication from the EPA is that the site may be contaminated with PCBs, petroleum hydrocarbons, chlorinated solvents and heavy metals.

Thirteen other companies received a similar notice, including current and former owners of the site, the Bonneville Power Administration, Portland General Electric Corporation, Northwestern Energy and Unocal Oil. In August 2005, a majority of the named parties met among themselves and with the BPA for the purpose of discussing the interest in forming a steering committee and to listen to and ask questions of the EPA regarding the Harbor Oil site and their process in selecting the Potentially Responsible Parties (PRPs). The PRPs determined that it was premature to form a steering committee and that additional information was needed from the EPA on the process used in selecting the PRPs. A meeting with the EPA and the PRPs has been scheduled for November 2005.

The Company is in the process of gathering and reviewing all records related to Harbor Oil. Based on the review to this point, the Company does not believe it is a major contributor to this potential environmental contamination based on the relative volume of waste oil delivered to the Harbor Oil site. However, there is currently not enough information to allow the Company to assess the probability or amount of a liability, if any, being incurred. As such, it is currently not possible to make an estimate of any liability at this time.

Northeast Combustion Turbine Site

On August 7, 2005, a diesel fuel spill occurred at the Company’s Northeast Combustion Turbine generating facility (Northeast CT) located in Spokane, Washington. The Northeast CT site has fuel storage facilities that are leased to Co-op Supply, Inc., a subsidiary of Cenex Cooperative (Co-op). The fuel spill occurred when Co-op made a delivery of diesel to a tank that was already nearly full and the extra fuel overflowed into a containment area. It is estimated that approximately 30,000 gallons of fuel escaped the containment area and leaked into the soil below it. An investigation, supervised by the DOE, determined the fuel was, for the most part, uniformly present in the soil to a depth of 30-35 feet. Groundwater below the site is at a depth of 170 feet. Remediation efforts, which include the removal of contaminated soil and the fuel storage facilities, are currently ongoing and expected to be completed by the end of 2005. The Company has accrued its estimated share of the cleanup costs during the third quarter of 2005, which was not material to the Company’s consolidated financial condition or results of operations. It is possible that a change could occur in the Company’s estimate of the liability. Such a change, should it occur, is not expected to be significant.

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 (Tribe) owns, among other things, portions of the bed and banks of Lake Coeur d’Alene (Lake) lying within the current boundaries of the Coeur d’Alene Reservation. This action had been brought by the United States on behalf of the Tribe against the state of Idaho. The Company was not a party to this action. 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, among other things, the Company being liable to the Tribe for compensation for the use of reservation lands under Section 10(e) of the Federal Power Act.

The Company’s Post Falls Hydroelectric Generating Station (Post Falls), a facility constructed in 1906 with a present capability of 18 MW, utilizes a dam on the Spokane River downstream of the Lake which controls the water level in the Lake for portions of the year (including portions of the lakebed owned by the Tribe). The Company has other hydroelectric facilities on the Spokane River downstream of Post Falls, but these facilities do not affect the water level in the Lake. The Company and the Tribe are engaged in discussions with respect to past and future compensation (which may include interest) for use of the portions of the bed and banks of the Lake, which are owned by the Tribe. If the parties cannot agree on the amount of compensation, the matter could result in litigation. The Company cannot predict the amount of compensation that it will ultimately pay or the terms of such payment. However, the Company intends to seek recovery of any amounts paid through the rate making process.

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AVISTA CORPORATION

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 on August 1, 2007; the Company filed a Notice of Intent to Relicense in July 2002. The formal consultation process involving planning and information gathering with stakeholder groups has been underway since that time. The Company filed its license application with the FERC in July 2005. The Company has requested the FERC to consider a license for Post Falls that is separate from the other four hydroelectric plants. This is due to the fact that Post Falls presents more complex issues that may take longer to resolve than those dealing with the rest of the Spokane River Project. If granted, new licenses would have a term of 30 to 50 years. In the license application, the Company has proposed a number of measures intended to address the impact of the Spokane River Project and enhance resources associated with the Spokane River. Currently, certain environmental measures in the Company’s license application have estimated costs of $3.2 million per year. For certain items, costs cannot be reasonably estimated at this time. The total annual operating and capitalized costs associated with the relicensing of the Spokane River Project will become better known and estimable as the process continues over the next 21 months. The Company intends to seek recovery of relicensing costs through the rate making process.

Clark Fork Settlement Agreement

Dissolved atmospheric gas levels exceed state of Idaho and federal water quality standards downstream of the Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement, the Company developed an abatement and mitigation strategy with the other signatories to the agreement and submitted the Gas Supersaturation Control Program (GSCP) in December 2002 for review and approval to the Idaho Department of Environmental Quality (DEQ) and the U.S. Fish and Wildlife Service. In February 2004, the Idaho DEQ and the U.S. Fish and Wildlife Service approved the GSCP. In January 2005, the FERC issued an order approving the GSCP. The GSCP provides for the opening and modification of one and, potentially, both of the two existing diversion tunnels built when Cabinet Gorge was originally constructed. Streamflows would be diverted to the tunnels when these flows are in excess of turbine capacity. The cost of modifying the first tunnel is currently preliminarily estimated to be $38 million (including AFUDC and inflation) and will be incurred between 2004 and 2010 ($1.0 million incurred through September 30, 2005), with the majority of these costs being incurred in 2007 through 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 preliminarily estimated that the costs to modify the second tunnel would be $26 million (including AFUDC and inflation). As part of the GSCP, the Company provides $0.5 million annually 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 intends to seek recovery of the costs for the modification of Cabinet Gorge and the mitigation payments through the rate making process.

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 fish 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. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

NOTE 13. DISPOSITION OF SOUTH LAKE TAHOE PROPERTIES

In April 2005, Avista Corp. completed the sale of its South Lake Tahoe, California natural gas distribution properties to Southwest Gas Corporation as part of Avista Utilities’ strategy to focus on its business in the northwestern United States. This was the Company’s only regulated utility operation in California. The cash proceeds received during the second quarter were approximately $15.6 million, which resulted in a pre-tax gain of $3.2 million during the

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second quarter of 2005. During the third quarter of 2005, the Company completed the sale of its South Lake Tahoe administrative facilities, which resulted in a pre-tax gain of $0.9 million. The total pre-tax gain for the nine months ended September 30, 2005 was $4.1 million related to the Company’s disposition of its South Lake Tahoe natural gas properties.

Total revenues for 2004 from the South Lake Tahoe region were approximately $20.3 million (or 6 percent of total natural gas revenues) and approximately 22.1 million therms (or 4 percent of total therms) were delivered to South Lake Tahoe customers.

The Company classified the assets of its South Lake Tahoe natural gas properties as assets held for sale on the Consolidated Balance Sheets as of December 31, 2004. These assets consisted primarily of net utility property, accounts receivable and deferred natural gas costs.

NOTE 14. INFORMATION BY BUSINESS SEGMENTS

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 business segment primarily consists of electricity and natural gas marketing, trading and resource management including 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 utility bill processing, payment and information services to multi-site customers throughout North America. The Other business segment includes other investments and operations of various subsidiaries as well as certain other operations of Avista Capital. The following table presents information for each of the Company’s business segments (dollars in thousands):

	Avista Utilities			Energy Marketing And Resource Management			Avista Advantage		Other			Intersegment Eliminations (1)			Total
For the three months ended September 30, 2005:
Operating revenues	$	221,709		$	30,926		$	8,201	$	4,843		$	—		$	265,679
Resource costs		126,511			40,514			—		—			—			167,025
Gross margin		95,198			(9,588	)		—		—			—			85,610
Other operating expenses:
Operations and maintenance		28,212			58			3,596		3,962			—			35,828
Administrative and general		16,658			4,175			1,893		430			—			23,156
Depreciation and amortization		19,857			348			511		652			—			21,368
Income (loss) from operations		17,284			(14,460	)		2,201		(214	)		—			4,811
Interest expense (2)		22,951			72			233		473			(564	)		23,165
Income taxes		(1,206	)		(4,815	)		694		(87	)		—			(5,414	)
Net income (loss)		(1,803	)		(8,266	)		1,274		(242	)		—			(9,037	)
Capital expenditures		33,544			414			220		686			—			34,864
For the three months ended September 30, 2004:
Operating revenues		198,592			55,773			6,021		4,066			(22,900	)		241,552
Resource costs		110,744			48,156			—		—			(22,900	)		136,000
Gross margin		87,848			7,617			—		—			—			95,465
Other operating expenses:
Operations and maintenance		28,117			5,067			2,835		3,881			—			39,900
Administrative and general		18,258			4,860			1,912		1,449			—			26,479
Depreciation and amortization		19,102			320			451		585			—			20,458
Income (loss) from operations		8,446			(2,874	)		823		(1,850	)		—			4,545
Interest expense (2)		22,556			127			225		219			(332	)		22,795
Income taxes		(5,008	)		(623	)		210		(274	)		—			(5,695	)
Net income (loss)		(7,332	)		(1,241	)		391		(1,600	)		—			(9,782	)
Capital expenditures		30,807			346			208		156			—			31,517

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	Avista Utilities		Energy Marketing And Resource Management			Avista Advantage		Other			Intersegment Eliminations (1)			Total
For the nine months ended September 30, 2005:
Operating revenues	$	779,743	$	104,242		$	23,143	$	13,476		$	(19,429	)	$	901,175
Resource costs		420,946		118,640			—		—			(19,429	)		520,157
Gross margin		358,797		(14,398	)		—		—			—			344,399
Other operating expenses:
Operations and maintenance		81,244		343			10,610		11,677			—			103,874
Administrative and general		52,840		12,682			5,457		1,511			—			72,490
Depreciation and amortization		60,878		1,141			1,510		1,933			—			65,462
Income (loss) from operations		117,792		(29,241	)		5,336		(1,674	)		—			92,213
Interest expense (2)		68,677		208			700		1,225			(1,539	)		69,271
Income taxes		20,089		(9,435	)		1,644		(960	)		—			11,338
Net income (loss)		35,590		(16,874	)		3,000		(1,960	)		—			19,756
Capital expenditures		148,844		1,166			751		1,348			—			152,109
For the nine months ended September 30, 2004:
Operating revenues		688,743		202,559			16,808		12,645			(109,583	)		811,172
Resource costs		366,513		177,831			—		—			(109,583	)		434,761
Gross margin		322,230		24,728			—		—			—			346,958
Other operating expenses:
Operations and maintenance		82,134		5,067			8,369		11,349			—			106,919
Administrative and general		52,981		14,326			6,371		3,067			—			76,745
Depreciation and amortization		54,517		1,008			1,418		1,827			—			58,770
Income (loss) from operations		83,800		3,624			650		(3,735	)		—			84,339
Interest expense (2)		69,143		496			644		720			(1,020	)		69,983
Income taxes		8,488		2,217			13		(1,275	)		—			9,443
Net income (loss) before cumulative effect of accounting change		12,576		3,793			24		(3,359	)		—			13,034
Net income (loss)		12,576		3,793			24		(3,819	)		—			12,574
Capital expenditures		77,335		913			387		614			—			79,249
Total Assets:
Total assets as of September 30, 2005		2,868,455		2,595,412			46,555		48,613			—			5,559,035
Total assets as of December 31, 2004		2,602,715		1,002,843			47,318		53,305			—			3,706,181

(1) Intersegment eliminations reported as operating revenues and resource costs represent the transactions between Avista Utilities and Avista Energy for energy commodities and services, primarily natural gas purchased by Avista Utilities under the Agency Agreement. Intersegment eliminations reported as interest expense represent intercompany interest.

(2) Including interest expense to affiliated trusts.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Avista Corporation and Subsidiaries

Spokane, Washington

We have reviewed the accompanying consolidated balance sheet of Avista Corporation and subsidiaries (the “Company”) as of September 30, 2005, and the related consolidated statements of income and of comprehensive income (loss) for the three-month and nine-month periods ended September 30, 2005 and 2004, and of cash flows for the nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of the Company as of December 31, 2004 and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated March 9, 2005, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2004 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Seattle, Washington

November 2, 2005

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

Forward-Looking Statements

Avista Corp. from time to time makes forward-looking statements such as statements regarding future financial performance, capital expenditures, dividends, capital structure and other financial items, and assumptions underlying them (many of which are based, in turn, upon further assumptions), as well as strategic goals and objectives and plans for future operations. Such statements are made both in Avista Corp.’s reports filed under the Securities Exchange Act of 1934, as amended (including this Quarterly Report on Form 10-Q), and elsewhere. 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,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “projects,” “predicts,” and similar expressions.

All forward-looking statements (including those made in this Quarterly Report) are subject to a variety of risks and uncertainties and other factors, most of which are beyond the control of Avista Corp. and many of which could have a significant impact on Avista Corp.’s operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements. Such risks, uncertainties and other factors include, among others:

• weather conditions, including the effect of precipitation and temperatures on the availability of hydroelectric resources and the effect of temperatures on customer demand;

• the impact of state and federal regulatory decisions affecting the ability of the Company to recover its costs and/or earn a reasonable return, including, but not limited to, the disallowance of previously deferred costs;

• changes in wholesale energy prices that can affect, among other things, the market value of derivative assets and liabilities and unrealized gains and losses, as well as cash requirements to purchase electricity and natural gas for retail customers;

• the outcome of pending regulatory and legal proceedings arising out of the “western energy crisis” of 2001 and 2002, and including possible retroactive price caps and resulting refunds;

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

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

• the potential effects of any legislation or administrative rulemaking passed into law, including the Energy Policy Act of 2005 which was passed into law in August 2005;

• the impact from the potential formation of a Regional Transmission Organization;

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

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

• changes in global energy markets that can affect, among other things, the price of natural gas purchased for retail customers and purchased as fuel for electric generation;

• the ability to relicense the Spokane River Project at a cost-effective level with reasonable terms and conditions;

• unplanned outages at any Company-owned generating facilities;

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

• natural disasters that can disrupt energy delivery as well as the availability and costs of materials and supplies and support services;

• blackouts or large disruptions of transmission systems, which can have an impact on the Company’s ability to deliver energy to its customers;

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

• changes in the long-term climate of the Pacific Northwest, which can affect, among other things, customer demand patterns and the volume and timing of streamflows to hydroelectric resources;

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

• 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

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AVISTA CORPORATION

affected by various factors including the Company’s credit ratings, interest rate fluctuations and other capital market conditions;

• the impact of any potential change in the Company’s credit ratings;

• changes in actuarial assumptions, the interest rate environment and the actual return on plan 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.

• 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 rapidly advancing technologies, possibly making some of the current technology quickly obsolete;

• changes in tax rates and/or policies; and

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

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. and 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. Business Segments

Avista Corp. is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. The Company has four business segments – Avista Utilities, Energy Marketing and Resource Management, Avista Advantage and Other. Avista Utilities is an operating division of Avista Corp. comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility business segments. The Company’s total common stockholders’ equity was $754.0 million as of September 30, 2005 of which $227.6 million represented its investment in Avista Capital.

The Energy Marketing and Resource Management business segment is comprised of Avista Energy, Inc. (Avista Energy) and Avista Power, LLC (Avista Power). Avista Energy is an electricity and natural gas marketing, trading and resource management business, operating primarily in the Western Electricity Coordinating Council (WECC) geographical area, which is comprised of eleven Western states and the provinces of British Columbia and Alberta, Canada. Avista Power is an investor in certain generation assets, primarily its 49 percent interest in the Lancaster Project.

Avista Advantage, Inc. (Avista Advantage) is a provider of utility bill processing, payment and information services to multi-site customers throughout North America. Its primary product lines include consolidated billing, resource accounting, energy analysis and load profiling services.

The Other business segment includes Avista Ventures, Inc. (Avista Ventures), Pentzer Corporation (Pentzer), Avista Development and certain other operations of Avista Capital. Included in this business segment is Advanced Manufacturing and Development (AM&D) doing business as METALfx, a subsidiary of Avista Ventures that performs custom sheet metal manufacturing of electronic enclosures, parts and systems for the computer, telecom and medical industries. AM&D also provides complete fabrication and turnkey assembly for arcade games, kiosks, store fixtures and displays. Other significant investments in this segment include commercial office buildings, investments in low income housing and venture capital partnerships, the remaining investment in a previous fuel cell subsidiary of the Company, and notes receivable from the sale of property and investments.

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Executive Level Summary

Avista Corp.’s operating results and cash flows are derived primarily from Avista Utilities and Avista Energy (included in the Energy Marketing and Resource Management segment). Avista Corp. intends to continue to focus on improving earnings and operating cash flows, controlling costs and reducing debt while working to restore an investment grade credit rating.

Avista Utilities expects to continue to be among the industry leaders in performance, value and service in its electric and natural gas utility businesses. Avista Utilities expects to continue its modest, yet steady, combined growth of electric and natural gas customers of 2 to 3 percent per year primarily from economic and population growth in its service territory. As part of Avista Utilities’ strategy to focus on its business in the northwestern United States, in April 2005, the Company completed the sale of its natural gas properties in South Lake Tahoe, California (see “Note 13 of the Notes to Consolidated Financial Statements”). This was the Company’s only regulated utility operation in California.

It is Avista Utilities’ strategy to own or to have contracts that provide a sufficient amount of electric resources to meet its retail and wholesale energy requirements under a range of operating conditions. Precipitation, temperatures and other variables significantly affect the availability of Avista Utilities’ hydroelectric generation. Avista Utilities’ hydroelectric generation was 95 percent of normal in 2004. Based on actual hydroelectric generation through September 30, 2005 and forecasts of below normal precipitation and streamflows for the remainder of the year, Avista Utilities expects hydroelectric generation will be approximately 94 percent of normal in 2005. This may change based upon precipitation, temperatures and other variables during the fourth quarter. The earnings impact of below normal hydroelectric generation is mitigated by power cost deferral and recovery mechanisms in Washington and Idaho. The expected reduction in hydroelectric generation is not expected to have a significant negative effect on operating cash flows or earnings for 2005 from the amount originally forecasted. Including the forecast for 2005, hydroelectric generation has been below normal for 5 of the past 6 years. The Company cannot determine if this trend of lower than normal hydroelectric generation will continue in future years.

Customer loads and resulting revenues are also significantly affected by weather, which causes changes in energy usage from season to season and from month to month within a season. Avista Utilities normally experiences its highest total retail (electric and natural gas) energy sales during the heating season in the first and fourth quarters of the year. Avista Utilities also experiences high electricity demand for air conditioning during the summer (third quarter). The weather was warmer during the winter heating season and colder during the summer cooling season during the nine months ended September 30, 2005 as compared to the corresponding periods of 2004. As such, electric and natural gas loads and revenues were negatively affected by weather when comparing year-to-date results for 2005 and 2004.

As is the case with most regulated entities, Avista Utilities generally has ongoing regulatory proceedings. Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which it provides service. Avista Utilities received the following base rate increases in 2004 and 2005: Idaho electric and natural gas in September 2004; Washington natural gas in November 2004; and Idaho electric in April 2005 for the addition of the remaining interest in Coyote Springs 2. The base rate increases implemented in 2004 have increased revenues and net income for the three and nine months ended September 30, 2005 as compared to the three and nine months ended September 30, 2004 and should result in increased net income for the full year of 2005 as compared to 2004. In March 2005, Avista Utilities filed a request with the WUTC to increase its base electric and natural gas rates. A settlement agreement was reached in August 2005, which is subject to the approval of the WUTC. Avista Utilities will continue to file for rate adjustments to provide for recovery of its costs and to more closely align earned returns with those allowed by regulatory agencies in each jurisdiction.

Avista Utilities’ net income increased for the nine months ended September 30, 2005 as compared to the nine months ended September 30, 2004 primarily due to the general rate increases, as well as the gain on the sale of the South Lake Tahoe natural gas properties. This was partially offset by decreased use per customer in the Washington and Idaho service territories as a result of warmer weather during the first quarter. The Company expects Avista Utilities’ net income for 2005 to increase as compared to 2004 primarily due to the continued effect of general rate increases, subject to the influence of weather during the fourth quarter. The third quarter is typically a relatively lower earnings quarter for Avista Utilities. Results for the third quarter of 2005 were reduced by higher electric resource costs due to seasonally low hydroelectric generation, higher fuel costs, increase purchased power expenses and the absorption of the $8.2 million of the dead band under the ERM in Washington. This included the reversal of the $0.7 million benefit received for the first half of 2005 under the ERM methodology. On a year-to-date basis,

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Avista Utilities absorbed $7.5 million of the $9.0 million dead band under the ERM and expects to absorb the remaining $1.5 million during the fourth quarter of 2005.

Avista Energy focuses on optimization of generation assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric transmission and natural gas transportation arrangements. Avista Energy is also involved in trading electricity and natural gas, including derivative commodity instruments. Avista Energy Canada, Ltd. (Avista Energy Canada) is a wholly owned subsidiary of Avista Energy that provides natural gas services to approximately 250 end-user industrial and commercial customers that represent over 400 sites in British Columbia, Canada. In addition to earnings and resulting cash flows from settled or realized transactions, Avista Energy records unrealized or mark-to-market adjustments for the change in the value of derivative commodity instruments. Avista Energy’s marketing, trading and resource management activities 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 continues to seek opportunities to expand its business of optimizing generation assets owned by other entities and has expanded its natural gas end-user business to industrial and commercial customers in Montana.

Avista Energy is subject to certain regulatory proceedings that remain unresolved; however, Avista Energy believes that it has adequate reserves established for refunds that may be ordered. The wholesale power markets in which Avista Energy operates continue to change with respect to market participants involved, level of activity, volatility in market prices, liquidity, regulatory imposed price caps and counterparty credit issues.

Avista Energy and the Energy Marketing Resource Management segment incurred a net loss for the nine months ended September 30, 2005 compared to net income for the nine months ended September 30, 2004. This net loss for the year-to-date 2005 was primarily related to losses in Avista Energy’s natural gas portfolio, particularly with respect to the management of natural gas inventory.

Avista Advantage remains focused on increasing revenues, controlling operating expenses, continuously enhancing client satisfaction and developing complementary value-added services in a competitive market. During the first quarter of 2005, Avista Advantage acquired TelAssess, Inc. Although not a significant financial transaction, this acquisition provides Avista Advantage a foundation on which to expand beyond utility bill information services to provide similar services relating to telecom billing. The Company expects that net income for Avista Advantage for 2005 will increase as compared to 2004 based on increased revenues from an expanding customer base and stabilizing operating expenses from processing efficiencies.

Over time as opportunities arise, the Company plans to continue to dispose of assets and phase out operations in the Other business segment. The Company expects the net loss in the Other business segment to be less for fiscal year 2005 as compared to 2004 primarily due to decreased losses from asset impairments and write-offs.

During the nine months ended September 30, 2005, positive cash flows from operations, proceeds from the sale of the Company’s South Lake Tahoe natural gas properties and an overall reduction in the Company’s consolidated cash position were used to fund the majority of Avista Corp.’s cash requirements, including utility capital expenditures and dividends.

In September 2005, Avista Corp. terminated (by exercise of a purchase option) the lease agreement with, and acquired the Rathdrum CT from, WP Funding LP (an entity whose financial statements have been consolidated with the Company since 2003). As a result of this transaction, Avista Corp. is no longer including WP Funding LP in its consolidated financial statements as of September 30, 2005. This transaction and deconsolidation did not have a material effect on the Company’s total consolidated assets, liabilities, stockholders’ equity or results of operations. From a consolidated perspective, the Company replaced the $56.3 million of WP Funding LP debt and third-party investment, with borrowings on Avista Corp.’s committed line of credit. Avista Corp. expects to issue up to $100 million of long-term debt during the fourth quarter of 2005 to, among other things, refinance these borrowings on its committed line of credit.

Excluding the planned long-term debt issuance during the fourth quarter of 2005, the Company expects cash flows from operations and Avista Corp.’s committed line of credit to provide adequate resources to fund capital expenditures, maturing long-term debt, dividends and other contractual commitments.

The Company has management succession plans that work towards ensuring that executive officer and key management positions can be appropriately filled as vacancies occur. The Company has taken similar steps in key technical and craft areas.

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Avista Utilities – Regulatory Matters

General Rate Cases

On March 30, 2005, Avista Utilities filed a request with the WUTC to increase its base electric and natural gas rates. On August 12, 2005, Avista Utilities, the WUTC staff, the Northwest Industrial Gas Users and the Energy Project entered into a settlement that, if approved by the WUTC, would resolve all issues in Avista Utilities’ electric and natural gas general rate cases. The Public Counsel Section of the Washington Attorney General’s Office and the Industrial Customers of Northwest Utilities did not join in the settlement agreement. The settlement agreement provides for base electric and natural gas rate increases of 7.7 percent and 0.6 percent, respectively, a decrease from Avista Utilities’ March 2005 requests of 12.5 percent and 1.8 percent, respectively. The revised rate increase requests are designed to increase electric and natural gas revenues by $22.1 million and $1.0 million, respectively. The majority of the increase in electric revenues provides for an increased level of power supply costs to be recovered in base rates. As such, a portion of the increase will not increase gross margin or net income. The settlement agreement provides for an overall rate of return of 9.11 percent, including a return on common equity of 10.4 percent based on an equity level of 40 percent. Under the settlement agreement, Avista Utilities has agreed to increase the utility equity component to 35 percent by the end of 2007 and 38 percent by the end of 2008. If these targets are not met, it could result in a reduction to base retail rates. The utility equity component was approximately 31 percent as of September 30, 2005. The settlement agreement also provides for modifications to the ERM as discussed at “Power Cost Deferrals and Recovery Mechanisms” below. Hearings were held in October 2005 and the settling parties have requested that the settlement agreement become effective January 1, 2006. The WUTC can take several actions with respect to the settlement including, but not limited to, approving it as presented, rejecting it and ordering additional rate case proceedings, or approving it with conditions that would also be subject to the acceptance of the settling parties.

In January 2005, the WUTC issued its final order with respect to a natural gas general rate case filed by Avista Utilities in Washington. The final order authorized, among other things, an increase in natural gas rates of 3.9 percent, which is designed to increase annual revenues by $5.4 million. The final order authorized an overall rate of return of 8.68 percent.

In October 2004, the IPUC issued its final order with respect to electric and natural gas general rate cases filed by Avista Utilities in Idaho. The final order authorized, among other things, Avista Utilities to increase its electric base rates by 16.9 percent, which is designed to increase annual revenues by $24.7 million, and increase its natural gas base rates by 6.4 percent, which is designed to increase annual revenues by $3.3 million. Due to a decrease implemented concurrently in Avista Utilities’ power cost adjustment (PCA) surcharge and certain other minor adjustments, the net increase in electric rates for Idaho customers was 1.9 percent above rates in effect at that time. The final order authorized an overall rate of return of 9.25 percent, including a return on common equity of 10.4 percent based on an authorized equity level of approximately 43 percent. Based on the final order, Avista Utilities had to write off a total of $14.7 million ($12.3 million of deferred power cost and $2.4 million of capitalized utility plant costs), which was recorded in the third quarter of 2004.

Other Regulatory Filings and Rulings

In April 2005, the IPUC issued an order approving the inclusion of the remaining 50 percent of Coyote Springs 2 in base electric rates. The order provides for a 1.9 percent increase in base electric rates, which is designed to increase annual revenues by $3.2 million. At the same time, the IPUC approved a 1.9 percent reduction in the Company’s current PCA rate surcharge. These two requests together resulted in no overall change to customers’ existing rates.

The OPUC has recently issued temporary rules and is in the process of formulating final rules related to Oregon Senate Bill 408 (OSB 408). OSB 408 requires the OPUC to direct the utility to establish an automatic adjustment clause to account for the difference between taxes collected in rates and taxes paid to units of government, net of adjustments, when that difference exceeds $100,000. Taxes paid attributed to Oregon regulated operations are limited to the lesser of consolidated or stand-alone tax payments. The automatic adjustment clause may result in either rate increases or rate decreases and applies only to taxes paid and collected on or after January 1, 2006. Interpretation and application of OSB 408 is complicated by a number of factors, including, but not limited to, the adjustments that are allowed under OSB 408, the Company’s organizational structure, and the fact that the Company provides retail natural gas and electric services in multiple state jurisdictions. At this point in time, the Company cannot predict the impact that OSB 408 may have on revenues or net income related to its Oregon natural gas operations.

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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 Consolidated Balance Sheets for future review and the opportunity for recovery through retail rates.

In Washington, 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, which is referred to as the dead band. Under the ERM, 90 percent of the power supply costs exceeding or below the dead band 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 August 2005 settlement agreement in Avista Utilities’ general rate case filing provides for the dead band to be reduced from $9.0 million to $3.0 million beginning in 2006. In addition, the current ERM surcharge of 9.8 percent would be increased to 10.8 percent, which would allow Avista Utilities to more rapidly recover deferred power costs.

Avista Utilities expensed $7.5 million of the dead band during the nine months ended September 30, 2005 and expects to absorb the remaining $1.5 million during the fourth quarter. The Company expensed the entire dead band during 2004, 2003 and 2002 ($4.5 million in 2002 due to mid-year implementation on July 1, 2002).

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 ERM provides 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 annual filing with the WUTC on March 30, 2005 related to $10.8 million of deferred power costs incurred for 2004. On June 29, 2005, the WUTC issued an order, which approved the recovery of the $10.8 million of deferred power costs incurred for 2004. In addition, by the end of 2006, Avista Utilities is required to make a filing with the WUTC that will allow interested parties the opportunity to review and propose changes to the ERM. Avista Utilities has agreed in the August 2005 settlement agreement, if approved by the WUTC, to initiate discussions with interested parties in early 2006 regarding a review and potential modifications to the ERM.

Avista Utilities has a PCA mechanism in Idaho that allows it to modify electric rates periodically with IPUC approval. Under the PCA mechanism, Avista Utilities defers 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. As disclosed at “General Rate Cases” above, in October 2004, the IPUC issued its final order with respect to general electric and natural gas rate cases filed by Avista Utilities in Idaho. The IPUC authorized the recovery of remaining deferred power costs over a two-year period through a PCA rate surcharge to customers that was reduced to 4.4 percent. The PCA surcharge was further reduced to 2.5 percent in April 2005 with the approval of the inclusion of the remaining interest in Coyote Springs 2 in base electric rates. The decrease in the PCA rate surcharge extends the recovery period of deferred power costs by an additional year.

The following table shows activity in deferred power costs for Washington and Idaho during 2004 and the nine months ended September 30, 2005 (dollars in thousands):

	Washington			Idaho			Total
Deferred power costs as of December 31, 2003	$	125,705		$	30,285		$	155,990
Activity from January 1 – December 31, 2004:
Power costs deferred		10,498			15,276			25,774
Unrealized gain on fuel contracts (1)		(3,139	)		(1,596	)		(4,735	)
Interest and other net additions		6,354			532			6,886
Write-off of deferred power costs		—			(11,959	)		(11,959	)
Recovery of deferred power costs through retail rates		(26,210	)		(23,040	)		(49,250	)
Deferred power costs as of December 31, 2004		113,208			9,498			122,706
Activity from January 1 – September 30, 2005:
Power costs deferred		—			2,529			2,529
Interest and other net additions		4,164			220			4,384
Recovery of deferred power costs through retail rates		(19,673	)		(4,556	)		(24,229	)
Deferred power costs as of September 30, 2005	$	97,699		$	7,691		$	105,390

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

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Purchased Gas Adjustments

Natural gas commodity costs in excess of, or which fall below, the amount recovered in current retail rates are deferred and recovered or refunded as a pass-through to customers in future periods with applicable regulatory approval through adjustments to rates. Currently, purchased gas adjustments provide for the deferral and future recovery or refund of 100 percent of the difference between commodity costs and the amount recovered in current retail rates in Washington and Idaho. In Oregon, Avista Utilities has received a tariff revision that provides for 100 percent recovery of known hedges. With respect to the unhedged portion of customer loads, the revised tariff provides for the deferral and future recovery or refund of 90 percent of the difference between actual prices and the amount recovered in current retail rates effective October 1, 2005. The Company has hedged most of its natural gas load requirements in Oregon. During September through November of 2004, natural gas rate increases of 11.7 percent, 14.2 percent and 12.6 percent were implemented in Washington, Idaho and Oregon, respectively. During October and November of 2005, natural gas rate increases of 23.5 percent, 23.8 percent and 22.5 percent were implemented in Washington, Idaho and Oregon, respectively. These natural gas rate increases are designed to pass through increases in purchased natural gas costs to customers with no change in Avista Utilities’ gross margin or net income. Although substantial, these natural gas rate increases are still less than the current market price of natural gas. If prices remain at current levels, the balance of deferred natural gas costs will continue to increase in future periods. Total deferred natural gas costs were $34.2 million and $28.6 million as of September 30, 2005 and December 31, 2004, respectively.

Natural Gas Benchmark Mechanism

See “Natural Gas Benchmark Mechanism” in “Note 1 of the Notes to Consolidated Financial Statements” for a description of the Natural Gas Benchmark Mechanism and related Agency Agreement. Effective April 1, 2005, the Natural Gas Benchmark Mechanism and related Agency Agreement were terminated and the management of natural gas procurement functions was moved from Avista Energy back to Avista Utilities. This was required for Washington customers by WUTC orders issued in February 2004, and Avista Utilities’ resulting transition plan approved by the WUTC in April 2004. The Company also elected to move these functions back to Avista Utilities for Idaho and Oregon natural gas customers.

Power Market Issues

Legal and Regulatory Proceedings in Western Power Markets

Avista Energy and Avista Utilities are involved in a number of legal and regulatory proceedings and complaints with respect to power markets in the western United States. Most of these proceedings and complaints relate to the significant increase in the spot market price of energy in western power markets in 2000 and 2001, which allegedly contributed to or caused unjust and unreasonable prices. These proceedings and complaints include, but are not limited to, refund proceedings and hearings in California and the Pacific Northwest, market conduct investigations by the FERC (including a specific investigation of Avista Utilities and Avista Energy), and complaints and cross-complaints filed by various parties with respect to alleged misconduct by other parties in western power markets. As a result of these proceedings and complaints, certain parties have asserted claims for refunds and damages from Avista Energy and Avista Utilities, which could result in a negative impact on future earnings. Avista Energy and Avista Utilities have joined other parties in opposing these refund claims and complaints for damages. See further information in “Note 12 of the Notes to Consolidated Financial Statements.”

Market Conduct Investigations and Market-Based Rate Authority

As a result of certain revelations about alleged improper practices engaged in by Enron and certain of its affiliates, the FERC initiated investigations in 2002 of many participants in power markets in the western United States, including Avista Corp. doing business as Avista Utilities, and Avista Energy. Avista Utilities and Avista Energy cooperated with the FERC investigation by providing requested documents and other information. Several parties filed documents with the FERC in March 2003 alleging improper market conduct by various parties, including Avista Utilities and Avista Energy, and requesting refunds and other relief. Avista Utilities and Avista Energy filed replies in response to the allegations of the parties.

In March 2003, the FERC policy staff issued its final report on its 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 2003 FERC policy staff report, Avista Corp. and Avista Energy were among the few that had already been subjects of a FERC investigation. In April 2004, the FERC approved an agreement that resolves the investigation of Avista Corp. and Avista Energy. Other parties filed requests for rehearing and filed motions to intervene in these proceedings. In April 2005, the FERC denied the requests for rehearing and motion to intervene in these proceedings; however, the other parties subsequently filed appeals with the United States Court of Appeals

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for the Ninth Circuit in response to the FERC’s denial of rehearing requests. See further information under “Federal Energy Regulatory Commission Inquiry” in “Note 12 of the Notes to Consolidated Financial Statements.”

Every three years or more frequently if certain regulatory triggers are met, Avista Corp. doing business as Avista Utilities, and Avista Energy are required to file for renewal of their respective market-based rate authority with the FERC. Avista Utilities and Avista Energy made their respective filings with the FERC in September 2004. By orders issued in March 2005, the FERC approved the renewal of the market-based rate authority of Avista Utilities and Avista Energy.

Wholesale Energy Markets and Development of Regional Transmission Organizations

In July 2005, the FERC announced that it had officially abandoned its efforts commenced in 2002 to create new national standard wholesale power market rules. However, the FERC continues its efforts with respect to the formation of Regional Transmission Organizations. This could significantly change how transmission facilities are regulated and operated.

Avista Corp. has participated with other utilities in the western United States on the possible formation of a Regional Transmission Organization (RTO). Interim bylaws governing continuing developmental activities for this non-profit corporation, under the name Grid West, were adopted in December 2004. The next phase of the development of Grid West would be the establishment of a board of directors, which is currently planned for early 2006. Avista Corp. is also participating in concurrent discussions with the Transmission Improvements Group regarding the enhancement of existing organizational structures to incorporate certain elements and functions that have been contemplated to be included in a RTO.

The final proposal for any RTO must be filed with the FERC and approved by the boards of directors of the filing companies and regulators in various states. The Company’s decision to move forward with the formation of any RTO serving the Pacific Northwest region, as well as the legal, financial and operating implications of such decisions, will ultimately depend on the terms and conditions related to the formation of the entities and conditions established in the regulatory approval processes. The Company cannot predict these implications.

Energy Policy Act of 2005

In August 2005, the Energy Policy Act of 2005 (Energy Policy Act) was passed into law. The Energy Policy Act will substantially affect the regulation of energy companies, including Avista Corp. Key provisions of the Energy Policy Act affecting the Company include, but are not limited to, reform of the hydroelectric licensing process, tax credits for incremental hydroelectric production and the implementation of mandatory reliability standards. The Energy Policy Act also has provisions related to the future operation and development of transmission systems and federal support for certain clean power initiatives and renewable energy technologies, including wind power generation. Finally, the Energy Policy Act repeals the Public Utility Holding Company Act of 1935 (PUHCA) and, among other things, grants the FERC and state utility commissions access to the books and records of holding company systems, provides (upon request of a state commission or holding company system) for FERC review of allocations of costs of non-power goods and administrative services and modifies the jurisdiction of the FERC over certain mergers and acquisitions involving public utilities or holding companies.

The implementation of the Energy Policy Act requires proceedings at the state level and the development of regulations by the FERC, the Department of Energy and other federal agencies. In particular, the FERC has proposed rules that, among other things, implement new reliability standards; require that open access be provided to non-regulated transmission utilities and implement the new provisions relating to the repeal of PUHCA.

The Company is still in the process of analyzing the effect of the Energy Policy Act on the Company, including the effects of any related proceedings at the state level and new regulations at the national level.

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Results of Operations

Contribution to Diluted Earnings (Loss) per Common Share by Business Segments

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

	Three months ended September 30,						Nine months ended September 30,
	2005			2004			2005			2004
Avista Utilities	$	(0.04	)	$	(0.15	)	$	0.72		$	0.26
Energy Marketing and Resource Management		(0.17	)		(0.03	)		(0.34	)		0.08
Avista Advantage		0.03			0.01			0.06			—
Other		(0.01	)		(0.03	)		(0.04	)		(0.07	)
Earnings (loss) per common share before cumulative effect of accounting change		(0.19	)		(0.20	)		0.40			0.27
Loss per common share from cumulative effect of accounting change		—			—			—			(0.01	)
Total earnings (loss) per common share, diluted	$	(0.19	)	$	(0.20	)	$	0.40		$	0.26

Overall Operations

Three months ended September 30, 2005 compared to the three months ended September 30, 2004

Avista Corp. incurred a net loss of $9.0 million for the three months ended September 30, 2005 compared to a net loss of $9.8 million for the three months ended September 30, 2004. The net loss for the three months ended September 30, 2005 was due to the net loss at Avista Energy (Energy Marketing and Resource Management segment) and the absorption of $8.2 million of power costs under Avista Utilities’ ERM dead band. The net loss for the three months ended September 30, 2004 was primarily due to the IPUC related write-offs of $14.7 million ($9.6 million, net of taxes) recorded at Avista Utilities, as well as asset impairment charges of $5.1 million ($3.3 million, net of taxes) recorded at Avista Power (Energy Marketing and Resource Management segment).

Avista Utilities had a net loss of $1.8 million for the three months ended September 30, 2005, compared to a net loss of $7.3 million for the three months ended September 30, 2004. The net loss for the third quarter of 2005 was due to the absorption of $8.2 million of power costs under the ERM dead band during the three months ended September 30, 2005. The net loss for the three months ended September 30, 2004 was due to the IPUC related write-offs. Excluding the effect of the ERM dead band for 2005 and the IPUC related write-offs for 2004, the improvement in Avista Utilities’ results was primarily due to the positive effects of general rate increases implemented during the second half of 2004 in Washington and Idaho.

Energy Marketing and Resource Management had a net loss of $8.3 million for the three months ended September 30, 2005 compared to a net loss of $1.2 million for the three months ended September 30, 2004. The net loss for the third quarter of 2005 was primarily due to losses in Avista Energy’s natural gas portfolio with a significant portion of the net loss due to the accounting for the management of natural gas inventory. The net loss for the third quarter of 2004 was due to asset impairment charges at Avista Power for a turbine and related equipment.

Net income for Avista Advantage was $1.3 million for the three months ended September 30, 2005 compared to $0.4 million for the three months ended September 30, 2004. The change was primarily due to an increase in operating revenues from customer growth.

The Other business segment incurred a net loss of $0.2 million for the three months ended September 30, 2005 compared to a net loss of $1.6 million for the three months ended September 30, 2004. The decrease in the net loss was primarily due to the accrual of an environmental liability at Avista Development during the third quarter of 2004, as well as the improved performance of AM&D.

Total revenues increased $24.1 million for the three months ended September 30, 2005 compared to the three months ended September 30, 2004. Avista Utilities’ revenues increased $23.1 million due to increases in both electric and natural gas revenues. The increase in natural gas revenues was primarily due to increased natural gas wholesale sales and natural gas rate increases implemented during 2004, partially offset by the sale of the South Lake Tahoe properties. The increase in electric revenues primarily reflects an increase in wholesale revenues, partially offset by a decrease in sales of fuel and a slight decrease in retail revenues due to reduced cooling loads. Revenues

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from Energy Marketing and Resource Management decreased $24.8 million primarily due to decreased revenues under the Agency Agreement with Avista Utilities as natural gas procurement operations were transitioned to Avista Utilities effective April 1, 2005, and decreased net trading margin on contracts accounted for under SFAS No. 133, partially offset by increased revenues for Avista Energy Canada. Revenues from Avista Advantage increased $2.2 million to $8.2 million primarily as a result of customer growth. Revenues from the Other business segment increased $0.8 million to $4.8 million primarily as a result of increased sales at AM&D.

Total resource costs increased $31.0 million for the three months ended September 30, 2005 compared to the three months ended September 30, 2004. Resource costs for Avista Utilities increased $15.8 million primarily due to an increase in purchased power and natural gas costs, as well as increased net amortization of deferred power costs. The increase in purchased power and natural gas costs was due to an increase in prices, as well as an increase in the volume of natural gas purchases. Avista Utilities’ resource costs reflect the expense of $8.2 million under the ERM dead band in Washington for the third quarter of 2005. The entire $9.0 million ERM dead band was expensed in 2004 prior to the third quarter. Resource costs for Energy Marketing and Resource Management decreased $7.6 million primarily due to decreased resource costs under the Agency Agreement with Avista Utilities as natural gas procurement operations were transitioned to Avista Utilities effective April 1, 2005, partially offset by increased resource costs for Avista Energy Canada.

Intersegment eliminations, which decrease both operating revenues and resource costs, were $22.9 million for the three months ended September 30, 2004. There were not any intersegment eliminations for operating revenues and resource costs for the three months ended September 30, 2005 as the Agency Agreement between Avista Utilities and Avista Energy was terminated effective April 1, 2005.

Operations and maintenance expenses decreased $4.1 million for the three months ended September 30, 2005 compared to the three months ended September 30, 2004 primarily due to asset impairment charges of $5.1 million recorded at Avista Power (Energy Marketing and Resource Management segment) and the disallowance by the IPUC of $2.4 million of capitalized utility plant costs at Avista Utilities during the third quarter of 2004. This was partially offset by increased operations and maintenance expenses for Avista Utilities (excluding the effect of the IPUC related write-off in 2004) and Avista Advantage.

Administrative and general expenses decreased $3.3 million for the three months ended September 30, 2005 compared to the three months ended September 30, 2004 primarily due to decreased expenses for Avista Utilities, Energy Marketing and Resource Management and the Other business segment. The decrease for Energy Marketing and Resource Management was primarily a result of decreased compensation expense. The decrease for the Other business segment was primarily due to the accrual of an environmental liability at Avista Development during the third quarter of 2004.

Depreciation and amortization increased $0.9 million for the three months ended September 30, 2005 compared to the three months ended September 30, 2004 primarily due to utility plant additions at Avista Utilities and the resulting increase in depreciation expense.

Interest expense increased $0.4 million for the three months ended September 30, 2005 compared to the three months ended September 30, 2004 primarily due to interest rate adjustments on variable rate debt to affiliated trusts.

Other income-net increased $1.2 million for the three months ended September 30, 2005 compared to the three months ended September 30, 2004 primarily due to an increase in interest income, including interest on power and natural gas deferrals.

The income tax benefit decreased $0.3 million for the three months ended September 30, 2005 compared to the three months ended September 30, 2004, primarily due to decreased loss before income taxes.

Nine months ended September 30, 2005 compared to the nine months ended September 30, 2004

Net income was $19.8 million for the nine months ended September 30, 2005 compared to $12.6 million for the nine months ended September 30, 2004. This increase was due to the improved performance of Avista Utilities, as well as Avista Advantage and the Other business segment. This was partially offset by a net loss for Avista Energy (Energy Marketing and Resource Management segment).

Net income for Avista Utilities was $35.6 million for the nine months ended September 30, 2005, compared to $12.6 million for the nine months ended September 30, 2004. The increase for Avista Utilities was due to an increase in

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gross margin as a result of general rate increases and the $4.1 million pre-tax gain from the sale of the South Lake Tahoe natural gas properties in 2005, as well as the IPUC related write-offs recorded during the third quarter of 2004. This was partially offset by warmer weather in the Washington and Idaho service territories during the first quarter, which decreased use per customer.

Energy Marketing and Resource Management incurred a net loss of $16.9 million for the nine months ended September 30, 2005 compared to net income of $3.8 million for the nine months ended September 30, 2004. The net loss for the nine months ended September 30, 2005 was primarily due to losses in Avista Energy’s natural gas portfolio during the first and third quarters of 2005 with a significant portion of the loss due to the accounting for the management of natural gas inventory.

Net income for Avista Advantage was $3.0 million for the nine months ended September 30, 2005 compared to net income of less than $0.1 million for the nine months ended September 30, 2004. The change was primarily due to an increase in operating revenues from customer growth, as well as the settlement of an employment contract during 2004.

The Other business segment incurred a net loss of $2.0 million for the nine months ended September 30, 2005 compared to a net loss of $3.4 million (excluding the cumulative effect of accounting change) for the nine months ended September 30, 2004. The decrease in the net loss was primarily due to the accrual of environmental liabilities at Avista Development during 2004.

Total revenues increased $90.0 million for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. Avista Utilities’ revenues increased $91.0 million due to increases in both electric and natural gas revenues. The increase in natural gas revenues was primarily due to increased natural gas wholesale sales and natural gas rate increases implemented during 2004. The increase in electric revenues primarily reflects an increase in wholesale revenues, partially offset by a decrease in sales of fuel and a slight decrease in retail revenues. Revenues from Energy Marketing and Resource Management decreased $98.3 million primarily due to decreased revenues under the Agency Agreement with Avista Utilities as natural gas procurement operations were transitioned to Avista Utilities effective April 1, 2005, and decreased net trading margin on contracts accounted for under SFAS No. 133, partially offset by increased revenues for Avista Energy Canada. Revenues from Avista Advantage increased $6.3 million to $23.1 million primarily as a result of customer growth. Revenues from the Other business segment increased $0.8 million to $13.5 million primarily as a result of increased sales at AM&D.

Total resource costs increased $85.4 million for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. Resource costs for Avista Utilities increased $54.4 million primarily due to an increase in purchased power and natural gas costs, as well as increased net amortization of deferred power costs. The increase in purchased power and natural gas costs was primarily due to an increase in prices, as well as an increase in the volume of natural gas purchases. Resource costs for Energy Marketing and Resource Management decreased $59.2 million primarily due to decreased resource costs under the Agency Agreement with Avista Utilities as natural gas procurement operations were transitioned to Avista Utilities effective April 1, 2005, partially offset by increased resource costs for Avista Energy Canada.

Intersegment eliminations, which decrease both operating revenues and resource costs, were $19.4 million for the nine months ended September 30, 2005 compared to $109.6 million for the nine months ended September 30, 2004, representing decreased purchases of natural gas as the Agency Agreement between Avista Utilities and Avista Energy was terminated effective April 1, 2005.

Operations and maintenance expenses decreased $3.0 million for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004 primarily due to asset impairment charges of $5.1 million recorded at Avista Power (Energy Marketing and Resource Management segment) and the disallowance by the IPUC of $2.4 million of capitalized utility plant costs at Avista Utilities during 2004. This was partially offset by increased operations and maintenance expenses for Avista Utilities (excluding the effect of the IPUC related write-off in 2004) and Avista Advantage.

Administrative and general expenses decreased $4.3 million for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004 primarily due to decreased expenses for Energy Marketing and Resource Management, Avista Advantage and the Other business segment. The decrease for Energy Marketing and Resource Management was primarily a result of decreased compensation expense. The decrease for Avista Advantage was due to the settlement of an employment contract during 2004. The decrease for the Other business segment was due to the accrual of environmental liabilities during 2004.

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Depreciation and amortization increased $6.7 million for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004 due in part to utility plant additions at Avista Utilities and the resulting increase in depreciation expense. This was also due to a correction at Avista Utilities for overstated depreciation expense in prior periods recorded during the first quarter of 2004.

Interest expense decreased $0.7 million for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004 primarily due to a decrease in the effective borrowing rate as a result of previous debt issuances and repurchases.

Income taxes increased $1.9 million for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004, primarily due to increased income before income taxes. The effective tax rate was 36.5 percent for the nine months ended September 30, 2005 compared to 42.0 percent for the nine months ended September 30, 2004. The decrease in the effective tax rate was partially due to tax credits for the Kettle Falls Plant that the Company began receiving the benefit from in 2005.

During the nine months ended September 30, 2004, the Other business segment recorded as a cumulative effect of accounting change a charge of $0.5 million related to the implementation of FIN 46, which required Avista Ventures to consolidate several minor entities.

Avista Utilities

Three months ended September 30, 2005 compared to the three months ended September 30, 2004

Avista Utilities had a net loss of $1.8 million for the three months ended September 30, 2005 compared to a net loss of $7.3 million for the three months ended September 30, 2004. Avista Utilities’ income from operations was $17.3 million for the three months ended September 30, 2005 compared to $8.4 million for the three months ended September 30, 2004. The decrease in the net loss was primarily due to the IPUC related write-offs of $14.7 million ($9.6 million, net of taxes) during the third quarter of 2004, partially offset by the absorption of $8.2 million of power costs under the ERM dead band during the third quarter of 2005. Excluding the effect of the ERM dead band in 2005 and the IPUC related write-offs in 2004, the improvement in results was primarily due to increased gross margin (operating revenues less resource costs) as a result of general rate increases.

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

	Electric				Natural Gas				Total
	2005		2004		2005		2004		2005		2004
Operating revenues	$	173,210	$	164,896	$	48,499	$	33,696	$	221,709	$	198,592
Resource costs		92,061		89,140		34,450		21,604		126,511		110,744
Gross margin	$	81,149	$	75,756	$	14,049	$	12,092	$	95,198	$	87,848

Avista Utilities’ operating revenues increased $23.1 million and resource costs increased $15.8 million, which resulted in an increase of $7.3 million in gross margin for the third quarter of 2005 as compared to the third quarter of 2004. The gross margin on electric sales increased $5.4 million and the gross margin on natural gas sales increased $1.9 million. The increase in the gross margin on electric sales was primarily due to the IPUC’s disallowance of $12.3 million in deferred power costs during the third quarter of 2004. In addition, the increase in electric gross margin was partially due to the Idaho electric general rate increase implemented in September 2004, as well as customer growth. The increase in electric gross margin was partially offset by an increase in electric resource costs as compared to the amount included in base retail rates and the expense of $8.2 million under the ERM dead band in Washington during the third quarter of 2005, which included the reversal of the $0.7 million benefit from the first half of 2005. This was primarily due to high fuel costs, purchased power expenses and seasonally low hydroelectric generation. In 2004, the entire $9.0 million ERM dead band was absorbed during the first half of the year. As such, 90 percent of all power costs above the amount included in base retail rates were deferred during the third quarter of 2004. The increase in the gross margin on natural gas sales was primarily due to the Idaho natural gas general rate increase implemented in September 2004 and the Washington natural gas general rate increase implemented in November 2004, as well as customer growth in Washington, Idaho and Oregon. The effects of general rate increases and customer growth were partially offset by the sale of the South Lake Tahoe properties in April 2005.

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

	Electric Operating Revenues				Electric Energy MWh sales
	2005		2004		2005	2004
Residential	$	45,152	$	46,628	731	755
Commercial		51,816		53,013	769	777
Industrial		23,782		23,709	541	542
Public street and highway lighting		1,242		1,206	6	6
Total retail		121,992		124,556	2,047	2,080
Wholesale		40,260		15,012	597	326
Sales of fuel		6,869		19,569	—	—
Other		4,089		5,759	—	—
Total	$	173,210	$	164,896	2,644	2,406

Retail electric revenues decreased $2.6 million for the three months ended September 30, 2005 from the three months ended September 30, 2004. This decrease was primarily due to a decrease in total MWhs sold (decreased revenues $2.0 million) and partially due to a decrease in revenue per MWh (decreased revenues $0.6 million). The decrease in total MWhs sold was primarily due to cooler weather and decreased air conditioning loads partially offset by customer growth. Total cooling degree days at Spokane, Washington for third quarter of 2005 decreased as compared to third quarter of 2004 with both periods warmer than normal. As such, electric loads and revenues were negatively affected by weather when comparing third quarter 2005 and 2004 results. In September 2004, a general electric rate increase was implemented in Idaho. However, this was almost entirely offset by a decrease in the PCA surcharge, such that the net increase in rates to Idaho customers was only 1.9 percent. Although the general rate case increased gross margin, income from operations and net income, it did not have a significant effect on operating revenues.

Wholesale electric revenues increased $25.2 million primarily due to an increase in wholesale sales volumes and partially due to an increase in wholesale sales prices. The increase in wholesale sales volumes reflects added generation capacity and lower than anticipated retail loads, which resulted in excess resources that were sold in the wholesale market.

Sales of fuel decreased $12.7 million as a greater percentage of fuel purchases were used in generation. Sales of fuel represents natural gas that was not used for generation when electric wholesale market prices were generally below the cost of operating the natural gas-fired thermal generating units.

Other electric revenues decreased $1.7 million primarily as a result of decreased transmission revenues.

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

	Natural Gas Operating Revenues				Natural Gas Therms Delivered
	2005		2004		2005	2004
Residential	$	18,337	$	17,327	14,601	15,732
Commercial		12,052		11,706	12,144	13,764
Industrial		2,460		2,043	3,078	2,997
Total retail		32,849		31,076	29,823	32,493
Wholesale		13,255		—	18,490	—
Transportation		1,466		1,748	32,110	32,633
Other		929		872	18	1,833
Total	$	48,499	$	33,696	80,441	66,959

Natural gas revenues increased $14.8 million for the three months ended September 30, 2005 from the three months ended September 30, 2004 due to an increase in both wholesale and retail natural gas revenues. The increase in wholesale revenues reflects sales of excess resources acquired as part of the natural gas procurement process that was implemented at Avista Utilities effective April 1, 2005 with the termination of the Agency Agreement with Avista Energy. The $1.8 million increase in retail natural gas revenues was primarily due to an increase in retail rates (increased revenues $4.7 million), partially offset by a decrease in volumes (decreased revenues $2.9 million). During September through November of 2004, retail rates for natural gas were increased in response to an increase

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in current and projected natural gas costs. In September 2004, a general natural gas rate increase was implemented in Idaho. In November 2004, a general natural gas rate increase was implemented in Washington. The decrease in total therms sold was primarily due to the sale of the South Lake Tahoe operations, partially offset by customer growth and slightly colder weather in the Washington, Idaho and Oregon service territories during September 2005.

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

	Electric Customers		Natural Gas Customers
	2005	2004	2005	2004
Residential	293,668	287,912	258,109	267,285
Commercial	37,239	36,780	31,127	31,831
Industrial	1,411	1,421	310	315
Public street and highway lighting	425	414	—	—
Total retail	332,743	326,527	289,546	299,431
Wholesale	46	45	10	—
Transportation	—	—	97	76
Total customers	332,789	326,572	289,653	299,507

The following table presents Avista Utilities’ heating and cooling degree days for the three months ended September 30:

	2005		2004
Heating degree days (1):
Spokane, Washington actual	262		254
Spokane, Washington 30 year average (2)	282		282
Percent of average	93	%	90	%
Medford, Oregon actual	63		61
Medford, Oregon 30 year average (2)	139		139
Percent of average	45	%	44	%
Cooling degree days (3):
Spokane, Washington actual	364		475
Spokane, Washington 30 year average (2)	335		335
Percent of average	109	%	142	%

(1) Heating degree days are a common measure used in the utility industry to analyze the demand for natural gas and electricity during the heating season (generally the first and fourth quarters of a fiscal year and to a lesser extent the second quarter). Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of the high and low temperatures for a day falls below 65 degrees Fahrenheit (degree days below historic indicate warmer than average temperatures).

(2) Computed for the period from 1971 through 2000.

(3) Cooling degree days are used to analyze the demand for electricity during the summer (generally the third quarter) and indicate when a customer would use electricity for air conditioning. Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of the high and low temperatures for a day exceeds 65 degrees Fahrenheit (degree days above historic indicate warmer than average temperatures).

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

	2005			2004
Electric resource costs:
Power purchased	$	54,935		$	44,444
Power cost amortizations (deferrals), net		4,480			(1,437	)
Fuel for generation		26,173			9,263
Other fuel costs		5,271			22,289
Other regulatory amortizations, net		(1,271	)		(151	)
Other electric resource costs		2,473			14,732
Total electric resource costs		92,061			89,140
Natural gas resource costs:
Natural gas purchased		41,475			23,133
Natural gas deferrals, net of amortization		(7,291	)		(1,899	)
Other regulatory amortizations, net		266			370
Total natural gas resource costs		34,450			21,604
Total resource costs	$	126,511		$	110,744

Power purchased for the three months ended September 30, 2005 increased $10.5 million compared to the three months ended September 30, 2004 due to an increase in the price of power purchases (increased costs $11.1 million), partially offset by a decrease in the volume of power purchases (decreased costs $0.6 million).

Net amortization of deferred power costs was $4.5 million for the three months ended September 30, 2005 compared to net deferrals of $1.4 million for the three months ended September 30, 2004. During the three months ended September 30, 2005, Avista Utilities recovered (collected as revenue) $6.2 million of previously deferred power costs in Washington and $1.1 million in Idaho. There was a decrease in the recovery of previously deferred power costs in Idaho as compared to the three months ended September 30, 2004, which was primarily due to the reduction of the PCA rate surcharge. During the three months ended September 30, 2005, Avista Utilities deferred $2.8 million of power costs in Idaho. Avista Utilities did not defer any power costs in Washington during the three months ended September 30, 2005 as power costs were within the $9.0 million ERM dead band.

Fuel for generation for the three months ended September 30, 2005 increased $16.9 million compared to the three months ended September 30, 2004 due to an increase in fuel prices and greater use of thermal generation, including the addition of the remaining interest in Coyote Springs 2.

Other fuel costs for the three months ended September 30, 2005 decreased $17.0 million compared to the three months ended September 30, 2004. This natural gas fuel was sold with the associated revenues reflected as sales of fuel. Revenues from selling the natural gas exceeded other fuel costs. This excess revenue is accounted for under the ERM in Washington and the PCA in Idaho. The decrease in other fuel costs was primarily due to a greater percentage of fuel used in generation.

Other electric resource costs for the three months ended September 30, 2005 decreased $12.3 million compared to the three months ended September 30, 2004 primarily due to the IPUC’s disallowance of certain deferred power costs in 2004.

The expense for natural gas purchased for the three months ended September 30, 2005 increased $18.3 million compared to the three months ended September 30, 2004 due to an increase in the cost of natural gas (increased costs $5.2 million) and an increase in total therms purchased (increased costs $13.1 million). The increase in total therms purchased is consistent with an increase in wholesale sales as part of the balancing of loads and resources with the natural gas procurement process. During the three months ended September 30, 2005, Avista Utilities had $7.3 million of net deferrals of natural gas costs compared to $1.9 million of net deferrals for the three months ended September 30, 2004, reflecting higher natural gas prices.

Nine months ended September 30, 2005 compared to the nine months ended September 30, 2004

Net income for Avista Utilities was $35.6 million for the nine months ended September 30, 2005 compared to $12.6 million for the nine months ended September 30, 2004. Avista Utilities’ income from operations was $117.8 million for the nine months ended September 30, 2005 compared to $83.8 million for the nine months ended September 30, 2004. This increase was primarily a result of increased gross margin (operating revenues less resource costs) due to general rate increases and IPUC related write-offs of $14.7 million ($9.6 million, net of taxes) in 2004, as well as the

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$4.1 million pre-tax gain related to the sale of Avista Utilities’ South Lake Tahoe natural gas properties. This was partially offset by decreased use per customer in the Washington and Idaho service territories due to warmer weather during the first quarter of 2005 as compared to the first quarter of 2004, as well as an increase in depreciation expense.

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

	Electric				Natural Gas				Total
	2005		2004		2005		2004		2005		2004
Operating revenues	$	519,002	$	488,411	$	260,741	$	200,332	$	779,743	$	688,743
Resource costs		235,012		231,338		185,934		135,175		420,946		366,513
Gross margin	$	283,990	$	257,073	$	74,807	$	65,157	$	358,797	$	322,230

Avista Utilities’ operating revenues increased $91.0 million and resource costs increased $54.4 million, which resulted in an increase of $36.6 million in gross margin for the nine months ended September 30, 2005 as compared to the nine months ended September 30, 2004. The gross margin on electric sales increased $26.9 million and the gross margin on natural gas sales increased $9.7 million. The increase in electric gross margin was partially due to the IPUC’s disallowance of $12.3 million in deferred power costs in 2004. The increase in electric gross margin was also due to the Idaho electric general rate increase implemented in September 2004 as well as customer growth, partially offset by warmer weather during the first quarter of 2005 as compared to the first quarter of 2004. The increase in the gross margin on natural gas sales was primarily due to the Idaho natural gas general rate increase implemented in September 2004 and the Washington natural gas general rate increase implemented in November 2004, colder weather in the Oregon service territory, as well as customer growth. The effects of general rate increases and customer growth were partially offset by warmer weather in the Washington and Idaho service territories during the first quarter of 2005 and the sale of the South Lake Tahoe properties in April 2005.

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

	Electric Operating Revenues				Electric Energy MWh sales
	2005		2004		2005	2004
Residential	$	149,986	$	151,078	2,421	2,408
Commercial		150,615		151,425	2,217	2,182
Industrial		68,899		68,054	1,570	1,567
Public street and highway lighting		3,711		3,613	19	19
Total retail		373,211		374,170	6,227	6,176
Wholesale		100,737		40,514	1,959	1,079
Sales of fuel		33,122		58,926	—	—
Other		11,932		14,801	—	—
Total	$	519,002	$	488,411	8,186	7,255

Retail electric revenues decreased $1.0 million for the nine months ended September 30, 2005 from the nine months ended September 30, 2004. This decrease was primarily due to a decrease in revenue per MWh (decreased revenues $4.0 million), partially offset by an increase in total MWhs sold (increased revenues $3.0 million). The increase in total MWhs sold was primarily due to customer growth, partially offset by warmer weather during the first quarter heating season and colder weather during the third quarter cooling season. Total heating degree days at Spokane, Washington for the nine months ended September 30, 2005 decreased as compared to the same period of 2004 with both periods warmer than normal. Total cooling degree days at Spokane, Washington for the nine months ended September 30, 2005 decreased as compared to the same period of 2004 with both periods warmer than normal. As such, electric loads and revenues were negatively affected by weather when comparing 2005 and 2004 results. In September 2004, a general electric rate increase was implemented in Idaho. However, this was almost entirely offset by a decrease in the PCA surcharge, such that the net increase in rates to Idaho customers was only 1.9 percent. Although the general rate case increased gross margin, income from operations and net income, it did not have a significant effect on operating revenues.

Wholesale electric revenues increased $60.2 million primarily due to an increase in wholesale sales volumes and partially due to an increase in wholesale sales prices. The increase in wholesale sales volumes reflects added generation capacity, earlier-than-normal and better-than-anticipated runoff to hydroelectric generating assets during the first half of 2005 and lower than anticipated retail loads, which resulted in excess resources that were sold in the wholesale market.

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Sales of fuel decreased $25.8 million as a greater percentage of fuel purchases were used in generation. Sales of fuel represents natural gas that was not used for generation when electric wholesale market prices were generally below the cost of operating the natural gas-fired thermal generating units.

Other electric revenues decreased $2.9 million primarily as a result of decreased transmission revenues.

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

	Natural Gas Operating Revenues				Natural Gas Therms Delivered
	2005		2004		2005	2004
Residential	$	140,491	$	119,993	128,042	128,971
Commercial		76,550		65,507	79,212	80,326
Industrial		7,674		6,126	9,506	9,111
Total retail		224,715		191,626	216,760	218,408
Wholesale		27,046		116	41,388	245
Transportation		5,899		6,036	115,283	110,001
Other		3,081		2,554	348	2,676
Total	$	260,741	$	200,332	373,779	331,330

Natural gas revenues increased $60.4 million for the nine months ended September 30, 2005 from the nine months ended September 30, 2004 due to an increase in retail natural gas revenues and wholesale natural gas revenues. The increase in wholesale revenues reflects sales of excess resources acquired as part of the natural gas procurement process that was implemented at Avista Utilities effective April 1, 2005. The $33.1 million increase in retail natural gas revenues was primarily due to an increase in retail rates (increased revenues $34.8 million), partially offset by a decrease in volumes (decreased revenues $1.7 million). During September through November of 2004, retail rates for natural gas were increased in response to an increase in current and projected natural gas costs. In September and November 2004, general natural gas rate increases were implemented in Idaho and Washington, respectively. The decrease in total therms sold was primarily due to warmer weather in the Washington and Idaho service territories and the sale of the South Lake Tahoe properties, partially offset by customer growth and colder weather in the Oregon service territory.

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

	Electric Customers		Natural Gas Customers
	2005	2004	2005	2004
Residential	293,072	287,477	266,008	267,423
Commercial	37,198	36,650	31,757	31,847
Industrial	1,411	1,415	309	312
Public street and highway lighting	419	419	—	—
Total retail	332,100	325,961	298,074	299,582
Wholesale	44	41	8	1
Transportation	—	—	93	81
Total customers	332,144	326,002	298,175	299,664

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The following table presents Avista Utilities’ heating and cooling degree days for the nine months ended September 30:

	2005		2004
Heating degree days (1):
Spokane, Washington actual	3,872		3,957
Spokane, Washington 30 year average (2)	4,201		4,201
Percent of average	92	%	94	%
Medford, Oregon actual	2,507		2,221
Medford, Oregon 30 year average (2)	2,748		2,748
Percent of average	91	%	81	%
Cooling degree days (3):
Spokane, Washington actual	409		571
Spokane, Washington 30 year average (2)	393		393
Percent of average	104	%	145	%

(1) Heating degree days are a common measure used in the utility industry to analyze the demand for natural gas and electricity during the heating season (generally the first and fourth quarters of a fiscal year and to a lesser extent the second quarter). Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of the high and low temperatures for a day falls below 65 degrees Fahrenheit (degree days below historic indicate warmer than average temperatures).

(2) Computed for the period from 1971 through 2000.

(3) Cooling degree days are used to analyze the demand for electricity during the summer (generally the third quarter) and indicate when a customer would use electricity for air conditioning. Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of the high and low temperatures for a day exceeds 65 degrees Fahrenheit (degree days above historic indicate warmer than average temperatures).

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

	2005			2004
Electric resource costs:
Power purchased	$	120,094		$	111,398
Power cost amortizations, net of deferrals		21,701			10,643
Fuel for generation		61,632			20,790
Other fuel costs		30,249			67,284
Other regulatory amortizations, net		(5,134	)		(769	)
Other electric resource costs		6,470			21,992
Total electric resource costs		235,012			231,338
Natural gas resource costs:
Natural gas purchased		189,064			142,020
Natural gas deferrals, net of amortizations		(5,499	)		(9,697	)
Other regulatory amortizations, net		2,369			2,852
Total natural gas resource costs		185,934			135,175
Total resource costs	$	420,946		$	366,513

Power purchased for the nine months ended September 30, 2005 increased $8.7 million compared to the nine months ended September 30, 2004 due to an increase in the price of power purchases (increased costs $12.2 million), partially offset by a decrease in the volume of power purchases (decreased costs $3.5 million). The decrease in the volume of power purchases was primarily due to increased thermal generation. As such, Avista Utilities purchased less power on the wholesale market to meet its load requirements.

Net amortization of deferred power costs was $21.7 million for the nine months ended September 30, 2005 compared to $10.6 million for the nine months ended September 30, 2004. During the nine months ended September 30, 2005, Avista Utilities recovered (collected as revenue) $19.7 million of previously deferred power costs in Washington and $4.6 million in Idaho. There was a decrease in the recovery of previously deferred power costs in Idaho as compared to the nine months ended September 30, 2004, which was primarily due to the reduction of the PCA rate surcharge. During the nine months ended September 30, 2005, Avista Utilities deferred $2.5 million of power costs in Idaho. Avista Utilities did not defer any power costs in Washington during the nine months ended September 30, 2005 as power costs were within the $9.0 million ERM dead band.

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Fuel for generation for the nine months ended September 30, 2005 increased $40.8 million compared to the nine months ended September 30, 2004 due to an increase in fuel prices and greater use of thermal generation, including the addition of the remaining interest in Coyote Springs 2.

Other fuel costs for the nine months ended September 30, 2005 decreased $37.0 million compared to the nine months ended September 30, 2004. This natural gas fuel was sold with the associated revenues reflected as sales of fuel. Revenues from selling the natural gas exceeded other fuel costs. This excess revenue is accounted for under the ERM in Washington and the PCA in Idaho. The decrease in other fuel costs was primarily due to a greater percentage of fuel used in generation.

Other electric resource costs for the nine months ended September 30, 2005 decreased $15.5 million compared to the nine months ended September 30, 2004 primarily due to the IPUC’s disallowance of $12.3 million of deferred power costs in 2004.

The expense for natural gas purchased for the nine months ended September 30, 2005 increased $47.0 million compared to the nine months ended September 30, 2004 due to an increase in the cost of natural gas (increased costs $20.1 million) and an increase in total therms purchased (increased costs $26.9 million). The increase in total therms purchased is consistent with an increase in wholesale sales as part of the balancing of loads and resources with the natural gas procurement process. During the nine months ended September 30, 2005, Avista Utilities had $5.5 million of net deferrals of natural gas costs compared to $9.7 million of net deferrals for the nine months ended September 30, 2004.

Energy Marketing and Resource Management

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

Avista Energy’s earnings are primarily derived from the following activities:

• Optimization of generation assets owned by other entities.

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

• Purchasing and storing natural gas for later sales to seek gains from seasonal price variations and demand peaks.

• Transmitting electricity and transporting natural gas between locations, including moving energy from lower priced/demand regions to higher priced/demand markets and hub locations within the WECC.

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

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

The following table presents Avista Energy’s net realized gains and net unrealized losses for the three and nine months ended September 30 (dollars in thousands):

	Three months ended September 30,						Nine months ended September 30,
	2005			2004			2005			2004
Net realized gains	$	8,244		$	10,748		$	20,731		$	31,302
Net unrealized losses		(17,832	)		(3,131	)		(35,129	)		(6,574	)
Total gross margin (operating revenues less resource costs)	$	(9,588	)	$	7,617		$	(14,398	)	$	24,728

Energy Marketing and Resource Management had a net loss of $8.3 million for the three months ended September 30, 2005, compared to a net loss of $1.2 million for the three months ended September 30, 2004. Energy Marketing and Resource Management’s net loss was $16.9 million for the nine months ended September 30, 2005, compared to net income of $3.8 million for the nine months ended September 30, 2004. The net loss for the third quarter of 2004 was due to asset impairment charges recorded at Avista Power of $5.1 million ($3.3 million, net of taxes).

A significant portion of the net loss for Avista Energy was due to the effects of differences between the economic management and the required accounting for certain energy contracts and physical assets under management, particularly with respect to natural gas inventory, as further discussed below. However, part of the loss was due to

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changes in natural gas prices relative to the positions that Avista Energy has taken in the natural gas market. While Avista Energy’s portfolio is within its limits and in accordance with its risk management practices, losses can and do occur when the market moves contrary to its positions, which has occurred during 2005. Increases in natural gas prices had a negative effect on Avista Energy’s positions and net income for the three and nine months ended September 30, 2005. As markets moved counter to certain contracts, Avista Energy acted to adjust its position consistent with established risk management policies. This reduced the market risk; however, it had the effect of locking in losses on certain natural gas positions during the first and third quarters of 2005. These losses can be magnified when there are large unforeseen fluctuations or disruptions in the market, such as those caused by the hurricanes in the southeastern United States during the third quarter.

Avista Energy continued to produce positive results on the power side of its business, which includes trading, marketing and managing the output and availability of generation assets owned by other entities.

Total assets for the Energy Marketing and Resource Management segment increased $1,592.6 million from December 31, 2004 primarily as a result of the increase in commodity prices (particularly natural gas) and the impact on Avista Energy’s derivative commodity assets.

Analysis of differences in the economic management and the required accounting for certain contracts and physical assets under management

The operations of Avista Energy are managed on an economic basis reflecting all contracts and assets under management at estimated market value, which is different from the required accounting for certain contracts and physical assets under management. Under SFAS No. 133, certain contracts, which are considered derivatives and accounted for at market value, economically hedge other contracts and physical assets under management, which are not considered derivatives and are generally accounted for at the lower of cost or market value. The accounting treatment does not impact the underlying cash flows or economics of these transactions. These differences are generally reversed in future periods as market values change or the contracts are settled or realized. These differences primarily relate to Avista Energy’s management of natural gas inventory and resulting impact of the natural gas storage cycle, as well as Avista Energy’s control of natural gas-fired generation through a power purchase agreement.

Avista Energy is affected by earnings volatility associated with the natural gas storage cycle, which runs annually from April through March of the next year. Generally, injections of natural gas into storage inventory take place in the summer months and natural gas is withdrawn from storage in the winter months. Avista Energy economically hedges the value of natural gas storage with financial and physical sales, effectively locking in a margin on storage. However, accounting rules require the natural gas storage to be carried at the lower of cost or market, while the forward sales contracts (which are derivatives) are marked-to-market using forward price curves. Changes in forward price curves result in income or losses on the derivative sales contracts, but generally do not affect the recorded value for natural gas inventory. Therefore, if Avista Energy enters into a forward contract to sell natural gas as a hedge against the value of natural gas in storage, and market prices subsequently increase, a loss with respect to the forward contract is recorded in net income. While the market value of the natural gas inventory has also increased, the natural gas inventory remains recorded at the lower of cost or market value. During the nine months ended September 30, 2005, increases in the market price of natural gas and changes in inventory balances had a negative effect on net income of $11.7 million with respect to Avista Energy’s economic management of natural gas inventory. During the nine months ended September 30, 2004, this activity and changes in natural gas prices had a negative effect on net income of $2.6 million. During the third quarter of 2005, changes in the market price of natural gas and changes in inventory balances had a negative effect on net income of $8.0 million with respect to Avista Energy’s economic management of natural gas inventory. During the third quarter of 2004, this activity and changes in natural gas prices had a negative effect on net income of $1.8 million. The difference should reverse when the transactions are settled or the natural gas has been withdrawn from storage, which is forecasted to occur during the first quarter of 2006. However, the difference could increase or decrease prior to the settlement of the transactions depending on changes in commodity prices.

Avista Energy controls natural gas-fired generation through a power purchase agreement related to the Lancaster Project. The power purchase agreement gives Avista Energy the right to purchase natural gas for generation, and convert to electricity for a fixed fee. Avista Energy has economically hedged the value of this power purchase agreement by entering into contracts to buy and sell natural gas and electricity during certain time periods in the future. Although the power purchase agreement is not a derivative and not marked-to-market, the contracts to buy and sell natural gas and electricity are derivatives that are recorded at estimated market value. Where possible, Avista Energy has designated the natural gas and electricity contracts as accounting hedges in accordance with SFAS No. 133

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in order to reduce the earnings volatility associated with these combinations of accounting treatments. However, not all of these contracts qualify for hedge accounting. Avista Energy will continue to recognize changes in fair value of those contracts in earnings as unrealized gains and losses. In addition, the ineffective portion of the change in the forward value of qualifying hedges will continue to be recognized in earnings. Similar to natural gas inventory, the power purchase agreement is managed as if it is recorded at estimated market value. During the nine months ended September 30, 2005, changes in natural gas and electricity prices for the future delivery periods in which the contract had been economically hedged (but not hedged in accordance with SFAS No. 133) had a negative effect on net income of approximately $0.8 million. During the nine months ended September 30, 2004, this activity and changes in prices had a negative effect on net income of approximately $1.2 million. During the third quarter of 2005, changes in natural gas and electricity prices for the future delivery periods in which the contract had been economically hedged (but not hedged in accordance with SFAS No. 133) had a negative effect on net income of approximately $0.9 million. During the third quarter of 2004, this activity and changes in prices had a negative effect on net income of approximately $0.7 million.

Analysis of operating revenues, resource costs and gross margin for the three months ended September 30, 2005 compared to the three months ended September 30, 2004

Operating revenues decreased $24.8 million and resource costs decreased $7.6 million for the three months ended September 30, 2005 as compared to the three months ended September 30, 2004 resulting in a decrease in gross margin of $17.2 million. Avista Energy’s gross margin (operating revenues less resource costs) was a loss of $9.6 million for the three months ended September 30, 2005 compared to a gain of $7.6 million for the three months ended September 30, 2004. The decrease in gross margin was due to a decrease in trading margins, as well as the negative effects of accounting for certain contracts and physical assets under management, particularly natural gas inventory, as described above.

Net realized gains decreased to $8.2 million for the three months ended September 30, 2005 from $10.7 million for the three months ended September 30, 2004. Net realized gains represent the net gains on contracts that have settled. The decrease in net realized gains was primarily due to an increase in net losses on physical natural gas transactions, an increase in transmission and transportation fees, partially offset by an increase in the net gains on settled financial transactions and physical electric transactions. The total mark-to-market adjustment for Energy Marketing and Resource Management was a net unrealized loss of $17.8 million for the three months ended September 30, 2005 compared to a net unrealized loss of $3.1 million for the three months ended September 30, 2004. The increase in the net unrealized loss was primarily due to the impact of increases in natural gas prices on certain positions, including positions associated with the management of natural gas inventory.

Analysis of operating revenues, resource costs and gross margin for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004

Operating revenues decreased $98.3 million and resource costs decreased $59.2 million for the nine months ended September 30, 2005 as compared to the nine months ended September 30, 2004 resulting in a decrease in gross margin of $39.1 million. Avista Energy’s gross margin (operating revenues less resource costs) was a loss of $14.4 million for the nine months ended September 30, 2005 compared to a gain of $24.7 million for the nine months ended September 30, 2004. The decrease in gross margin was primarily due to the increase in natural gas prices and the resulting impact on Avista Energy’s natural gas positions, including the effect on the accounting for natural gas inventory described above.

Net realized gains decreased to $20.7 million for the nine months ended September 30, 2005 from $31.3 million for the nine months ended September 30, 2004. The decrease in net realized gains was due to increased net losses on physical natural gas transactions, decreased net gains on physical electric transactions and increased transmission and transportation fees, partially offset by increased net gains on settled financial transactions. The total mark-to-market adjustment for Energy Marketing and Resource Management was a net unrealized loss of $35.1 million for the nine months ended September 30, 2005 compared to a net unrealized loss of $6.6 million for the nine months ended September 30, 2004. The net unrealized loss for the nine months ended September 30, 2005 was primarily due to realization of physical electric transactions and natural gas price movements that were unfavorable to Avista Energy’s positions including positions associated with the management of natural gas inventory.

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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, 2005 (dollars in thousands):

	Electric Assets net of Liabilities			Natural Gas Assets net of Liabilities			Total Unrealized Gain (Loss)
Fair value of contracts as of December 31, 2004	$	58,965		$	11,341		$	70,306
Less contracts settled during 2005 (1)		(58,030	)		37,299			(20,731	)
Fair value of new contracts when entered into during 2005 (2)		—			—			—
Change in fair value due to changes in valuation techniques (3)		—			—			—
Change in fair value attributable to market prices and other market changes		(11,855	)		(2,662	)		(14,517	)
Fair value of contracts as of September 30, 2005	$	(10,920	)	$	45,978		$	35,058

(1) Contracts settled during 2005 include those contracts that were open in 2004 but settled during 2005 as well as new contracts entered into and settled during 2005. Amount represents net realized gains associated with these settled transactions.

(2) Avista Energy did not enter into any origination transactions during 2005 in which dealer profit or mark-to-market gain or loss was recorded at inception.

(3) During 2005, Avista Energy did not experience a change in fair value due to changes in valuation techniques.

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, 2005 (dollars in thousands):

	Less than one year			Greater than one and less than three years			Greater than three and less than five years			Greater than five years			Total
Electric assets (liabilities), net
Prices from other external sources (1)	$	(16,747	)	$	18,704		$	—		$	—		$	1,957
Fair value based on valuation models (2)		(876	)		(1,582	)		13,702			(24,121	)		(12,877	)
Total electric assets (liabilities), net	$	(17,623	)	$	17,122		$	13,702		$	(24,121	)	$	(10,920	)
Natural gas assets (liabilities), net
Prices from other external sources (1)	$	28,696		$	17,568		$	—		$	—		$	46,264
Fair value based on valuation models (3)		(180	)		(58	)		(48	)		—			(286	)
Total natural gas assets (liabilities), net	$	28,516		$	17,510		$	(48	)	$	—		$	45,978

(1) Fair value is determined based upon actively traded, “over-the-counter” market quotes received from third party brokers. These market quotes are used through 36 months.

(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 36 months, 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 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 36 months, for which active quotes are not available. These internally developed market curves are based upon published New York Mercantile Exchange prices, as well as basis spreads using historical and broker estimates.

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Avista Advantage

Three months ended September 30, 2005 compared to the three months ended September 30, 2004

Net income for Avista Advantage was $1.3 million for the three months ended September 30, 2005 compared to net income of $0.4 million for the three months ended September 30, 2004. Operating revenues for Avista Advantage increased $2.2 million and operating expenses increased $0.8 million as compared to the three months ended September 30, 2004. The increase in operating revenues was primarily due to the expansion of Avista Advantage’s customer base. Avista Advantage had a 31 percent increase in the number of billed sites as of September 30, 2005 as compared to September 30, 2004. The increase in operating expenses over 2004 primarily reflects increased labor costs necessary to serve an expanding customer base. Avista Advantage’s average cost of processing a bill decreased 5 percent for the three months ended September 30, 2005 as compared to the three months ended September 30, 2004.

Nine months ended September 30, 2005 compared to the nine months ended September 30, 2004

Net income for Avista Advantage was $3.0 million for the nine months ended September 30, 2005 compared to a net income of less than $0.1 million for the nine months ended September 30, 2004. Operating revenues for Avista Advantage increased $6.3 million and operating expenses increased $1.6 million as compared to the nine months ended September 30, 2004. The increase in operating revenues was primarily due to the expansion of Avista Advantage’s customer base. The increase in operating expenses over 2004 primarily reflects increased labor costs necessary to serve an expanding customer base, partially offset by increased efficiencies and the settlement of an employment contract during 2004. Avista Advantage’s average cost of processing a bill decreased 7 percent for the nine months ended September 30, 2005 as compared to the nine months ended September 30, 2004.

Other

The Other business segment includes Avista Ventures (including AM&D), Pentzer, Avista Development and certain other operations of Avista Capital.

Three months ended September 30, 2005 compared to the three months ended September 30, 2004

The net loss from this business segment was $0.2 million for the three months ended September 30, 2005 compared to a net loss of $1.6 million for the three months ended September 30, 2004. The decrease in the net loss was primarily due to the accrual of an environmental liability at Avista Development during the three months ended September 30, 2004. The net loss from AM&D was less than $0.1 million for the three months ended September 30, 2005 compared to $0.4 million for the three months ended September 30, 2004.

Nine months ended September 30, 2005 compared to the nine months ended September 30, 2004

The net loss from this business segment was $2.0 million for the nine months ended September 30, 2005 compared to a net loss of $3.4 million (excluding the cumulative effect of accounting change) for the nine months ended September 30, 2004. The decrease in the net loss was primarily due to a decrease in losses on certain investments of Avista Ventures not related to AM&D and the accrual of environmental liabilities during 2004. The net loss for AM&D was $0.6 million for the nine months ended September 30, 2005 compared to $0.7 million for the nine months ended September 30, 2004.

New Accounting Standards

See “Note 2 of the Notes to Consolidated Financial Statements.”

Critical Accounting Policies and 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. These estimates and assumptions are based on historical experience and other factors that are believed to be reasonable under the circumstances based on the judgment of the Company’s management. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. The Company’s critical accounting policies that require the use of estimates and assumptions were discussed in detail in the 2004 Form 10-K and have not changed materially from that discussion.

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Liquidity and Capital Resources

Review of Cash Flow Statement

Overall During the nine months ended September 30, 2005, positive cash flows from operations of $150.9 million, proceeds from the sale of the Company’s South Lake Tahoe natural gas properties of $16.6 million and an overall reduction in the Company’s consolidated cash position of $25.4 million were used to fund the majority of the Company’s cash requirements, including utility capital expenditures of $148.8 million and dividends of $19.6 million. The amount outstanding under Avista Corp.’s five-year $350.0 million committed line of credit increased from $68.0 million to $157.0 million during the nine months ended September 30, 2005 to primarily fund $91.5 million of debt redemptions and maturities.

Operating Activities Net cash provided by operating activities was $150.9 million for the nine months ended September 30, 2005 compared to $68.1 million for the nine months ended September 30, 2004. Power and natural gas cost amortizations, net of deferrals, were $15.8 million for the nine months ended September 30, 2005 compared to $1.4 million for the nine months ended September 30, 2004. This was primarily due to decreased deferrals of power costs (and a corresponding decrease in cash paid for electric resources) and increased amortization of natural gas costs (and a corresponding increase in cash received from customers), partially offset by decreased amortization of deferred power costs (and a corresponding decrease in cash received from customers) and increased deferrals of natural gas costs due to rising prices. The amortization of deferred power and natural gas costs is substantially matched by an increase in cash revenues collected from customers. Increases in cash resource costs paid for power and natural gas costs are substantially matched by additions to deferred power and natural gas costs. Net cash provided by working capital components was $13.7 million for the nine months ended September 30, 2005, compared to net cash used of $59.6 million for the nine months ended September 30, 2004. The net cash provided during the nine months ended September 30, 2005 primarily reflects an increase in accounts payable and cash deposits from counterparties (representing cash received for collateral funds), partially offset by a net decrease in the balance outstanding under the Company’s revolving accounts receivable sales facility, an increase in natural gas inventory (cash paid for natural gas to be used in the winter heating season) and an increase in other current assets. The net cash used for the nine months ended September 30, 2004 primarily reflects a net decrease in deposits from counterparties (representing the return of collateral funds), a net decrease in accounts payable (representing cash paid to vendors) and a net decrease in the balance outstanding under the Company’s revolving accounts receivable financing facility. This was partially offset by a net decrease in accounts receivable (representing cash received from customers). Significant changes in non-cash items included a $28.5 million change in energy commodity assets and liabilities, representing the change from an unrealized loss of $6.6 million on energy trading activities for Avista Energy for the nine months ended September 30, 2004 to an unrealized loss of $35.1 million for the nine months ended September 30, 2005.

Investing Activities Net cash used in investing activities was $151.0 million for the nine months ended September 30, 2005, an increase compared to $85.8 million for the nine months ended September 30, 2004. The increase was primarily due to an increase in utility property capital expenditures, including $57.5 million for the purchase of Mirant Oregon’s 50 percent ownership interest in Coyote Springs 2. The total acquisition cost of $62.5 million includes $5.0 million paid in 2004. During the nine months ended September 30, 2005, the Company received $16.6 million for the sale of its South Lake Tahoe natural gas properties. A net increase in restricted cash increased net cash used in investing activities during both the nine months ended September 30, 2005 and 2004.

Financing Activities Net cash used in financing activities was $25.2 million for the nine months ended September 30, 2005 compared to $3.9 million for the nine months ended September 30, 2004. During the nine months ended September 30, 2005, short-term borrowings increased $89.0 million, which reflects an increase in the amount of debt outstanding under Avista Corp.’s line of credit. During the nine months ended September 30, 2005, Avista Corp. redeemed a total of $26.0 million of medium-term notes scheduled to mature in future years, repaid $54.6 million of WP Funding LP debt and $10.9 million of long-term debt matured. Cash dividends paid increased to $19.6 million (or 40.5 cents per share) for the nine months ended September 30, 2005 from $18.6 million (or 38.5 cents per share) for the nine months ended September 30, 2004. During the nine months ended September 30, 2004, short-term borrowings increased $90.0 million, which primarily reflected an increase in the amount of debt outstanding under Avista Corp.’s line of credit. During the nine months ended September 30, 2004, the Company repurchased $36.6 million of long-term debt scheduled to mature in future years at a total premium of $6.7 million, and $29.9 million of debt matured. During the nine months ended September 30, 2004, the Company had $61.9 million of cash inflows and outflows related to the issuance and redemption of long-term debt to affiliated trusts.

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Overall Liquidity

The Company’s consolidated operating cash flows are primarily derived from the operations of Avista Utilities and Avista Energy. The primary source of operating cash flows for Avista Utilities is revenues (including the recovery of previously deferred power and natural gas costs) from sales of electricity and natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, taxes and interest. The primary source and use of operating cash flows for Avista Energy is revenues and costs from realized energy commodity transactions as well as cash collateral deposited to or held from counterparties. Significant operating cash outflows for Avista Energy also include other operating expenses and taxes.

Operating cash flows do not always fully support the capital expenditure needs of Avista Utilities. As such, from time to time, the Company may need to access capital markets in order to fund these needs as well as fund maturing debt. See further discussion at “Capital Resources.”

The Company designs operating and capital budgets to control operating costs and 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 fund high power and natural gas costs in addition to these continuing requirements and to otherwise maintain adequate levels of working capital. As a result of improved operating cash flow and other sources of funds, since 2002 through September 30, 2005, the Company has repurchased $318.7 million of long-term debt.

The general rate increases that became effective in 2002, 2003 and 2004 are allowing the Company to continue to improve its liquidity. The 2002 general electric rate increase in Washington provided for the restructuring and continuation of previously approved temporary rate increases totaling 31.2 percent. In 2003, the Company received a general rate increase, designed to increase annual revenues by $6.3 million in Oregon. In September 2004, the Company received general rate increases, designed to increase base annual revenues by $24.7 million for electric and $3.3 million for natural gas service in Idaho. The Idaho electric base rate increase was substantially offset by a decrease in the PCA surcharge and other minor adjustments such that the net increase in revenues is designed to be $3.2 million. However, the increase in electric base rates will have a significant effect on recurring retail revenues and liquidity. In November 2004, a natural gas general rate increase, designed to increase annual revenues by $5.4 million, was implemented in Washington. In August 2005, the Company entered into a settlement agreement related to its March 2005 Washington general rate case that, if approved by the WUTC, is designed to increase annual revenues by $23.1 million. See further details in the section “Avista Utilities - Regulatory Matters.”

When Avista Utilities’ power and natural gas costs exceed the levels currently recovered from retail customers, its net cash flows are 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. 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. Based on actual hydroelectric generation through September 30, 2005 and forecasts of below normal precipitation and streamflows for the remainder of the year, Avista Utilities expects hydroelectric generation will be approximately 94 percent of normal in 2005. This may change based upon precipitation, temperatures and other variables during the fourth quarter. The expected reduction in hydroelectric generation is not expected to have a significant negative effect on operating cash flows or earnings for 2005 from the amount originally forecasted.

The Company is concerned about increasing energy commodity prices, particularly with respect to natural gas. This has a significant effect on liquidity for both Avista Utilities and Avista Energy. The Company believes that it has adequate liquidity through current cash and cash equivalents, Avista Corp.’s $350.0 million committed line of credit and Avista Energy’s $145.0 million committed line of credit to meet the increased cash needs of higher energy commodity prices. Avista Utilities has regulatory mechanisms in place that provide for the deferral and recovery of the majority of its power and natural gas supply costs. However, if current prices hold or increase, deferral balances will increase, which will negatively affect the Company’s cash flow and liquidity.

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Capital Resources

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, 2005 and December 31, 2004 (dollars in thousands):

	September 30, 2005				December 31, 2004
	Amount		Percent of total		Amount		Percent of total
Current portion of long-term debt	$	51,516	2.7	%	$	85,432	4.4	%
Short-term borrowings		157,498	8.1			68,517	3.5
Long-term debt to affiliated trusts		113,403	5.8			113,403	5.8
Long-term debt		844,291	43.3			901,556	46.2
Total debt		1,166,708	59.9			1,168,908	59.9
Preferred stock-cumulative (including current portion)		28,000	1.4			29,750	1.5
Total liabilities		1,194,708	61.3			1,198,658	61.4
Stockholders’ equity		753,958	38.7			753,205	38.6
Total	$	1,948,666	100.0	%	$	1,951,863	100.0	%

The Company’s total debt decreased $2.2 million from December 31, 2004 to September 30, 2005 due to the redemption and maturity of long-term debt, partially offset by an increase in short-term borrowings. 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’s stockholders’ equity increased $0.8 million during the nine months ended September 30, 2005 primarily due to net income, partially offset by dividends and other comprehensive loss.

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. Excluding the planned long-term debt issuance, 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 the fourth quarter of 2005. Borrowings under Avista Corp.’s committed line of credit may supplement these funds to the extent necessary.

On December 17, 2004, the Company entered into a five-year committed line of credit with various banks in the amount of $350.0 million with an expiration date of December 16, 2009. This committed line of credit replaced a $350.0 million committed line of credit with a 364-day term that had an expiration date of May 5, 2005. The Company can request the issuance of up to $150.0 million in letters of credit under the committed line of credit. As of September 30, 2005 and December 31, 2004, the Company had $157.0 million and $68.0 million, respectively, of borrowings outstanding. As of September 30, 2005 and December 31, 2004, there were $21.3 million and $32.8 million in letters of credit outstanding, respectively. The committed line of credit is secured by $350.0 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. However, if the Company obtains an investment grade senior unsecured rating with a stable outlook from two nationally recognized rating agencies, it has the option to release such security.

The committed line of credit agreement contains customary covenants and default provisions, including covenants not to permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 70 percent at the end of any fiscal quarter. As of September 30, 2005, the Company was in compliance with this covenant with a ratio of 59.9 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, 2005 to be greater than 1.6 to 1. As of September 30, 2005, the Company was in compliance with this covenant with a ratio of 2.49 to 1.

Any default on the line of credit or other financing arrangements of Avista Corp. or any of its significant subsidiaries (including Avista Energy) could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other of such entities, and could induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult for the Company to obtain financing on reasonable terms to pay creditors or fund operations, and the Company would likely be prohibited from paying dividends on its common stock. Avista Corp. does not guarantee the indebtedness of any of its subsidiaries. As of

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September 30, 2005, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements.

In April 2004, the Company filed an amended registration statement on Form S-3 with the Securities and Exchange Commission, which would allow for the issuance of up to $349.6 million of securities (either debt or common stock). This filing amended and combined three previous registration statements filed by the Company. As of September 30, 2005, the Company had remaining availability of $259.6 million under this registration statement. Avista Corp. expects to issue up to $100 million of long-term debt during the fourth quarter of 2005 to, among other things, refinance borrowings on its committed line of credit.

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 obtains borrowings from, Avista Capital. In turn, Avista Capital from time to time makes unsecured short-term loans to, and obtains borrowings from, its subsidiaries. As of September 30, 2005, Avista Corp. held a short-term subordinated note receivable from Avista Capital in the principal amount of $39.0 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.

Pension Plan

As of September 30, 2005, 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. The Company does not expect the current pension plan funding deficit to have a material adverse effect on its financial condition, results of operations or cash flows. The Company made $15 million in cash contributions to the pension plan in 2004. The Company has contributed $15 million to the pension plan in 2005.

Off-Balance Sheet Arrangements

Avista Receivables Corporation (ARC) is a wholly owned, bankruptcy-remote subsidiary of Avista Corp. formed for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On March 22, 2005, Avista Corp., ARC and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment was to extend the termination date from May 29, 2005 to March 21, 2006. Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 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 Avista Corp. As of September 30, 2005, $43.0 million in accounts receivables were sold under this revolving agreement. This agreement provides the Company with cost-effective funds for working capital requirements, capital expenditures and other general corporate needs.

WP Funding LP

WP Funding LP is an entity that was formed in 1993 for the purpose of acquiring the Rathdrum CT. FIN 46 required the Company to consolidate WP Funding LP effective for the period ended December 31, 2003 through June 30, 2005. WP Funding LP purchased the Rathdrum CT from Avista Corp. with funds provided by unrelated investors of which 97 percent represented debt and 3 percent represented equity. Avista Corp. operated the Rathdrum CT and leased it from WP Funding LP until September 2005. See “Note 8 of the Notes to the Consolidated Financial Statements” and the “Executive Level Summary” for a description of the termination of the lease agreement, redemption of the debt and deconsolidation of WP Funding LP in September 2005.

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Credit Ratings

The following table summarizes the Company’s credit ratings as of November 1, 2005:

	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 II (1)
Preferred Trust Securities	BB-	Ba2	BB
AVA Capital Trust III (1)
Preferred Trust Securities	BB-	Ba2	BB
Rating outlook	Stable	Stable	Stable

(1) 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 ratings.

Dividends

The Board of Directors considers the level of dividends on the Company’s common stock on a regular basis, taking into account numerous factors including, without limitation, the Company’s results of operations, cash flows and financial condition, as well as the success of the Company’s strategies and general economic and competitive conditions. The Company’s net income available for dividends is derived primarily from the operations of Avista Utilities and Avista Energy.

Covenants under the Company’s 9.75 percent Senior Notes that mature in 2008 limit the Company’s ability to increase its common stock cash dividend to no more than 5 percent over the previous quarter.

Avista Energy holds a significant portion of cash and cash equivalents reflected on the Consolidated Balance Sheets. Covenants in Avista Energy’s credit agreement, certain counterparty agreements and current market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively 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, 2005, Avista Energy paid $15.1 million in dividends to Avista Capital.

Avista Utilities Operations

In January 2005, the Company completed the purchase of Mirant Oregon’s 50 percent ownership interest in Coyote Springs 2 at a price of $62.5 million, which includes $5.0 million paid in 2004.

In 2005, Avista Corp. completed the sale of its South Lake Tahoe natural gas properties. The cash received for the properties was approximately $16.6 million. See “Note 13 of the Notes to Consolidated Financial Statements” for further information.

As of September 30, 2005, Avista Utilities had $1.7 million in cash and temporary investments, as well as $4.8 million of restricted cash. The restricted cash relates to deposits for Avista Corp.’s interest rate swap agreements.

Avista Utilities held cash deposits from other parties in the amount of $27.9 million as of September 30, 2005, which is included in deposits from counterparties 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.

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

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Energy Marketing and Resource Management Operations

On July 13, 2005, Avista Energy and its subsidiary, Avista Energy Canada, as co-borrowers, amended its committed credit agreement with a group of banks to increase the aggregate amount from $110.0 million to $145.0 million and to extend the expiration date to July 12, 2007. This committed credit facility provides for the issuance of letters of credit to secure contractual obligations to counterparties and for cash advances. This facility is secured by the assets of Avista Energy and Avista Energy Canada and guaranteed by Avista Capital and by CoPac Management, Inc., a wholly owned subsidiary of Avista Energy Canada. 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 amendment to the credit agreement increased the maximum amount for cash advances from $30.0 million to $50.0 million. No cash advances were outstanding as of September 30, 2005 and December 31, 2004. Letters of credit in the aggregate amount of $106.3 million and $91.3 million were outstanding as of September 30, 2005 and December 31, 2004, respectively. The cash deposits of Avista Energy at the respective banks collateralized $31.1 million and $21.5 million of these letters of credit as of September 30, 2005 and December 31, 2004, respectively, which is reflected as restricted cash on the Consolidated Balance Sheets. The increase in letters of credit outstanding is partially due to an increase in commodity prices.

The Avista Energy credit agreement continues to contain 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 that the co-borrowers may incur. The credit agreement also continues to contain covenants and other restrictions related to the co-borrowers’ 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. These covenants, certain counterparty agreements and current market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively limit 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, 2005. Prior to the July 13, 2005 amendment, a reduction in the credit rating of Avista Corp. would have represented an event of default under Avista Energy’s credit agreement. The July 13, 2005 amendment to the credit agreement removed this covenant.

Avista Capital provides guarantees for Avista Energy’s credit agreement (see discussion above) and, in the course of business, may provide performance 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 performance guarantee, which was $68.5 million as of September 30, 2005. The face value of all performance guarantees issued by Avista Capital for energy trading contracts at Avista Energy was $412.3 million as of September 30, 2005.

As part of its cash management practices and operations, Avista Energy from time to time makes unsecured short-term loans to its parent, Avista Capital. Avista Capital’s Board of Directors has limited the total outstanding indebtedness to no more than $45.0 million. Further, as required under Avista Energy’s credit facility, such loans cannot be outstanding longer than 90 days without being repaid. During the nine months ended September 30, 2005, Avista Energy’s maximum total outstanding short-term loan to Avista Capital was $40.2 million including accrued interest. As of September 30, 2005, all outstanding loans including accrued interest had been repaid.

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 $26.3 million as of September 30, 2005. Avista Energy held cash deposits from other parties in the amount of $3.8 million as of September 30, 2005, which is included in deposits from counterparties 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, 2005, Avista Energy had $60.9 million in cash, as well as $34.7 million of restricted cash.

During the nine months ended September 30, 2005, Avista Energy paid $15.1 million in dividends to Avista Capital.

Contractual Obligations

During the nine months ended September 30, 2005, the Company’s future contractual obligations have not changed materially from the amounts disclosed in the 2004 Form 10-K with the following exceptions:

Short-term debt of Avista Utilities (representing borrowings under Avista Corp.’s $350.0 million committed line of credit) increased from $68.0 million as of December 31, 2004 to $157.0 million as of September 30, 2005.

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The amount outstanding under Avista Utilities’ revolving accounts receivable sales financing facility decreased from $72.0 million as of December 31, 2004 to $43.0 million as of September 30, 2005. In March 2005, the termination date was extended from May 29, 2005 to March 21, 2006.

During the nine months ended September 30, 2005, Avista Corp. redeemed a total of $26.0 million of medium-term notes scheduled to mature in future years.

Avista Energy’s contractual commitments to purchase energy commodities as well as commitments related to transmission, transportation and other energy-related contracts in future periods were as follows as of September 30, 2005 (dollars in millions):

For the 12-month periods ended September 30,	2006		2007		2008		2009		2010		Thereafter
Energy purchase contracts	$	1,147	$	276	$	198	$	182	$	177	$	391

Avista Energy also has sales commitments related to these contractual obligations in future periods.

As of September 30, 2005, Avista Corp. did not have any commitments outstanding with equity triggers. Avista Corp. does not expect any material impact from rating triggers; although there are certain rating triggers for Avista Corp. primarily related to changes in pricing under certain financing agreements. Prior to the July 13, 2005 amendment, a reduction in the credit rating of Avista Corp. would have represented an event of default under Avista Energy’s credit agreement. The July 13, 2005 amendment to the credit agreement removed this covenant.

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 allowance of the recovery of power and natural gas costs, operating costs and capital investments, streamflow and weather conditions, the effects of changes in legislative and governmental regulations, changes in regulatory requirements, availability of generation facilities, competition, technology and availability of funding. Also, like other utilities, the Company’s facilities and operations may be exposed to terrorism risks or other malicious acts. See further reference to risks and uncertainties under “Forward-Looking Statements.”

Avista Utilities has mechanisms 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, excluding the ERM dead band in Washington, are deferred on the Consolidated Balance Sheets 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 generation was 95 percent of normal in 2004. Based on actual hydroelectric generation through September 30, 2005 and forecasts of below normal precipitation and streamflows for the remainder of the year, Avista Utilities expects hydroelectric generation will be approximately 94 percent of normal in 2005. This may change based upon precipitation, temperatures and other variables during the fourth quarter. 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 and approval of the recovery of deferred power 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.

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 and approval 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

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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 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. As of September 30, 2005, Avista Energy’s accounts receivable outstanding related to defaulting parties in California are fully offset by reserves for uncollected amounts and funds collected from defaulting parties. Avista Energy is pursuing recovery of the defaulted obligations. See “Counterparty Defaults,” “California Refund Proceeding” and “Pacific Northwest Refund Proceeding” in “Note 12 of the Notes to Consolidated Financial Statements” for further information with respect to the refund proceedings.

In connection with matching loads to available resources and optimizing the use of its assets, 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. Please refer to the 2004 Form 10-K for a description and analysis of commodity price, credit, other operating, interest rate and foreign currency risks.

Risk Management

Risk Policies and Oversight. Avista Utilities and Avista Energy use a variety of techniques to manage risks for their energy resources and wholesale energy market activities. Please refer to the 2004 Form 10-K for discussion of risk management policies and procedures.

Quantitative Risk Measurements. Avista Energy measures the risk in its electric and natural gas portfolio daily utilizing a Value-at-Risk (VAR) model, which monitors its risk in comparison to established thresholds. Please refer to the 2004 Form 10-K for further discussion of the VAR model. Prior to June 30, 2005, Avista Energy utilized a VAR model to assess market risk for the next eight calendar quarters. Beginning, in July 2005, Avista Energy began measuring VAR in the next 12 calendar quarters, and continues to apply other risk measurement techniques, including price sensitivity stress tests, to assess the future market risk, beyond twelve calendar quarters. The addition of four calendar quarters to the VAR calculation was due to more transparent pricing in longer-term commodity markets, due to new market participants and increased volumes. This change did not have a material effect on the VAR calculations. As of September 30, 2005, Avista Energy’s estimated potential one-day unfavorable impact on gross margin as measured by VAR was $0.7 million, compared to $0.4 million as of December 31, 2004. The average daily VAR for the nine months ended September 30, 2005 was $0.9 million. The high daily VAR was $3.0 million and the low daily VAR was $0.3 million during the nine months ended September 30, 2005. Avista Energy was in compliance with its one-day VAR limits during the nine months ended September 30, 2005. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.

Environmental Issues and Other Contingencies

The Company continues to monitor legislative developments at both the state and national level with respect to the potential for further restrictions on sulfur dioxide, nitrogen oxide, carbon dioxide (including cap and trade emission reduction programs), as well as other greenhouse gas and mercury emissions. In addition, the EPA has finalized mercury emission regulations that will affect coal-fired generation plants, including Colstrip Units 3 & 4. The new EPA regulations establish an emission trading program to take effect beginning in January 2010, with a second phase to take effect in 2018. Compliance with these new and proposed requirements and possible additional legislation or regulations could result in increases in capital expenditures and operating expenses for expanded emission controls at the Company’s thermal generating facilities. The amount of these costs and the impact of the restrictions on the operation of the facilities cannot be estimated at this time.

Long-term global climate changes, particularly with respect to the Pacific Northwest, could have a significant effect on the Company’s business. Changing temperatures and precipitation, including snowpack conditions, affect the availability and timing of hydroelectric generation capacity. Changing temperatures could also increase or decrease

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customer demand. The Company’s operations could also be affected by any legislative or regulatory developments in response to global climate changes, including restrictions on the operation of its power generation resources.

For other environmental issues and other contingencies see “Note 12 of the Notes to Consolidated Financial Statements.”

Item 3. Quantitative and Qualitative Disclosures About Market Risk

See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations: – Business Risk and – Risk Management,” “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Energy Marketing and Resource Management – Energy trading activities and positions,” and “Note 5 of the Notes to Consolidated Financial Statements.”

Item 4. Controls and Procedures

The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) 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. Under the supervision and with the participation of the Company’s management, including the Company’s principal executive officer and principal financial officer, the Company has evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon the Company’s 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 under the Securities Exchange Act of 1934.

There have been no changes in the Company’s internal control over financial reporting that occurred during the third quarter of 2005 that have materially affected, or are 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

12	Computation of ratio of earnings to fixed charges and preferred dividend requirements*
15	Letter Re: Unaudited Interim Financial Information*
31.1	Certification of Chief Executive Officer*
31.2	Certification of Chief Financial Officer*
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)**

* Filed herewith.

** Furnished herewith.

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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 4, 2005	/s/ Malyn K. Malquist
	Malyn K. Malquist
	Senior Vice President,
	Chief Financial Officer and Treasurer
	(Principal Accounting and
	Financial Officer)

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