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, 2006

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 incorporation or organization)	(I.R.S. Employer 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 a large accelerated filer, accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  x            Accelerated filer  ¨            Non-accelerated filer  ¨

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 October 31, 2006, 49,244,256 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 (Loss) - Three Months Ended September 30, 2006 and 2005	3
		Consolidated Statements of Income - Nine Months Ended September 30, 2006 and 2005	4
		Consolidated Statements of Comprehensive Income (Loss) - Three and Nine Months Ended September 30, 2006 and 2005	5
		Consolidated Balance Sheets - September 30, 2006 and December 31, 2005	6
		Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2006 and 2005	8
		Notes to Consolidated Financial Statements	9
		Report of Independent Registered Public Accounting Firm	33
	Item 2.	Management’s Discussion and Analysis of Financial Condition Condition and Results of Operations	34
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	60
	Item 4.	Controls and Procedures	60
Part II. Other Information:
	Item 1.	Legal Proceedings	60
	Item 1A.	Risk Factors	60
	Item 6.	Exhibits	61
Signature			62

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,” “forecasts,” “projects,” “predicts,” and similar expressions. All forward-looking statements are subject to a variety of risks and uncertainties and other factors, most of which are beyond the control of Avista Corporation and many of which could have a significant effect 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 (LOSS)

(Unaudited)

Avista Corporation

For the Three Months Ended September 30

Dollars in thousands, except per share amounts

	2006			2005
Operating Revenues:
Utility revenues	$	229,335		$	221,709
Non-utility energy marketing and trading revenues		47,711			30,926
Other non-utility revenues		15,955			13,044
Total operating revenues		293,001			265,679
Operating Expenses:
Utility operating expenses:
Resource costs		129,246			126,511
Other operating expenses		45,864			44,870
Depreciation and amortization		20,394			19,857
Taxes other than income taxes		15,170			14,071
Non-utility operating expenses:
Resource costs		29,798			40,514
Other operating expenses		17,218			14,418
Depreciation and amortization		1,220			1,511
Total operating expenses		258,910			261,752
Gain on sale of utility properties		—			884
Income from operations		34,091			4,811
Other Income (Expense):
Interest expense		(22,467	)		(21,583	)
Interest expense to affiliated trusts		(1,817	)		(1,582	)
Capitalized interest		840			392
Other income - net		2,736			3,511
Total other income (expense)-net		(20,708	)		(19,262	)
Income (loss) before income taxes		13,383			(14,451	)
Income taxes		3,310			(5,414	)
Net income (loss)	$	10,073		$	(9,037	)
Weighted-average common shares outstanding (thousands), basic		49,098			48,538
Weighted-average common shares outstanding (thousands), diluted		49,902			48,538
Total earnings (loss) per common share, basic (Note 11)	$	0.21		$	(0.19	)
Total earnings (loss) per common share, diluted (Note 11)	$	0.20		$	(0.19	)
Dividends paid per common share	$	0.145		$	0.135

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

	2006			2005
Operating Revenues:
Utility revenues	$	910,701		$	779,743
Non-utility energy marketing and trading revenues		123,568			84,813
Other non-utility revenues		45,328			36,619
Total operating revenues		1,079,597			901,175
Operating Expenses:
Utility operating expenses:
Resource costs		522,937			420,946
Other operating expenses		139,809			134,084
Depreciation and amortization		61,485			60,878
Taxes other than income taxes		55,559			50,136
Non-utility operating expenses:
Resource costs		98,121			99,211
Other operating expenses		50,098			43,216
Depreciation and amortization		3,981			4,584
Total operating expenses		931,990			813,055
Gain on sale of utility properties		—			4,093
Income from operations		147,607			92,213
Other Income (Expense):
Interest expense		(66,821	)		(64,723	)
Interest expense to affiliated trusts		(5,286	)		(4,548	)
Capitalized interest		2,010			979
Other income - net		7,289			7,173
Total other income (expense)-net		(62,808	)		(61,119	)
Income before income taxes		84,799			31,094
Income taxes		29,695			11,338
Net income	$	55,104		$	19,756
Weighted-average common shares outstanding (thousands), basic		48,951			48,508
Weighted-average common shares outstanding (thousands), diluted		49,633			49,046
Total earnings per common share, basic (Note 11)	$	1.13		$	0.41
Total earnings per common share, diluted (Note 11)	$	1.11		$	0.40
Dividends paid per common share	$	0.425		$	0.405

The Accompanying Notes are an Integral Part of These Statements.

4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

Avista Corporation

For the Three Months Ended September 30

Dollars in thousands

	2006			2005
Net income (loss)	$	10,073		$	(9,037	)
Other Comprehensive Income (Loss):
Foreign currency translation adjustment		1			414
Unrealized gains (losses) on interest rate swap agreements - net of taxes of $(2,687) and $2,698, respectively		(4,990	)		5,011
Unrealized losses on derivative commodity instruments - net of taxes of $(730) and $(253), respectively		(1,356	)		(470	)
Reclassification adjustment for realized losses (gains) on derivative commodity instruments included in net income - net of taxes of $163 and $(477), respectively		304			(887	)
Reclassification adjustment for realized losses on investment securities included in net income - net of taxes of $43		80			—
Unrealized investment gains - net of taxes of $ - and $52, respectively		1			96
Total other comprehensive income (loss)		(5,960	)		4,164
Comprehensive income (loss)	$	4,113		$	(4,873	)

For the Nine Months Ended September 30

Dollars in thousands

	2006			2005
Net income	$	55,104		$	19,756
Other Comprehensive Income (Loss):
Foreign currency translation adjustment		411			301
Unrealized gains (losses) on interest rate swap agreements - net of taxes of $779 and $(601), respectively		1,446			(1,116	)
Unrealized gains (losses) on derivative commodity instruments - net of taxes of $(500) and $663, respectively		(929	)		1,232
Reclassification adjustment for realized gains on derivative commodity instruments included in net income - net of taxes of $(328) and $(705), respectively		(608	)		(1,309	)
Reclassification adjustment for realized losses on investment securities included in net income - net of taxes of $43		80			—
Unrealized investment losses - net of taxes of $(9) and $(33), respectively		(16	)		(61	)
Total other comprehensive income (loss)		384			(953	)
Comprehensive income	$	55,488		$	18,803

The Accompanying Notes are an Integral Part of These Statements.

5

CONSOLIDATED BALANCE SHEETS

(Unaudited)

Avista Corporation

Dollars in thousands

	September 30, 2006		December 31, 2005
Assets:
Current Assets:
Cash and cash equivalents	$	31,600	$	25,917
Restricted cash		26,703		25,634
Accounts and notes receivable-less allowances of $43,795 and $44,634, respectively		188,035		502,947
Energy commodity derivative assets		360,237		918,609
Utility energy commodity derivative assets		10,200		69,494
Regulatory asset for utility derivatives		65,496		—
Funds held for customers		89,955		38,269
Deposits with counterparties		79,246		59,354
Materials and supplies, fuel stock and natural gas stored		55,086		54,123
Deferred income taxes		12,639		14,519
Assets held for sale		20,920		11,850
Other current assets		42,087		49,652
Total current assets		982,204		1,770,368
Net Utility Property:
Utility plant in service		2,913,410		2,847,043
Construction work in progress		97,236		64,291
Total		3,010,646		2,911,334
Less: Accumulated depreciation and amortization		829,178		784,917
Total net utility property		2,181,468		2,126,417
Other Property and Investments:
Investment in exchange power-net		31,646		33,483
Non-utility properties and investments-net		60,527		77,731
Non-current energy commodity derivative assets		327,401		511,280
Investment in affiliated trusts		13,403		13,403
Other property and investments-net		14,828		15,058
Total other property and investments		447,805		650,955
Deferred Charges:
Regulatory assets for deferred income taxes		106,851		114,109
Other regulatory assets		30,997		26,660
Non-current utility energy commodity derivative assets		25,286		46,731
Power and natural gas deferrals		112,114		147,622
Unamortized debt expense		43,800		48,522
Other deferred charges		19,084		17,110
Total deferred charges		338,132		400,754
Total assets	$	3,949,609	$	4,948,494

The Accompanying Notes are an Integral Part of These Statements.

6

CONSOLIDATED BALANCE SHEETS (continued)

(Unaudited)

Avista Corporation

Dollars in thousands

	September 30, 2006			December 31, 2005
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable	$	201,926		$	511,427
Energy commodity derivative liabilities		327,997			906,794
Customer fund obligations		89,955			38,237
Deposits from counterparties		44,594			13,724
Current portion of long-term debt		170,760			39,524
Current portion of preferred stock-cumulative		26,250			1,750
Short-term borrowings		62,000			63,494
Interest accrued		26,318			18,643
Utility energy commodity derivative liabilities		75,696			3,447
Regulatory liability for utility derivatives		—			66,047
Other current liabilities		67,764			66,801
Total current liabilities		1,093,260			1,729,888
Long-term debt		819,039			989,990
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 shares outstanding at December 31, 2005 ($100 stated value)		—			26,250
Other Non-Current Liabilities and Deferred Credits:
Non-current energy commodity derivative liabilities		325,494			488,644
Regulatory liability for utility plant retirement costs		194,571			186,635
Non-current regulatory liability for utility derivatives		12,796			46,643
Deferred income taxes		465,034			488,934
Other non-current liabilities and deferred credits		107,354			106,979
Total other non-current liabilities and deferred credits		1,105,249			1,317,835
Total liabilities		3,130,951			4,177,366
Commitments and Contingencies (See Notes to Consolidated Financial Statements)
Stockholders’ Equity:
Common stock - net, no par value; 200,000,000 shares authorized; 49,143,072 and 48,593,139 shares outstanding		633,206			620,598
Accumulated other comprehensive loss		(22,915	)		(23,299	)
Retained earnings		208,367			173,829
Total stockholders’ equity		818,658			771,128
Total liabilities and stockholders’ equity	$	3,949,609		$	4,948,494

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

	2006			2005
OPERATING ACTIVITIES:
Net income	$	55,104		$	19,756
Non-cash items included in net income:
Depreciation and amortization		65,466			65,462
Provision (benefit) for deferred income taxes		(14,785	)		11,934
Power and natural gas cost amortizations, net of deferrals		40,580			15,753
Amortization of debt expense		5,792			5,864
Gain on sale of utility properties		—			(4,093	)
Energy commodity assets and liabilities		(1,440	)		35,130
Other		(17,680	)		(11,606	)
Changes in working capital components:
Sale of customer accounts receivable under revolving agreement-net		(32,000	)		(29,000	)
Accounts and notes receivable		347,751			1,486
Materials and supplies, fuel stock and natural gas stored		(963	)		(6,532	)
Deposits with counterparties		(19,892	)		4,338
Other current assets		(44,121	)		(15,605	)
Accounts payable		(303,562	)		34,604
Deposits from counterparties		30,870			25,726
Other current liabilities		60,356			(1,350	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		171,476			151,867
INVESTING ACTIVITIES:
Utility property capital expenditures (excluding equity-related AFUDC)		(116,591	)		(149,823	)
Proceeds from sale of utility property claim		5,484			—
Other capital expenditures		(2,852	)		(3,265	)
Increase in restricted cash		(1,069	)		(13,291	)
Changes in other property and investments		(1,016	)		(2,233	)
Proceeds from property sales		7,965			16,609
NET CASH USED IN INVESTING ACTIVITIES		(108,079	)		(152,003	)
FINANCING ACTIVITIES:
Increase (decrease) in short-term borrowings		(1,494	)		88,981
Redemption and maturity of long-term debt		(39,663	)		(91,452	)
Premiums paid for the redemption of long-term debt		(355	)		(826	)
Redemption of preferred stock		(1,750	)		(1,750	)
Cash dividends paid		(20,782	)		(19,644	)
Issuance of common stock		7,109			1,518
Distribution to minority interests		—			(1,688	)
Long-term debt and short-term borrowing issuance costs		(779	)		(355	)
NET CASH USED IN FINANCING ACTIVITIES		(57,714	)		(25,216	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		5,683			(25,352	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		25,917			88,317
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	31,600		$	62,965
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period:
Interest	$	58,641		$	58,257
Income taxes		47,599			14,865

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, 2006 and 2005 are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results for the 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, 2005 (2005 Form 10-K). Please refer to the section “Acronyms and Terms” in the 2005 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 and northern Idaho, as well as parts of northeast and southwest Oregon. Avista Capital, Inc. (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 15 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 are 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.

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,
	2006			2005			2006			2005
Interest income	$	2,310		$	2,255		$	6,493		$	4,261
Interest on power and natural gas deferrals		1,579			1,786			5,073			5,567
Net gain (loss) on investments		(131	)		55			(521	)		(285	)
Other expense		(1,865	)		(1,683	)		(5,829	)		(4,613	)
Other income		843			1,098			2,073			2,243
Total	$	2,736		$	3,511		$	7,289		$	7,173

Stock-Based Compensation

Prior to January 1, 2006, the Company followed the disclosure only provisions of Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation.” Accordingly, employee stock options were accounted for under Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.” Stock options were granted at exercise prices not less than the fair value of common stock on the date of grant. Avista Corp. has not granted any stock options since 2003. Certain subsidiaries of Avista Corp. have

9

AVISTA CORPORATION

granted stock options to employees in more recent periods, which have not been material to the consolidated financial statements. Under APB No. 25, no compensation expense was recognized pursuant to the Company’s stock option plans. However, the Company recognized compensation expense related to performance-based share awards. The Company adopted SFAS No. 123R, “Share-Based Payment,” on January 1, 2006, which has resulted in changes to stock compensation expense recognition. See Note 2 and Note 12 for further information. The Company adopted SFAS No. 123R using the modified prospective method and, accordingly, financial statement amounts for prior periods presented have not been restated to reflect the fair value method of recognizing compensation expense relating to share-based payments. If compensation expense for the Company’s stock-based employee compensation plans were determined consistent with SFAS No. 123, net income and earnings per common share would have been the following pro forma amounts for the three and nine months ended September 30, 2005 (prior to the adoption of SFAS No. 123R):

	Three months ended September 30, 2005			Nine months ended September 30, 2005
Net income (loss) (dollars in thousands):
As reported	$	(9,037	)	$	19,756
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	)		(2,475	)
Pro forma	$	(9,288	)	$	19,004
Basic and diluted earnings (loss) per common share:
Basic as reported	$	(0.19	)	$	0.41
Diluted as reported	$	(0.19	)	$	0.40
Basic and diluted pro forma	$	(0.19	)	$	0.39

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, net of tax, consisted of the following as of September 30, 2006 and December 31, 2005 (dollars in thousands):

	September 30, 2006			December 31, 2005
Foreign currency translation adjustment	$	1,818		$	1,407
Unfunded accumulated benefit obligation for the pension plan		(19,625	)		(19,625	)
Unrealized loss on interest rate swap agreements		(5,140	)		(6,586	)
Unrealized loss on securities available for sale		—			(64	)
Unrealized gain on derivative commodity instruments		32			1,569
Total accumulated other comprehensive loss	$	(22,915	)	$	(23,299	)

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, 2006, assets held for sale included $17.3 million related to Avista Power, LLC’s investment in Rathdrum Power, LLC (RP LLC) and $3.6 million of turbines and related equipment at Avista Utilities. RP LLC, an unconsolidated entity that was 49 percent owned by Avista Power, LLC, operates a 270 MW natural gas-fired combined cycle combustion turbine plant in northern Idaho. In October 2006, Avista Power completed the sale of its investment in RP LLC for approximately book value. As of December 31, 2005, assets held for sale included $11.9 million of turbines and related equipment at Avista Power and Avista Utilities.

Power Cost Deferrals and Recovery Mechanisms

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).

In Washington, the Energy Recovery Mechanism (ERM) allows Avista Utilities to increase or decrease electric rates periodically with Washington Utilities and Transportation Commission (WUTC) approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences between actual power supply costs and the amount included in base retail rates for Washington customers. The initial amount of power supply costs in excess or below the level in retail rates, which the Company either incurs the cost of, or receives the

10

AVISTA CORPORATION

benefit from, is referred to as the dead band. Avista Utilities accrues interest on deferred power costs in the Washington jurisdiction at a rate, which is adjusted semi-annually, of 8.25 percent as of September 30, 2006. Total deferred power costs for Washington customers were $77.0 million and $96.2 million as of September 30, 2006 and December 31, 2005, respectively.

On June 16, 2006, the WUTC approved a settlement agreement between the Company, the staff of the WUTC, the Industrial Customers of Northwest Utilities and the office of Public Counsel Section of the Washington Attorney General’s Office, representing all parties in the Company’s ERM proceeding. The settlement agreement provides for the continuation of the ERM with certain agreed-upon modifications and is effective as of January 1, 2006. The settling parties have agreed to review the ERM after five years.

The settlement agreement modified the ERM such that the Company’s annual dead band was reduced from $9.0 million to $4.0 million and the Company will incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. Annual power supply cost variances between $4.0 million and $10.0 million are shared equally between the Company and its customers. As such, 50 percent of the annual power supply cost variance in this range is deferred for future surcharge or rebate to the Company’s customers and the remaining 50 percent is an expense of, or benefit to, the Company. Once the annual power supply cost variance from the amount included in base rates exceeds $10.0 million, 90 percent of the cost variance is deferred for future surcharge or rebate. The remaining 10 percent of the variance beyond $10.0 million is an expense of, or benefit to, the Company without affecting current or future customer rates. The following table summarizes the historical (prior to January 1, 2006) and modified ERM (effective January 1, 2006):

Annual Power Supply Cost Variability	Deferred for Future Surcharge or Rebate to Customers		Expense or Benefit to the Company
Historical ERM:
+/- $0 - $9 million	0	%	100	%
+/- excess over $9 million	90	%	10	%
Modified ERM:
+/- $0 - $4 million	0	%	100	%
+/- between $4 million - $10 million	50	%	50	%
+/- excess over $10 million	90	%	10	%

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 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. In June 2006, the WUTC issued an order, which approved the recovery of the $4.1 million of deferred power costs incurred for 2005.

Avista Utilities has a power cost adjustment (PCA) mechanism in Idaho that allows it to modify electric rates periodically with Idaho Public Utilities Commission (IPUC) approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for Idaho customers. Avista Utilities accrues interest on deferred power costs in the Idaho jurisdiction at a rate, which is adjusted annually, of 3.0 percent on current year deferrals and 5.0 percent on carryover balances as of September 30, 2006. Total deferred power costs for Idaho customers were $7.6 million and $8.0 million as of September 30, 2006 and December 31, 2005, respectively.

Natural Gas Cost Deferrals and Recovery Mechanisms

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, subject to applicable regulatory review and 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 actual commodity costs and the amount recovered in current retail rates in Washington and Idaho. In Oregon, Avista Utilities receives recovery of 100 percent of the cost of natural gas for which the price is fixed through hedge transactions, and included in retail rates through the annual purchased gas cost adjustment filing. With respect to the unhedged portion of customer loads in Oregon, Avista Utilities defers 90 percent of the difference between actual prices and the amount recovered in current retail rates. The Company has hedged approximately 90 percent of its natural gas load requirements in Oregon. Total deferred natural gas costs were $27.6 million and $43.4 million as of September 30, 2006 and December 31, 2005, respectively.

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Reclassifications

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

NOTE 2. NEW ACCOUNTING STANDARDS

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, “Share-Based Payment,” which supersedes APB No. 25 and SFAS No. 123 and their 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. The Company implemented the provisions of this statement effective January 1, 2006 using the modified prospective method and, accordingly, financial statement amounts for prior periods presented have not been restated to reflect the fair value method of recognizing compensation expense relating to share-based payments. Under the modified prospective approach, SFAS 123R applies to all of the Company’s unvested stock-based payment awards beginning January 1, 2006 and all prospective awards. For the three and nine months ended September 30, 2006, the Company recorded $0.9 million and $2.9 million (pre-tax), respectively, of stock-based compensation expense, which is included in other operating expenses in the Consolidated Statements of Income. See Note 12 for further information with respect to stock compensation plans.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109,” (FIN 48) which provides guidance for the recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 requires the evaluation of a tax position as a two-step process. First, the Company will be required to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If the tax position meets the “more likely than not” recognition threshold, it is then measured and recorded at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. The Company will be required to adopt FIN 48 in 2007. The Company is evaluating the impact FIN 48 will have on its financial condition and results of operations.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which provides enhanced guidance for using fair value to measure assets and liabilities. This statement also expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements. However, the statement does not require any new fair value measurements. This statement emphasizes that fair value is a market-based measurement and not an entity-specific measurement. Therefore a fair value measurement should be determined based on the assumptions that market participants would use in pricing an asset or liability. The statement establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. The Company will be required to adopt SFAS No. 157 in 2008. The Company is evaluating the impact SFAS No. 157 will have on its financial condition and results of operations.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132 (R).” The most significant provision of this statement will require the Company to recognize the overfunded or underfunded status of defined benefit postretirement plans in the Company’s Consolidated Balance Sheet measured as the difference between the fair value of plan assets and the benefit obligation. For a pension plan, the benefit obligation would be the projected benefit obligation; for any other postretirement benefit plans, the benefit obligation would be the accumulated postretirement benefit obligation. An overfunded status would result in the recognition of an asset and an underfunded status would result in the recognition of a liability. The adjustment required to recognize an asset or liability will result in an expense or benefit to other comprehensive income. The statement will be effective for the year ended December 31, 2006 for the Company. The Company is evaluating the impact this statement will have on its financial condition and results of operations. Based on the Company’s benefit obligations and fair value of plan assets as of December 31, 2005, the adoption of this statement would result in the recognition of an additional liability and corresponding charge to other comprehensive income (a component of stockholders’ equity). The actual impact of the adoption of this statement as of December 31, 2006 could differ significantly primarily due to plan asset performance for 2006 and the discount rate in effect as of December 31, 2006 when the projected benefit obligation is measured. The Company is also evaluating regulatory accounting treatment, which may allow the

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Company to recognize this item as a regulatory asset rather than as a charge to other comprehensive income. The adoption of this statement is not expected to have a material effect on the Company’s net income.

In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin (SAB) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” SAB No. 108 addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year financial statements. SAB No. 108 requires companies to quantify misstatements using a balance sheet and income statement approach and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. The Company is currently evaluating the impact, if any, of adopting SAB No. 108 in the fourth quarter of 2006.

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 20, 2006, 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 March 21, 2006 to March 20, 2007. 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 other operating expenses of Avista Corp. The Receivables Purchase Agreement has financial covenants, which are substantially the same as those of Avista Corp.’s $320.0 million committed line of credit (see Note 7). At September 30, 2006 and December 31, 2005, $53.0 million and $85.0 million in accounts receivable were sold under this revolving agreement, respectively.

NOTE 4. UTILITY ENERGY COMMODITY DERIVATIVE ASSETS AND LIABILITIES

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, 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 electricity and natural gas. 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. Substantially all forward contracts to purchase or sell power and natural gas 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. Utility energy commodity derivatives consisted of the following as of September 30, 2006 and December 31, 2005 (dollars in thousands):

	September 30, 2006			December 31, 2005
Current utility energy commodity derivative asset	$	10,200		$	69,494
Current utility energy commodity derivative liability		(75,696	)		(3,447	)
Net current regulatory liability (asset)	$	(65,496	)	$	66,047
Non-current utility energy commodity derivative asset	$	25,286		$	46,731
Non-current utility energy commodity derivative liability		(12,490	)		(88	)
Net non-current regulatory liability	$	12,796		$	46,643

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Non-current utility energy commodity derivative liabilities are included in other non-current liabilities and deferred credits on the Consolidated Balance Sheets.

NOTE 5. ENERGY COMMODITY TRADING

Avista Utilities and Avista Energy 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. Avista Utilities and Avista Energy have risk management policies and procedures to manage these risks, both qualitative and quantitative. The Company’s Risk Management Committee establishes 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 economic selection from available resources to serve load obligations and using existing resources to capture available economic value. Avista Utilities sells and purchases wholesale electric capacity and energy 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 for multiple years in duration. Avista Utilities makes continuing projections of (1) future retail and wholesale electric 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 for terms as short as one hour up to long-term contracts that extend beyond one year to match expected resources to expected energy and capacity 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 actions to manage or otherwise hedge the imbalances. Management also assesses available resources and actions for longer-term planning periods. The natural gas procurement process also includes entering into financial and physical hedging transactions to assure an adequate supply and as a means of managing natural gas price risks.

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.

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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. The net margin on Avista Energy’s derivative commodity instruments held for trading is reported as non-utility energy marketing and trading 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 non-utility energy marketing and trading 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 non-utility resource costs. Contracts in a receivable position and the value of options held are reported as assets. Similarly, contracts in a payable position and the value of options written are reported as liabilities. 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 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,
	2006			2005		2006			2005
Gain (loss) related to hedge ineffectiveness recorded in operating revenues	$	(1,520	)	$	5,808	$	(2,646	)	$	6,534
Gain (loss) reclassified from accumulated other comprehensive income (loss) and recognized in earnings (pre-tax)		(467	)		1,364		936			2,014

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The following table presents the net gain (loss), net of tax, related to Avista Energy’s cash flow hedges as of September 30, 2006 and December 31, 2005 (dollars in thousands):

	September 30, 2006			December 31, 2005
Accumulated other comprehensive income (loss) related to natural gas derivatives	$	(580	)	$	11,583
Accumulated other comprehensive income (loss) related to electric derivatives		612			(10,014	)
Total accumulated other comprehensive income	$	32		$	1,569

Avista Energy expects to recognize a gain of less than $0.1 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, 2006 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	25,257	28,248	11	4,584	4,762	3
Natural gas	196,219	190,254	5	876,186	893,958	5

The weighted average term of Avista Energy’s electric derivative commodity instruments as of September 30, 2006 was approximately 8 months. The weighted average term of Avista Energy’s natural gas derivative commodity instruments as of September 30, 2006 was approximately 3 months.

Estimated Fair Value The estimated fair value of Avista Energy’s derivative commodity instruments outstanding as of September 30, 2006, and the average estimated fair value of those instruments held during the nine months ended September 30, 2006, are set forth below (dollars in thousands):

	Estimated Fair Value as of September 30, 2006								Average Estimated Fair Value for the nine months ended September 30, 2006
	Current Assets		Long-term Assets		Current Liabilities		Long-term Liabilities		Current Assets		Long-term Assets		Current Liabilities		Long-term Liabilities
Electric	$	162,612	$	302,529	$	140,499	$	295,482	$	221,140	$	378,133	$	208,400	$	366,232
Natural gas		197,625		24,872		187,498		30,012		336,078		40,783		323,966		43,332
Total	$	360,237	$	327,401	$	327,997	$	325,494	$	557,218	$	418,916	$	532,366	$	409,564

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, 2006 was an unrealized gain of $1.4 million and is included in the Consolidated Statements of Income in non-utility energy marketing and trading revenues. The change in the fair value position for the nine months ended September 30, 2005 was an unrealized loss of $35.1 million.

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NOTE 6. LONG-TERM DEBT

The following details the interest rate and maturity dates of long-term debt outstanding as of September 30, 2006 and December 31, 2005 (dollars in thousands):

Maturity Year	Description	Interest Rate	September 30, 2006			December 31, 2005
2006	Secured Medium-Term Notes	7.89%-7.90%	$	—		$	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	7.39%-7.45%		22,500			22,500
2019	First Mortgage Bonds	5.45%		90,000			90,000
2023	Secured Medium-Term Notes	7.18%-7.54%		13,500			13,500
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
2035	First Mortgage Bonds	6.25%		150,000			150,000
	Total secured long-term debt			680,550			710,550
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%		273,960			279,735
2023	Pollution Control Bonds	6.00%		4,100			4,100
	Total unsecured long-term debt			298,060			303,835
	Other long-term debt and capital leases			7,619			11,506
	Interest rate swaps			4,893			5,236
	Unamortized debt discount			(1,323	)		(1,613	)
	Total			989,799			1,029,514
	Current portion of long-term debt			(170,760	)		(39,524	)
	Total long-term debt		$	819,039		$	989,990

NOTE 7. SHORT-TERM BORROWINGS

On April 6, 2006, the Company amended its committed line of credit agreement with various banks. The committed line of credit was originally entered into on December 17, 2004. Amendments to the committed line of credit include a reduction in the total amount of the facility to $320.0 million from $350.0 million and an extension of the expiration date to April 5, 2011 from December 16, 2009. The Company chose to reduce the facility based on forecasted liquidity needs. Under the amended credit agreement, the Company can request the issuance of up to $320.0 million in letters of credit, an increase from $150.0 million prior to the amendment. As of September 30, 2006 and December 31, 2005, the Company had $62.0 million and $63.0 million, respectively, of borrowings outstanding. As of September 30, 2006 and December 31, 2005, there were $51.0 million and $44.1 million in letters of credit outstanding, respectively. The amended committed line of credit is secured by $320.0 million of non-transferable First Mortgage Bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.

The amended committed line of credit agreement contains customary covenants and default provisions, including a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the preceding twelve-month period at the end of any fiscal quarter to be greater than 1.6 to 1. As of September 30, 2006, the Company was in compliance with this covenant with a ratio of 2.56 to 1. The committed line of credit agreement also has a covenant which does not 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. Under the amendment, this ratio limitation will be increased to 75 percent during the period between the completion of the proposed change in the Company’s corporate organization (see Note 14) and December 31, 2007. As of September 30, 2006, the Company was in compliance with this covenant with a ratio of 58 percent. If the proposed change in the Company’s corporate organization becomes effective, the committed line of credit agreement will remain at Avista Corp. (Avista Utilities).

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Avista Energy and its subsidiary, Avista Energy Canada, as co-borrowers, have a committed credit agreement with a group of banks in the aggregate amount of $145.0 million with an expiration date of 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 maximum amount available for cash advances under the credit agreement is $50.0 million. No cash advances were outstanding as of September 30, 2006 and December 31, 2005. Letters of credit in the aggregate amount of $21.2 million and $125.3 million were outstanding as of September 30, 2006 and December 31, 2005, respectively. The cash deposits of Avista Energy at the respective banks collateralized $21.2 million and $18.2 million of these letters of credit as of September 30, 2006 and December 31, 2005, respectively, which is reflected as restricted cash on the Consolidated Balance Sheets.

The Avista Energy credit agreement contains 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 contains 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 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, 2006.

NOTE 8. 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 associated with changes in interest rates and the impact on future interest payments. These interest rate swap agreements relate to the interest payments for 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.

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, 2006, Avista Corp. had a long-term derivative liability of $7.8 million and an unrealized loss of $5.1 million recorded as accumulated other comprehensive loss on the Consolidated Balance Sheets. The interest rate swap agreements provide for mandatory cash settlement of these contracts in 2008 and 2009. The amount included in accumulated other comprehensive income or loss at the cash settlement date will be reclassified to a regulatory liability (part of long-term debt) in accordance with regulatory accounting practices under SFAS No. 71. This regulatory asset or liability will be amortized as a component of interest expense over the remaining life of the forecasted debt issued.

NOTE 9. COMMON STOCK

In November 1999, the Company adopted a shareholder rights plan pursuant to which holders of common stock outstanding on February 15, 1999, or issued thereafter, were granted one preferred share purchase right (Right) on each outstanding share of common stock. Each Right, initially evidenced by and traded with the shares of common stock, entitles the registered holder to purchase one one-hundredth of a share of preferred stock of the Company, without par value, at a purchase price of $70, subject to certain adjustments, regulatory approval and other specified conditions. The Rights will be exercisable only if a person or group acquires 10 percent or more of the outstanding shares of common stock or commences a tender or exchange offer, the consummation of which would result in the beneficial ownership by a person or group of 10 percent or more of the outstanding shares of common stock. Upon any such acquisition, each Right will entitle its holder to purchase, at the purchase price, that number of shares of common stock or preferred stock of the Company (or, in the case of a merger of the Company into another person or group, common stock of the acquiring person or group) that has a market value at that time equal to twice the purchase price. In no event will the Rights be exercisable by a person that has acquired 10 percent or more of the Company’s common stock. The Rights may be redeemed, at a redemption price of $0.01 per Right, by the Board of Directors of the Company at any time until any person or group has acquired 10 percent or more of the common stock. In connection with the proposed statutory share exchange (see Note 14), the shareholder rights plan was amended to provide that the Rights will expire upon the earlier of the effective time of the statutory share exchange or March 31, 2009 (the originally scheduled expiration date).

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NOTE 10. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

The Company has a defined benefit pension plan covering substantially all regular full-time employees at Avista Corp. (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 contributed $15 million to the pension plan in 2005 and 2006. The Company expects to contribute at least $15 million to the pension plan in 2007.

The Pension Protection Act of 2006 (the Pension Act) was signed into law in August 2006. The Pension Act provides new funding rules for pension plans to improve the funded status of corporate defined benefit plans. The new funding rules could increase the Company’s minimum required cash contributions to the pension in the future. The legislation is effective in 2008; however, the law contains a transition period related to the funding rules. The Company does not expect the Pension Act to have a material effect on the Company’s financial condition, results of operations or cash flows.

The Company also has a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to executive officers of the Company. The SERP is intended to provide benefits to executive officers whose benefits under the pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans.

The Company provides certain health care and life insurance benefits for its retired employees that meet required vesting conditions. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. The Company established a Health Reimbursement Arrangement to provide eligible employees with tax-advantaged funds to pay for allowable medical expenses upon retirement. The amount earned by the respective employee is fixed on the retirement date based on the respective employee’s years of service and ending salary. The liability and expense of this plan are included as other post-retirement benefits.

The Company uses a December 31 measurement date for its pension and other 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						Other Post- retirement Benefits
	2006			2005			2006			2005
Three months ended September 30:
Service cost	$	2,495		$	2,325		$	132		$	115
Interest cost		4,231			4,046			416			414
Expected return on plan assets		(4,236	)		(4,000	)		(342	)		(342	)
Transition (asset)/obligation recognition		—			(272	)		126			126
Amortization of prior service cost		164			164			—			—
Net loss recognition		904			1,078			70			(71	)
Net periodic benefit cost	$	3,558		$	3,341		$	402		$	242
Nine months ended September 30:
Service cost	$	7,486		$	6,975		$	482		$	379
Interest cost		12,694			12,138			1,249			1,439
Expected return on plan assets		(12,708	)		(12,000	)		(1,026	)		(980	)
Transition (asset)/obligation recognition		—			(816	)		379			378
Amortization of prior service cost		491			492			—			—
Net loss recognition		2,646			3,243			241			226
Net periodic benefit cost	$	10,609		$	10,032		$	1,325		$	1,442

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NOTE 11. EARNINGS PER COMMON SHARE

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

	Three months ended September 30,					Nine months ended September 30,
	2006		2005			2006		2005
Numerator:
Net income (loss)	$	10,073	$	(9,037	)	$	55,104	$	19,756
Denominator:
Weighted-average number of common shares outstanding-basic		49,098		48,538			48,951		48,508
Effect of dilutive securities:
Contingent stock awards *		417		—			339		285
Stock options *		387		—			343		253
Weighted-average number of common shares outstanding-diluted		49,902		48,538			49,633		49,046
Total earnings (loss) per common share, basic	$	0.21	$	(0.19	)	$	1.13	$	0.41
Total earnings (loss) per common share, diluted	$	0.20	$	(0.19	)	$	1.11	$	0.40

* Due to the net loss for the three months ended September 30, 2005, 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 for the three months ended September 30, 2005.

Total stock options outstanding that were not included in the calculation of diluted earnings per common share were 26,200 and 693,900 for the nine months ended September 30, 2006 and 2005, respectively. 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 the respective period. In addition, contingent stock awards of 152,200 were outstanding as of September 30, 2005, which were not included in basic or diluted shares because the performance conditions were not satisfied.

NOTE 12. STOCK COMPENSATION PLANS

Avista Corp.

In 1998, the Company adopted and shareholders approved an incentive compensation plan, the Long-Term Incentive Plan (1998 Plan). Under the 1998 Plan, certain key employees, officers and non-employee directors of the Company and its subsidiaries may be granted stock options, stock appreciation rights, stock awards (including restricted stock) and other stock-based awards and dividend equivalent rights. The Company has available a maximum of 3.5 million shares of its common stock for grant under the 1998 Plan.

In 2000, the Company adopted a Non-Officer Employee Long-Term Incentive Plan (2000 Plan), which was not required to be approved by shareholders. The provisions of the 2000 Plan are essentially the same as those under the 1998 Plan, except for the exclusion of non-employee directors and executive officers of the Company. The Company has available a maximum of 2.5 million shares of its common stock for grant under the 2000 Plan. However, the Company currently does not plan to issue any further options or securities under the 2000 Plan.

Shares of common stock issued from the exercise of stock options under the 1998 Plan and the 2000 Plan were acquired on the open market prior to 2006. Beginning in 2006, the Company began issuing new shares for the exercise of stock options. As of September 30, 2006, there were 2.5 million shares available for future stock grants under the 1998 Plan and the 2000 Plan.

Prior to January 1, 2006, the Company accounted for stock based compensation using APB No. 25, which required the recognition of compensation expense on the excess, if any, of the market price of the stock at the date of grant over the exercise price of the option. As the exercise price for options granted under the 1998 Plan and the 2000 Plan was equal to the market price at the date of grant, there was no compensation expense recorded by the Company. However, the Company recognized compensation expense related to performance-based share awards. For periods presented prior to January 1, 2006, the Company is required to disclose pro forma net income and

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earnings per common share as if the Company had adopted the fair value method of accounting for stock-based compensation. The fair value of stock-based awards was calculated with option pricing models. These models require the use of subjective assumptions, including stock price volatility, dividend yield, risk-free interest rate and expected time to exercise. The fair value of options was estimated on the date of grant using the Black-Scholes option-pricing model. See Note 1 for disclosure of pro forma net income and earnings per common share for the three and nine months ended September 30, 2005. Avista Corp. has not granted any stock options since 2003. The following summarizes stock option activity under the 1998 Plan and the 2000 Plan for the nine months ended September 30, 2006:

Options outstanding at beginning of period		2,095,211
Options granted		—
Options exercised		(319,003	)
Options canceled		(49,714	)
Options outstanding at end of period		1,726,494
Options exercisable at end of period		1,616,885
Weighted average exercise price:
Options exercised	$	15.81
Options canceled	$	20.77
Options outstanding at end of period	$	15.54
Options exercisable at end of period	$	15.91

The aggregate intrinsic value of options outstanding and options exercisable was $14.1 million and $12.6 million, respectively, as of September 30, 2006. The aggregate intrinsic value represents the difference between Avista Corp.’s closing price on the last trading day of the period and the exercise price, multiplied by the number of in-the-money options. This is the value that would have been received by the option holders had all options holders exercised their options on September 30, 2006. The weighted average term of options outstanding and options exercisable was 4.5 years and 4.4 years, respectively. The intrinsic value of options exercised during the nine months ended September 30, 2006 was $1.8 million and total cash received from the exercise of stock options was $5.0 million. At each of September 30, 2006 and December 31, 2005, the Company had approximately 125,000 unvested stock options outstanding with a weighted average grant date fair value of $3.28 per share, which was computed in earlier periods using the Black-Scholes option-pricing model. Unrecognized compensation expense for Avista Corp.’s stock options was less than $0.1 million as of September 30, 2006, which will be recognized over the remainder of 2006.

On January 1, 2006, the Company adopted SFAS No. 123R, which supersedes APB No. 25 and SFAS No. 123 and their related implementation guidance. 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. The Company adopted SFAS No. 123R using the modified prospective method and, accordingly, financial statement amounts for prior periods presented have not been restated to reflect the fair value method of recognizing compensation expense relating to share-based payments. For the three nine months ended September 30, 2006, the Company recorded $0.9 million and $2.9 million (pre-tax), respectively, of stock-based compensation expense, which is included in other operating expenses in the Consolidated Statements of Income.

During the nine months ended September 30, 2006, the Company granted 138,340 performance shares of which 138,042 were outstanding and unvested as of September 30, 2006, and 36,260 restricted shares of which 36,180 were outstanding and unvested as of September 30, 2006, to certain officers and other key employees under the 1998 Plan. In 2005, the Company granted 163,600 performance shares to certain officers and other key employees under the 1998 Plan, of which 162,364 awards were outstanding and unvested as of September 30, 2006. In 2004, the Company granted 156,800 performance shares to certain officers and other key employees under the 1998 Plan and the 2000 Plan, of which 155,231 awards were outstanding and unvested as of September 30, 2006. The performance shares are payable at the Company’s option in either cash or common stock three years from the date of grant. The amount of cash paid or common stock issued will range from 0 to 150 percent of the performance shares granted depending on the change in the value of the Company’s common stock relative to an external benchmark. Based on the change in value of the Company’s common stock relative to an external benchmark during the 3-year performance cycle, the Company issued 183,497 shares of common stock in the first quarter of 2006 related to the performance shares granted in 2003. Compensation expense of $3.6 million related to the performance shares granted in 2003 was recognized in 2005.

The restricted shares granted during the nine months ended September 30, 2006 vest in equal thirds each year over a three-year period and are payable in Avista Corp. common stock at the end of each year in the three-year period if

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the service condition is met, with the exception of restricted shares for the Company’s Chief Executive Officer (CEO). In addition to the service condition, the Company must meet a return on equity target in order for the CEO’s restricted shares to vest. As of September 30, 2006, the restricted shares had unrecognized compensation expense of $0.5 million (which will be recognized over the fourth quarter of 2006, 2007 and 2008) and an intrinsic value of $0.9 million. The intrinsic value represents the total market value of restricted shares.

The Company measured (at the grant date) the estimated fair value of performance shares granted in 2006, 2005 and 2004 in accordance with the provisions of SFAS No. 123R. The fair value of each performance share award was estimated on the date of grant using a Monte Carlo valuation model. Expected volatility was based on the historical volatility of Avista Corp. common stock over a three-year period. The expected term of the performance shares is three years based on the performance cycle. The risk-free interest rate was based on the U.S. Treasury yield at the time of grant.

The following summarizes the weighted average assumptions used to determine the fair value of performance shares and related compensation costs:

	2006		2005		2004
Risk-free interest rate	4.6	%	3.4	%	2.4	%
Expected life, in years	3		3		3
Expected volatility	21.9	%	34.1	%	38.8	%

Accordingly, the fair value (on a per share basis) of performance shares granted was estimated to be $16.65, $15.33 and $16.02 for the nine months ended September 30, 2006, and the years 2005 and 2004, respectively. Unrecognized compensation expense for performance share awards was $3.0 million as of September 30, 2006, of which $0.6 million, $1.6 million and $0.8 million is expected to be expensed during the fourth quarter of 2006, and the years 2007 and 2008, respectively. The aggregate intrinsic value of all performance share awards outstanding as of September 30, 2006 was $10.8 million, which represents the total market value of all performance shares outstanding. This is the value that would have been received by the performance share recipients had all performance shares been vested and paid out at 100 percent on September 30, 2006.

The awards outstanding under the performance share grants include a dividend component that is paid in cash. This component of the performance share grants is accounted for as a liability award under the guidance of SFAS No. 123R. These liability awards are revalued on a quarterly basis taking into account the number of awards outstanding, historical dividend rate, and the change in the value of the Company’s common stock relative to an external benchmark. Over the life of these awards, the cumulative amount of compensation expense recognized will match the actual cash paid. As of September 30, 2006, the Company had recognized compensation expense and a liability of $0.4 million related to the dividend component of performance share grants.

Avista Capital Companies

Certain subsidiaries of Avista Capital have employee stock incentive plans under which certain employees and directors of the subsidiaries are granted options to purchase subsidiary shares at prices no less than the fair market value on the date of grant. Options outstanding under these plans generally vest over periods of between three and five years from the date granted and terminate ten years from the date granted. Employee stock incentive plans related to the Avista Capital subsidiaries are not significant to the consolidated financial statements.

NOTE 13. 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. With respect to matters that affect Avista Utilities’ operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the rate making 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

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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. For further details of the Agreement in Resolution please refer to the 2005 Form 10-K. In April 2005 and June 2005, the California Parties and the City of Tacoma, respectively, filed petitions for review of the FERC’s decisions approving the Agreement in Resolution with the United States Court of Appeals for the Ninth Circuit. Based on the FERC’s order approving the Agreement in Resolution and the FERC’s denial of rehearing requests, 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 November 10, 2005, an amended class action complaint was filed 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 Avista Corp., Gary G. Ely, the current Chairman of the Board and Chief Executive Officer of Avista Corp., and Jon E. Eliassen, the former Senior Vice President and Chief Financial Officer of Avista Corp. Several class action complaints were originally filed in September through November 2002 in the same court against the same parties. In February 2003, the court issued an order, which consolidated the complaints and in August 2003, the plaintiffs filed a consolidated amended class action complaint. 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 to dismiss this complaint. The order to dismiss was issued without prejudice, which allowed the plaintiffs to amend their complaint. The amended complaint filed on November 10, 2005 alleges damages due to the decrease in the total market value of the Company’s common stock during the class period, alleged to be approximately $2.6 billion. These alleged losses stemmed from alleged violations of federal securities laws through alleged misstatements and omissions of material facts with respect to the Company’s energy trading practices in 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. On January 6, 2006, the Company filed a motion to dismiss the November 10, 2005 complaint, asserting deficiencies in the amended complaint, including that the plaintiffs failed to adequately allege loss causation. On June 2, 2006, the U.S. District Court entered an order denying the Company’s motion to dismiss the complaint. The U.S. District Court’s order denying the Company’s motion to dismiss is not a decision on the merits of the lawsuit and the matter will proceed in the normal course of litigation and a trial date is currently scheduled for November 13, 2007. On September 16, 2006, the plaintiffs filed a motion for class certification. 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.

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 California Independent System Operator (CalISO) and the California Power Exchange (CalPX) during the period from October 2, 2000 to June 20, 2001 (Refund Period) in the California spot power market. The findings of the FERC administrative law judge were largely adopted in March 2003 by the FERC. The refunds ordered are 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. 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 January 2006, the FERC issued its Order on Cost Filings accepting Avista Energy’s cost filing claim, subject to a compliance filing and the utilization of final CalISO, CalPX and Automated Power Exchange Corporation (APX) data. Avista Energy submitted its compliance filing to the FERC in February 2006, and that filing was accepted by the FERC on November 2, 2006.

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In 2001, Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) defaulted on payment obligations to the CalPX and the 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 to the CalPX. 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. As of September 30, 2006, 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.

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 provided notice that Avista Energy was no longer subject to this investigation. In March and April 2005, the California Parties and PG&E, respectively, petitioned for review of the FERC’s decision by 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. 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. In August 2006, the Ninth Circuit upheld October 2, 2000 as the refund effective date for the FPA section 206 Refund Proceeding, but remanded to the FERC its decision not to consider a FPA section 309 remedy for tariff violations prior to October 2, 2000. The Ninth Circuit also granted California’s petition for review challenging the FERC’s exclusion of the energy exchange transactions as well as the FERC’s exclusion of forward market transactions from the California refund proceedings. On August 2, 2006, however, the Ninth Circuit also issued an order staying the time for seeking rehearing to October 31, 2006. On October 23, 2006, the Ninth Circuit further extended by 120 days, or until February 28, 2007, the time for filing petitions for rehearing. It is unclear at this time what impact, if any, the Court’s remand might have on Avista Energy. 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. This is primarily due to the fact that FERC orders have stated that any refunds will be offset against unpaid amounts owed to the respective parties and the Company does not believe that refunds would exceed unpaid amounts owed to the Company.

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 and June 20, 2001 were just and reasonable. During the hearing, Avista Utilities and Avista Energy vigorously opposed claims that rates for spot market sales were unjust and unreasonable and that the imposition of refunds would be appropriate. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of refunds. 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. In October 2006, various appellants filed a motion for oral argument. Oral arguments are scheduled for January 8, 2007. Because the resolution of the Pacific Northwest refund proceeding remains uncertain, legal counsel cannot express

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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.

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 should refund the difference between the rate charged and a just and reasonable rate. 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 Court denied the request without explanation on July 31, 2006. On October 23, 2006, the application for an extension of time within which to file a petition for a writ of certiorari was granted, extending the time to and including December 28, 2006. 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.

Wah Chang Complaint

In May 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. This complaint is similar to the Port of Seattle complaint (which has been dismissed by the United States District Court and the United States Court of Appeals for the Ninth Circuit as disclosed in the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006) and 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 February 2005, the Court granted the defendants’ motion to dismiss 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. 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.

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City of Tacoma Complaint

In June 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 is similar to the Port of Seattle complaint (which has been dismissed by the United States District Court and the United States Court of Appeals for the Ninth Circuit as disclosed in the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006) and 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.

State of Montana Proceedings

In June 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. In February 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.

Montana Public School Trust Fund Lawsuit

In October 2003, a lawsuit was originally filed by two residents of the State of Montana 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 alleged that the hydroelectric facilities are located on state-owned riverbeds and the owners of the dams 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. In February 2004, the Company filed its motion to dismiss this lawsuit; PacifiCorp and PPL Montana, the other named defendants, also filed a motion to dismiss, or joined therein. In May 2004, the Montana AG filed a complaint on behalf of the state in the District Court to join in this lawsuit to allegedly protect and preserve state lands/school trust lands from use without compensation. In July 2004, the defendants (including Avista Corp.) filed a motion to dismiss the Montana AG’s complaint. In September 2004, the motion to dismiss the Montana AG’s complaint was denied, rejecting the defendants’ argument, among other things, that the FERC has exclusive jurisdiction over this matter. In September 2005, the U.S. District Court issued an order vacating its prior decision based on lack of jurisdiction.

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In November 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, as discussed above, and the Montana AG filed an answer, counterclaim and motion for summary judgment. In June 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 into in 1999 with the State of Montana relating to the relicensing of Avista Corp.’s Noxon Rapids Hydroelectric Generating Project. On April 14, 2006, the Montana State Court granted the Montana AG’s motion for summary judgment and denied Avista Corp.’s motion to amend its complaint to add its breach of contract and negligent misrepresentation claims. However, the Montana State Court granted Avista Corp.’s motion to amend its complaint to contend that the Clark Fork River is not navigable. The Company contends that if the Clark Fork River was not navigable at the time of statehood in 1889, the State of Montana never acquired ownership of the riverbeds under the equal footing doctrine. The Court determined that the Montana AG’s claims for compensation were not preempted by the Federal Power Act because it was not, on its face, in conflict with Montana law, nor were they preempted by a federal navigational right for purposes of interstate commerce. The Court also rejected defenses based on estoppel, waiver, and the statute of limitations. The Court did not relieve the Montana AG, however, of its obligation to prove that the State of Montana actually owns the riverbeds or that the land is part of a school trust under the Montana Constitution. In addition, the question of whether there is federal preemption under the Federal Power Act, not on its face, but as actually applied in these circumstances, and the question of compensation, still remain open issues in the case. On May 16, 2006, the State of Montana filed a motion for summary judgment on the question of liability. On October 6, 2006, the Company filed several motions, which addressed, among other things, the question of navigability of the Clark Fork River arguing that since the Clark Fork River was not navigable at the time of statehood, the State of Montana never acquired ownership of the riverbeds under the equal footing doctrine. Oral arguments on the Company’s motions have been set for December 2006. The Company expects this matter to proceed in the normal course of litigation and a trial date is currently scheduled for October 2007. 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, the Company intends to seek recovery, through the rate making process, of any amounts paid.

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 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.

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). In January 2006, the EPA issued a draft settlement agreement related to the ACO. The ACO alleges that Colstrip Units 3 & 4 have been in violation of the CAA permit at Colstrip since the units came on-line in the 1980s. 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 the other owners of Colstrip believe that the ACO is unfounded. The owners of Colstrip are discussing the proposed settlement agreement with the EPA, the Department of Environmental Quality (Montana DEQ) and the Northern Cheyenne Tribe. The draft settlement agreement would resolve the potential liability related to this issue and would result in the installation of additional nitrogen oxide emissions control equipment at Colstrip. 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, the Company intends to seek recovery, through the rate making process, of any amounts paid (including capitalized costs).

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Colstrip Royalty Claim

Western Energy Company (WECO) supplies coal to the owners of Colstrip Units 3 & 4 under a Coal Supply Agreement and a Transportation Agreement. Avista Corp. owns a 15 percent interest in Colstrip Units 3 & 4. 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 (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. 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. However, the Company would most likely seek recovery, through the rate making process, of any amounts paid.

Spokane River

The Company has entered into a settlement with the State of Washington’s Department of Ecology (DOE) and Kaiser Aluminum & Chemical Corporation (Kaiser) relating to the remediation of a contaminated site on the Spokane River. The Company’s involvement with this contaminated site relates to its previous ownership of a wastewater treatment plant through Avista Development. Under the agreement with the DOE and Kaiser, the Company will perform the selected remedial action under the Cleanup Action Plan. Kaiser, 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. The Company has accrued its share of the total estimated costs, which was not material to the Company’s financial condition or results of operations. The Company expects that work under the Cleanup Action Plan will be completed in the fourth quarter of 2006 or early in the first quarter of 2007. 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 financial condition, results of operations or cash flows.

Northeast Combustion Turbine Site

In August 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 had fuel storage facilities that were leased to Co-op Supply, Inc., an affiliate 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 causing excess fuel to overflow into a containment area. It is estimated that approximately 26,000 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. The Company immediately commenced remediation efforts, including the removal of contaminated soil and the related fuel storage facilities. Options to dispose of the contaminated soil are currently being evaluated. During the fourth quarter of 2005, the Company filed a complaint against Co-op and an engineering firm to recover a substantial portion of the cleanup costs. Mediation between the Company, Co-op and the engineering firm commenced in August 2006. The Company accrued the estimated cleanup costs during 2005, which was not material to the Company’s consolidated financial condition or results of operations.

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. In June 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

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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 Company, Northwestern Energy and Unocal Oil. Several meetings have been held with the EPA and the Potentially Responsible Parties (PRPs) to ask questions of the EPA regarding the Harbor Oil site and to discuss the process used by the EPA in selecting PRPs, as well as the logistics of conducting a remedial investigation and feasibility study for the site. Based on the review of its records related to Harbor Oil, 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 not possible to make an estimate of any liability at this time.

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 ownership decision 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 annual generation of 10 aMW, 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. The Company intends to seek recovery, through the rate making process, of any amounts paid.

Spokane River Relicensing

The Company owns and operates six hydroelectric plants on the Spokane River, and five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls, which have a total present capability of 155.7 MW) are under one FERC license and are referred to, collectively, 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 new license applications with the FERC in July 2005. The Company has requested the FERC to consider a license for Post Falls, which has a present capability of 18 MW, that is separate from the other four hydroelectric plants because 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 proposed a number of measures intended to address the impact of the Spokane River Project and enhance resources associated with the Spokane River.

The Company filed applications with the States of Idaho and Washington in July 2006 for certification under Section 401 of the Clean Water Act. Such certification must be received (or state authority waived) prior to the FERC’s issuance of a new license(s).

Since the Company’s July 2005 filing of applications to relicense the Spokane River Project, the FERC has continued various stages of processing the applications. In May 2006, the FERC issued a notice calling for terms and conditions regarding the two license applications. In response to that notice, a number of parties (including the Coeur d’Alene Tribe, the State of Idaho, Washington State agencies, and the United States Department of Interior (DOI)) filed either recommended terms and conditions, pursuant to Sections 10(a) and 10(j) of the Federal Power Act (FPA), or mandatory conditions related to the Post Falls application, pursuant to Section 4(e) of the FPA. The Company’s initial estimate of the potential cost of the conditions proposed for Post Falls total between $400 million and $500 million over a 50-year period. This assumes all conditions, both mandatory and recommended, as well as the Company’s proposed conditions, would be included in a final license issued by the FERC, which the Company believes to be unlikely. For the rest of the Spokane River Project, which is located in Washington, the Company’s

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initial estimate of the cost of meeting the recommended conditions, should they be included in a final license, totals between $175 million and $225 million over a 50-year period. These cost estimates are based on the preliminary conditions and recommendations and will be updated based on the outcome of the FERC proceedings. The Company has requested a trial-type hearing on facts in front of a DOI administrative law judge related to the DOI’s mandatory conditions. DOI has responded to that request, and several parties have intervened. The request was formally referred for docketing on October 10, 2006. Further legal proceedings at the FERC or in court are possible as the various stages of the relicensing process continue.

Certain environmental measures in the Company’s July 2005 license applications have estimated costs exceeding $3 million per year, which are included in the total cost estimates provided above. For certain other items referenced in the license applications, 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. The FERC schedule currently provides for a September 2007 decision. The Company intends to seek recovery, through the rate making process, of all such operating and capitalized costs.

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 completed the Gas Supersaturation Control Program (GSCP). The Idaho Department of Environmental Quality and the U.S. Fish and Wildlife Service approved the GSCP in February 2004 and the FERC issued an order approving the GSCP in January 2005.

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. When river flows exceed the capacity of the powerhouse turbines, the excess flows would be diverted to the tunnels rather than released over the spillway. The Company has undertaken physical and computer modeling studies to confirm the feasibility and likely effectiveness of its tunnel solution. The Company has completed its preliminary design development efforts (which include additional computer model studies, some site investigation, and preliminary engineering design) and the cost estimates have been updated. The costs of modifying the first tunnel are now estimated to be $58 million (using 2006 dollars with inflation projected at 5 percent) with the majority of these costs to be incurred in 2008 through 2011, an increase from prior estimates of $38 million. The calculated updated cost estimates to modify the second tunnel are $39 million, an increase from prior estimates of $26 million. 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. The increases in costs are mainly due to inflation and large increases in materials costs, such as concrete and steel. As a result of the new cost estimates and extension of schedule, the Company is meeting with stakeholders to explore possible alternatives to the construction of the tunnels. The Company intends to seek recovery, through the rate making process, of the costs to address the dissolved atmospheric gas levels, including the mitigation payments.

The U.S Fish and Wildlife Service has listed bull trout as threatened under the Endangered Species Act. The Clark Fork Settlement Agreement describes programs intended to restore bull trout populations in the project area. 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 at Cabinet Gorge and Noxon Rapids. 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 bull trout population enhancement measures.

Air Quality

The Company must be in compliance with requirements under the Clean Air Act and Clean Air Act Amendments with respect to its thermal generating plants. 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 particular, the EPA has finalized mercury emission regulations that will affect coal-fired generation plants, including Colstrip. 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. In addition, on October 16, 2006, the Montana DEQ adopted final rules for the control of mercury emissions from coal-fired plants that are more restrictive than EPA regulations. The new rules set strict mercury emission limits by 2010, and put in place a recurring 10-year review process to ensure facilities are keeping pace with advancing technology in mercury emission control. The rules also provide for temporary alternate emission limits provided certain provisions are met, and they allocate mercury emission credits in a manner that rewards the cleanest facilities. Avista Corp. owns a 15 percent interest in Colstrip

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Units 3 & 4, located in Montana. 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 Company, along with the other owners of Colstrip, are in the process of computing estimates for the amount of these costs and the impact the restrictions could have on the operation of the facilities. The Company will continue to seek recovery, through the rate making process, of the costs to comply with various air quality requirements.

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 14: POTENTIAL HOLDING COMPANY FORMATION

At the 2006 Annual Meeting of Shareholders on May 11, 2006, the shareholders of Avista Corp. approved a proposal to proceed with a statutory share exchange, which would change the Company’s organization to a holding company structure. The holding company, currently named AVA Formation Corp. (AVA), would become the parent of Avista Corp. After the contemplated dividend to AVA of the capital stock of Avista Capital now held by Avista Corp. (Avista Capital Dividend), AVA would then also be the parent of Avista Capital. The Avista Capital Dividend would effect the structural separation of Avista Corp.’s non-utility businesses from its regulated utility business. Since the company’s 9.75 percent Senior Notes due June 1, 2008 contain a restriction that would prohibit the Avista Capital Dividend (but not the holding company structure), the dividend would not be distributed until the Senior Notes are retired.

Avista Corp. received approval from the FERC on April 18, 2006 (conditioned on approval by the state regulatory agencies) and from the IPUC on June 30, 2006. Avista Corp. also has filed for approval from the utility regulators in Washington, Oregon and Montana. The statutory share exchange is subject to the receipt of the remaining regulatory approvals and the satisfaction of other conditions. The Company anticipates that the statutory share exchange and the holding company structure implementation, if approved on terms acceptable to the Company, will not be completed earlier than mid-2007.

The IPUC accepted a stipulation entered into between Avista Corp. and the IPUC Staff that sets forth a variety of conditions, which would serve to segregate the Company’s utility operations from the other businesses conducted by the holding company. The stipulation would require Avista Corp. to maintain certain common equity levels as part of its capital structure. Avista Corp. has committed to increase its actual utility common equity component to 35 percent by the end of 2007 and 38 percent by the end of 2008, which is consistent with provisions of the Company’s Washington general rate case implemented on January 1, 2006. The calculation of the utility equity component is essentially the ratio of Avista Corp.’s total common equity to total capitalization excluding, in each case, Avista Corp.’s investment in Avista Capital. In addition, IPUC approval would be required for any dividend from Avista Corp. to the holding company that would lower utility common equity below 25 percent of total capitalization which, for this purpose, includes long and short-term debt, capitalized lease obligations and preferred and common equity.

Pursuant to the Plan of Share Exchange, a statutory share exchange would be effected whereby each outstanding share of Avista Corp. common stock would be exchanged for one share of AVA common stock, no par value, so that holders of Avista Corp. common stock would become holders of AVA common stock and Avista Corp. would become a subsidiary of AVA. The other outstanding securities of Avista Corp. would not be affected by the statutory share exchange, with limited exceptions for stock options and other securities outstanding under equity compensation and employee benefit plans.

NOTE 15. 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. Advantage IQ (formerly Avista Advantage) is a provider of facility information and cost management services for multi-site customers throughout North America. The Other business segment includes other investments

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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			Advantage IQ		Other			Intersegment Eliminations (1)			Total
For the three months ended September 30, 2006:
Operating revenues	$	229,335		$	47,711		$	10,389	$	5,566		$	—		$	293,001
Resource costs		129,246			29,798			—		—			—			159,044
Gross margin		100,089			17,913			—		—			—			118,002
Other operating expenses		45,864			5,498			6,589		5,131			—			63,082
Depreciation and amortization		20,394			195			544		481			—			21,614
Income (loss) from operations		18,661			12,220			3,256		(46	)		—			34,091
Interest expense (2)		24,120			32			144		588			(600	)		24,284
Income taxes		(3,358	)		5,011			1,193		464			—			3,310
Net income (loss)		480			8,773			1,918		(1,098	)		—			10,073
Capital expenditures		43,313			310			990		29			—			44,642
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		44,870			4,524			5,489		4,405			—			59,288
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		33,936			414			220		686			—			35,256
For the nine months ended September 30, 2006:
Operating revenues	$	910,701		$	123,568		$	29,011	$	16,317		$	—		$	1,079,597
Resource costs		522,937			98,121			—		—			—			621,058
Gross margin		387,764			25,447			—		—			—			413,211
Other operating expenses		139,809			15,025			19,249		15,824			—			189,907
Depreciation and amortization		61,485			788			1,544		1,649			—			65,466
Income (loss) from operations		130,911			9,634			8,218		(1,156	)		—			147,607
Interest expense (2)		71,625			131			499		1,679			(1,827	)		72,107
Income taxes		22,519			5,235			2,816		(875	)		—			29,695
Net income (loss)		43,531			9,209			4,903		(2,539	)		—			55,104
Capital expenditures		116,591			849			1,957		46						119,443
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		134,084			13,702			16,297		13,217			—			177,300
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		149,823			1,166			751		1,348			—			153,088
Total Assets:
Total assets as of September 30, 2006	$	2,768,387		$	1,035,312		$	99,813	$	46,097		$	—		$	3,949,609
Total assets as of December 31, 2005		2,838,154			2,012,354			46,094		51,892			—			4,948,494

(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, which was terminated effective April 1, 2005. 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, 2006, and the related consolidated statements of income and of comprehensive income for the three-month and nine-month periods ended September 30, 2006 and 2005, and of cash flows for the nine-month periods ended September 30, 2006 and 2005. 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 review, 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, 2005, 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 6, 2006, 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, 2005, 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

October 30, 2006

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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,” “forecasts,” “projects,” “predicts,” and similar expressions.

All forward-looking statements (including those made in this Quarterly Report on Form 10-Q) 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 effect 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;

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

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

• the effect 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;

• 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;

• 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;

• the potential impact of changes to electric transmission ownership, operation and governance, such as the formation of one or more regional transmission organizations or similar entities;

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

• the ability to relicense and maintain licenses for hydroelectric generating facilities at cost-effective levels with reasonable terms and conditions;

• unplanned outages at any Company-owned generating facilities or the inability of generating facilities to operate as intended;

• unanticipated delays or changes in construction costs, as well as the ability to obtain required operating permits with respect to present or prospective facilities;

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

• blackouts or disruptions of interconnected transmission systems;

• the potential for future terrorist attacks or other malicious acts, 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 affected by various factors including the Company’s credit ratings, interest rate fluctuations and other capital market conditions;

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

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• 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 affect future funding obligations, costs and pension plan liabilities;

• increasing health care costs and the resulting effect on health insurance premiums paid for employees and retirees;

• 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;

• the potential effects of negative publicity regarding business practices, whether true or not, which could result in, among other things, costly litigation and a decline in the Company’s common stock price;

• changes in technologies, possibly making some of the current technology quickly obsolete;

• changes in tax rates and/or policies;

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

• changes in the strategic business plans of the Company and/or any of its subsidiaries, which may be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses.

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 effect 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.

Potential Holding Company Formation

In May 2006, the shareholders of Avista Corp. approved a proposal to proceed with a statutory share exchange, which would change the Company’s organization to a holding company structure. See further information at “Note 14 of the Notes to Consolidated Financial Statements.”

Avista Corp. Business Segments

Avista Corp. has four business segments as follows:

• Avista Utilities – generation, transmission and distribution of electric energy and distribution of natural gas to retail customers, as well as wholesale purchases and sales of energy commodities. This business segment is conducted by an operating division of Avista Corp. known as Avista Utilities.

• Energy Marketing and Resource Management – electricity and natural gas marketing, trading and resource management. This business segment is conducted primarily by Avista Energy, an indirect subsidiary of Avista Corp.

• Advantage IQ (formerly Avista Advantage) – facility information and cost management services for multi-site customers. This business segment is conducted by Advantage IQ, Inc., which is an indirect subsidiary of Avista Corp.

• Other – includes sheet metal fabrication, radiant floor heating systems and certain other investments (including investments in real estate). This business segment is conducted by various indirect subsidiaries of Avista Corp., including Advanced Manufacturing and Development (AM&D), doing business as METALfx.

Avista Energy, Advantage IQ and the various companies in the Other business segment are subsidiaries of Avista Capital, which is a direct, wholly owned subsidiary of Avista Corp. The Company’s total common stockholders’ equity was $818.7 million as of September 30, 2006, of which $243.2 million represented its investment in Avista Capital.

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The following table presents the contribution to net income (loss) from each business segment for the three and nine months ended September 30 (dollars in thousands):

	Three months ended September 30,						Nine months ended September 30,
	2006			2005			2006			2005
Avista Utilities	$	480		$	(1,803	)	$	43,531		$	35,590
Energy Marketing and Resource Management		8,773			(8,266	)		9,209			(16,874	)
Advantage IQ		1,918			1,274			4,903			3,000
Other		(1,098	)		(242	)		(2,539	)		(1,960	)
Net income (loss)	$	10,073		$	(9,037	)	$	55,104		$	19,756

Executive Level Summary

Overall

Avista Corp.’s operating results and cash flows are derived primarily from Avista Utilities and Avista Energy (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.

Net income was $10.1 million for the three months ended September 30, 2006 compared to a net loss of $9.0 million for the three months ended September 30, 2005. Net income was $55.1 million for the nine months ended September 30, 2006 compared to $19.8 million for the nine months ended September 30, 2005. This increase for each period as compared to the respective period in the prior year was due to the improved performance of the Energy Marketing and Resource Management segment, Avista Utilities and Advantage IQ.

Avista Utilities

Avista Utilities is the Company’s most significant business segment. Avista Utilities’ operating and financial performance is substantially dependent upon, among other things: (1) weather conditions, (2) the price of natural gas in the wholesale market, including the effect on the price of fuel for generation, (3) the price of electricity in the wholesale market, including the effects of weather conditions, natural gas prices and other factors affecting supply and demand and (4) regulatory decisions, allowing Avista Utilities to recover its costs, including particularly its purchased power and fuel costs, on a timely basis, and to earn a fair return on its investment.

Weather has a significant effect on Avista Utilities’ operations, both with respect to customer demand and resulting operating revenues (primarily heating requirements in the winter and cooling requirements in the summer) and electric resource costs (primarily the availability of hydroelectric generation and the tendency for high demand to increase the cost of fuel for electric generation and wholesale electric market prices). Avista Utilities normally experiences its highest 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). In general, warmer weather in the heating season and cooler weather in the cooling season will reduce Avista Utilities’ operating revenues. In addition, a reduction in precipitation (particularly snowpack) will decrease hydroelectric generation capability and increase resource costs and cash outflows needed to purchase electric resources in the wholesale market. Regional precipitation and snowpack conditions typically have a significant effect on the wholesale price of electricity. Additionally, colder weather in the winter and warmer weather in the summer can significantly increase the short-term price of energy commodities. On July 24, 2006, after several days at or near record high temperatures in eastern Washington and northern Idaho, Avista Utilities’ retail native peak load was 1,642 MW, an all-time high for Avista Utilities’ summer load.

Avista Utilities’ hydroelectric generation was 95 percent of normal in 2005. Hydroelectric generation has been below normal (based on a 70-year average) for five of the past six years. For 2006, Avista Utilities forecasts that hydroelectric generation will be 101 percent of normal, assuming normal conditions for the remainder of the year. This forecast may change based upon precipitation, temperatures and other variables during the fourth quarter.

Both Avista Utilities and Avista Energy are subject to electric and natural gas commodity price risk. Price risk is, in general, the risk of fluctuation in the market price of the commodity needed, held or traded. Changes in wholesale energy prices can affect, among other things, cash requirements needed to purchase electricity and natural gas for retail customers or wholesale obligations, as well as the market value of derivative assets and liabilities and unrealized gains and losses. Increasing energy commodity prices have a significant effect on liquidity for both Avista Utilities and Avista Energy. 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 prices increase above the level currently recovered in retail rates during periods when Avista Utilities must purchase energy, power and natural gas

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deferral balances will increase, which will negatively affect Avista Utilities’ operating cash flow and liquidity until such costs, with interest, are recovered from customers.

In December 2005, Avista Utilities received approval from the Washington Utilities and Transportation Commission (WUTC) to increase its base electric and natural gas rates effective January 1, 2006. Avista Utilities will continue to periodically file for rate adjustments for recovery of its operating costs and capital investments to provide opportunity to align earned returns with those allowed by regulatory agencies.

Avista Utilities’ net income was $0.5 million for the three months ended September 30, 2006, an increase from a net loss of $1.8 million for the three months ended September 30, 2005 primarily due to an increase in gross margin (operating revenues less resource costs) and certain income tax adjustments, partially offset by an increase in other operating expenses, taxes other than income taxes and interest expense.

Avista Utilities’ net income was $43.5 million for the nine months ended September 30, 2006, an increase from $35.6 million for the nine months ended September 30, 2005 primarily due to an increase in gross margin (operating revenues less resource costs). The increase in gross margin was partially offset by an increase in other operating expenses, taxes other than income taxes and interest expense. The increase in gross margin was due in part to a decrease in electric resource costs as compared to the amount included in base retail rates. This resulted in Avista Utilities recognizing a benefit of $3.4 million under the Washington ERM during the nine months ended September 30, 2006 compared to an expense of $7.5 million for the nine months ended September 30, 2005. It is possible that some or all of the benefit in 2006 may be reversed during the fourth quarter of 2006 if power supply costs exceed the amount included in base retail rates. In addition, the sale of claims against Enron Corporation and certain of its affiliates (collectively Enron) and the general rate increase implemented in Washington, contributed to the increase in gross margin and net income. For further information on the sale of claims against Enron, see the discussion of other electric revenues on page 47.

Avista Utilities plans to continue to invest in its generation, transmission and distribution systems with a focus on providing reliable service to its customers. Utility capital expenditures were $116.6 million for the nine months ended September 30, 2006. The Company has a utility capital budget of approximately $160 million for 2006. Significant projects include the continued enhancement of Avista Utilities’ transmission system and upgrades to generating facilities.

Energy Marketing and Resource Management (Avista Energy)

Avista Energy’s business activities include trading electricity and natural gas, as well as the 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 Canada, Ltd. (Avista Energy Canada) is a wholly owned subsidiary of Avista Energy that provides natural gas services to end-user industrial and commercial customers in British Columbia, Canada.

The earnings and cash flows of Avista Energy are by nature subject to significant variability because they are derived primarily from the day-to-day trading of electricity and natural gas and optimization of assets owned by other entities, rather than predictable long-term revenue streams, and because Avista Energy’s activities are for the most part subject to mark-to-market accounting. In addition, with respect to the management of natural gas storage and certain other contracts, Avista Energy’s earnings are subject to variability caused by the differences between the economic management and the required accounting for these assets and contracts. While Avista Energy has taken measures to enhance profitability and reduce the risk of losses in the future, this business will continue to have variability in its results.

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 energy markets in which Avista Energy operates continue to have volatile market prices and variations in liquidity.

The Energy Marketing Resource Management segment, which consists primarily of Avista Energy, had net income of $8.8 million for the three months ended September 30, 2006 compared to a net loss of $8.3 million for the three months ended September 30, 2005. The operations of Avista Energy are managed on an economic basis, reflecting contracts and assets under management at estimated market value, consistent with industry practices, which is different from the required accounting for certain contracts and physical assets under management. These differences primarily relate to Avista Energy’s management of natural gas inventory and its control of natural gas-fired generation through a power purchase agreement, as well as certain other agreements. These differences had an estimated $1.6 million after-tax positive effect on results for the third quarter of 2006, as compared to an estimated $7.7 million after-tax negative effect on results for the third quarter of 2005.

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The Energy Marketing Resource Management segment had net income of $9.2 million for the nine months ended September 30, 2006 compared to a net loss of $16.9 million for the nine months ended September 30, 2005. The estimated difference between the economic management and the required accounting for certain contracts and physical assets under management reduced net income by approximately $3.7 million for this segment for the nine months ended September 30, 2006 and increased the net loss by approximately $11.6 million for the nine months ended September 30, 2005. A significant portion of the difference for 2006 is expected to reverse in future periods when the contracts are settled or realized. The difference could increase or decrease due to changes in forward market prices. The net loss for the nine months ended September 30, 2005 was also due to losses in Avista Energy’s natural gas portfolio. The volatility in natural gas and electricity prices can result in significant variability in Avista Energy’s earnings from period to period.

The variability in the results of operations of the Energy Marketing and Resource Management segment has caused management to evaluate whether Avista Corp. should continue in this business, over the long term, as currently conducted and what, if any, strategic alternatives may be available.

Advantage IQ

Net income for Advantage IQ was $1.9 million and $4.9 million for the three and nine months ended September 30, 2006, respectively, an increase from $1.3 million and $3.0 million for the three and nine months ended September 30, 2005, respectively, primarily due to increased revenues from an expanding customer base.

Advantage IQ is considering certain strategic investments aimed at creating long-term savings that may increase operating and capitalized costs in the short-term through up-front expenditures. This could limit earnings growth through 2007 while enhancing Advantage IQ’s long-term profitability.

Other Business Segment

Over time as opportunities arise, the Company plans to continue to dispose of assets and phase out operations in the Other business segment. However, the Company may, from time to time, invest incremental funds in these businesses to protect its existing investments. The net loss in the Other business segment was $1.1 million and $2.5 million for the three and nine months ended September 30, 2006, respectively, compared to net losses of $0.2 million and $2.0 million for the three and nine months ended September 30, 2005, respectively. The increase in the net loss from the prior year was primarily due to certain income tax adjustments recorded in the third quarter of 2006.

Liquidity and Capital Resources

On April 6, 2006, Avista Corp. amended its committed line of credit agreement, which was originally entered into on December 17, 2004. Amendments to the committed line of credit include a reduction in the total amount of the facility to $320.0 million from $350.0 million and an extension of the expiration date to April 5, 2011 from December 16, 2009. The Company chose to reduce the facility based on forecasted liquidity needs. On March 20, 2006, Avista Corp. amended its accounts receivable sales facility to extend the termination date to March 20, 2007. Under this facility, the Company (through a subsidiary) can sell without recourse, on a revolving basis, up to $85.0 million of its accounts receivable.

For the fourth quarter of 2006, the Company expects net cash flows from operating activities 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. However, the Company currently expects to issue long-term debt in the fourth quarter of 2006 to partially fund debt that matures in December 2006 and January 2007. The Company expects that the new debt issuance would be at a lower rate than the maturing debt.

Succession Planning

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 also has workforce development plans for key technical and craft areas.

Avista Utilities – Regulatory Matters

General Rate Cases

In December 2005, the WUTC approved Avista Utilities’ combined electric and natural gas general rate case settlement agreement with certain conditions, which were subsequently accepted by the settling parties (Avista Utilities, the WUTC staff, the Northwest Industrial Gas Users and the Energy Project). The WUTC Order provided for base rate increases of 7.5 percent for electric and 0.6 percent for natural gas, effective January 1, 2006. The electric base rate increase is designed to increase annual revenues by $21.4 million. The majority of the increase in electric revenues is related to increased power supply costs. As such, a significant portion of the increase does not increase gross margin or net income, because it is matched by an increase in the amount of resource costs currently

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recognized in expense. The natural gas base rate increase is designed to increase annual revenues by approximately $1.0 million. The WUTC Order also provided for further review of the ERM as discussed at “Power Cost Deferrals and Recovery Mechanisms” below.

As part of the general rate case settlement agreement that was modified and approved by the WUTC Order, 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. Failure by Avista Utilities to meet those targets could result in a reduction in base rates of 2 percent for each target. The calculation of the utility equity component is essentially the ratio of the Company’s total common equity to total capitalization excluding, in each case, the Company’s investment in Avista Capital. The utility equity component was 33.3 percent as of September 30, 2006.

Production/Transmission Update

On August 31, 2006, Avista Utilities filed a request with the WUTC to increase electric rates for its Washington customers by an average of 8.8 percent. This request is designed to increase annual revenues by $28.9 million, of which approximately $10 million would increase gross margin. As such, approximately two-thirds of the revenue increase would not increase gross margin or net income, because it would be designed to recover an increase in resource costs recognized in expense. The proposed increase, referred to as a Production/Transmission Update (P/T Update) includes an update to those ERM-related production and transmission costs that are included in base retail rates. Avista Utilities is not requesting an increase in rates related to cost changes associated with administrative and general expenses, operation and maintenance expenses, or the cost of equity and capital structure. In this filing, however, Avista Utilities is proposing to flow through to customers the lower cost of debt the Company is experiencing since the last general rate case. Included in the P/T Update are investments to upgrade several of the Company’s hydroelectric generating units to increase their efficiency and the continued upgrades to the Company’s transmission system to increase reliability and transmission capability to serve growing customer demand. Also contributing to the need for the P/T Update are higher costs for purchasing and generating electricity to serve Avista Utilities’ customers. In October 2006, the Industrial Customers of Northwest Utilities (ICNU) and the Public Counsel Section of the Washington Attorney General’s Office (Public Counsel) filed motions to dismiss the Company’s P/T Update claiming that, among other things, the filing represents improper single-issue ratemaking and violates a prior ERM stipulation, as well as rate case filing requirements. ICNU and Public Counsel contend that the costs at issue should be addressed in a general rate case filing. The current schedule established by the WUTC indicates that new rates could become effective in April 2007.

Oregon Senate Bill 408

The Oregon Public Utility Commission (OPUC) has issued final rules related to Oregon Senate Bill 408 (OSB 408). OSB 408, which was enacted into law in 2005, requires the OPUC to direct the utility to establish an automatic adjustment clause to account for the difference between income taxes collected in rates and taxes paid to units of government, net of adjustments, when that difference exceeds $100,000. 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.

In September 2006, the OPUC issued an Order adopting final rules and an “apportionment method” that uses a three-factor formula consisting of property, payroll and sales for regulated operations of the utility in Oregon as the numerator and these same factors for the consolidated company as the denominator to determine the amount of consolidated taxes paid that are properly attributed to Oregon operations. The least of (1) the properly attributed amount of taxes paid using the apportionment method, (2) the amount of taxes determined on a stand-alone basis for Oregon operations and (3) total consolidated taxes paid is then compared to taxes collected in rates to determine if a refund or surcharge is required.

As required by OPUC orders, the Company, along with other utilities in Oregon, will file a private letter ruling request with the Internal Revenue Service in December 2006, seeking guidance with respect to whether OSB 408 and the related OPUC orders violate normalization rules for accounting for income taxes. Certain parties may also seek legislative changes related to OSB 408. At this point in time, the Company cannot predict whether OSB 408 and related orders from the OPUC will result in a refund or surcharge related to Oregon natural gas operations for 2006. Based on analysis of prior years and current rules, the Company does not expect that refunds to customers, if any, would exceed $1.5 million.

Natural Gas Decoupling

In April 2006, Avista Utilities filed with the WUTC a proposal to implement a natural gas decoupling mechanism. Decoupling means separating the direct link between natural gas sales volume and the recovery of Avista Utilities’ fixed cost of providing service, which does not include the cost of the natural gas itself. Because Avista Utilities’ current rate structures provide for recovery of the majority of its fixed costs on a per-therm (sales volume) basis,

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energy efficiency and conservation objectives are directly at odds with the recovery of fixed costs, which do not vary with the volume of natural gas sold. Decoupling breaks the link between the volume of sales and the recovery of fixed costs and would facilitate an increased focus on energy efficiency and conservation. In October 2006, the Company entered into a contested settlement agreement, which included the WUTC staff, with respect to the decoupling mechanism. Avista Utilities’ proposed decoupling mechanism is a three-year “pilot” that would begin early in 2007 if regulatory approval is received. A rate adjustment in any one year would be limited to no more than 2 percent. The filing of the first decoupling rate adjustment would be in the fall of 2007.

Power Cost Deferrals and Recovery Mechanisms

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 is an accounting method used to track certain differences between actual power supply costs and the amount included in base retail rates for Washington customers. These differences primarily result from changes in purchased power and fuel costs, as well as variations in the level of hydroelectric generation and retail loads. The initial amount of power supply costs in excess or below the level in retail rates, which the Company either incurs the cost of, or receives the benefit from, is referred to as the dead band. The annual dead band amount was $9.0 million since the implementation of the ERM on July 1, 2002, and the Company expensed the entire dead band each year through 2005 because its power supply costs exceeded the amount included in base retail rates by more than $9.0 million.

The WUTC rejected the proposal in the rate case settlement agreement to reduce the ERM dead band from $9.0 million to $3.0 million. However, Avista Utilities was directed to make a filing with the WUTC by January 31, 2006, to allow further review of the ERM. On January 31, 2006, Avista Utilities made its filing with the WUTC proposing that the ERM be continued for an indefinite period of time and that the $9.0 million dead band be eliminated. This filing also satisfied a previous requirement for Avista Utilities to make a filing by the end of 2006 for a review of the ERM.

On June 16, 2006, the WUTC approved a settlement agreement between the Company, the staff of the WUTC, the Industrial Customers of Northwest Utilities and the office of Public Counsel Section of the Washington Attorney General’s Office, representing all parties in the Company’s ERM proceeding. The settlement agreement provides for the continuation of the ERM with certain agreed-upon modifications and is effective as of January 1, 2006. The settling parties have agreed to review the ERM after five years.

The settlement agreement modified the ERM such that the Company’s annual dead band was reduced from $9.0 million to $4.0 million and the Company will incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. Annual power supply cost variances between $4.0 million and $10.0 million are shared equally between the Company and its customers. As such, 50 percent of the annual power supply cost variance in this range is deferred for future surcharge or rebate to the Company’s customers and the remaining 50 percent is an expense of, or benefit to, the Company. Once the annual power supply cost variance from the amount included in base rates exceeds $10.0 million, 90 percent of the cost variance is deferred for future surcharge or rebate. The remaining 10 percent of the variance beyond $10.0 million is an expense of, or benefit to, the Company without affecting current or future customer rates. The following table summarizes the historical (prior to January 1, 2006) and modified ERM (effective January 1, 2006):

Annual Power Supply Cost Variability	Deferred for Future Surcharge or Rebate to Customers		Expense or Benefit to the Company
Historical ERM:
+/- $0 - $9 million	0	%	100	%
+/- excess over $9 million	90	%	10	%
Modified ERM:
+/- $0 - $4 million	0	%	100	%
+/- between $4 million - $10 million	50	%	50	%
+/- excess over $10 million	90	%	10	%

Under the ERM, Avista Utilities will continue 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. In June 2006, the WUTC issued an order, which approved the recovery of the $4.1 million of deferred power costs incurred for 2005.

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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 amount included in base retail rates for Idaho customers. The PCA rate surcharge is currently 2.5 percent.

The following table shows activity in deferred power costs for Washington and Idaho during the nine months ended September 30, 2006 (dollars in thousands):

	Washington			Idaho			Total
Deferred power costs as of December 31, 2005	$	96,191		$	7,987		$	104,178
Activity from January 1 – September 30, 2006:
Power costs deferred		—			2,829			2,829
Interest and other net additions		3,321			217			3,538
Recovery of deferred power costs through retail rates		(22,558	)		(3,471	)		(26,029	)
Deferred power costs as of September 30, 2006	$	76,954		$	7,562		$	84,516

Purchased Gas Adjustments

During the third quarter of 2006, Avista Utilities filed purchased gas cost adjustment requests in Washington, Idaho and Oregon to adjust natural gas rates to reflect changes in natural gas costs, which were subsequently amended to reflect decreasing natural gas prices. Avista Utilities received approval for a 1.3 percent increase in Washington and a 3.4 percent decrease in Idaho effective November 1, 2006. Avista Utilities received approval for a 6.9 percent increase in Oregon effective November 1, 2006, subject to refund pending further review of Avista Utilities’ natural gas purchasing and hedging strategies. These natural gas rate increases and decreases are designed to pass through changes in purchased natural gas costs to customers with no change in Avista Utilities’ gross margin or net income. Total deferred natural gas costs were $27.6 million and $43.4 million as of September 30, 2006 and December 31, 2005, respectively.

Regional Transmission Organizations

The FERC continues to encourage the development of Regional Transmission Organizations. The structure of a Regional Transmission Organization (RTO) could significantly change how transmission facilities are planned and operated. Avista Corp. has participated in discussions with transmission providers and other stakeholders in the Pacific Northwest for several years regarding the possible formation of an RTO in the region. One such effort, Grid West, dissolved in late 2005 and Avista Corp. has received orders from the WUTC and the IPUC authorizing deferred accounting for the opportunity for future regulatory recovery of the $1.2 million of funds advanced to Grid West. The Company is currently participating in discussions and is funding the development of an alternative transmission entity, ColumbiaGrid, a Washington nonprofit membership corporation, created to improve the operational efficiency, reliability, and planned expansion of the transmission grid in the Pacific Northwest. ColumbiaGrid members elected an independent slate of directors to the three-member board in August 2006. ColumbiaGrid’s responsibilities and related agreements with its participating entities are currently being developed in a public process with broad participation. The focus of the public process is on the design and implementation of near-term services beginning in 2006, beginning with comprehensive regional transmission system planning activities, as well as the design of additional longer-term responsibilities.

Results of Operations

The following provides an overview of changes in the Company’s Consolidated Statements of Income for the three and nine months ended September 30, 2006 as compared to the three and nine months ended September 30, 2005. More detailed explanations are provided, particularly with respect to operating revenues and operating expenses in the business segment discussions (Avista Utilities, Energy Marketing and Resource Management, Advantage IQ and Other) that follow this section.

Three months ended September 30, 2006 compared to the three months ended September 30, 2005

Utility revenues increased $7.6 million to $229.3 million for the three months ended September 30, 2006 due to an increase in natural gas revenues of $9.1 million, partially offset by a decrease in electric revenues of $1.5 million. The increase in natural gas revenues was primarily due to the increased volume of wholesale natural gas sales and increased retail natural gas rates. The decrease in electric revenues primarily reflects a decrease in wholesale revenues and sales of fuel, partially offset by an increase in retail revenues.

Non-utility energy marketing and trading revenues increased $16.8 million to $47.7 million for the three months ended September 30, 2006 primarily due to increased net trading margin on contracts accounted for under SFAS No.

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133, partially offset by decreased revenues from sales of natural gas to commercial and industrial end-user customers (through Avista Energy Canada).

Other non-utility revenues increased $2.9 million to $16.0 million for the three months ended September 30, 2006 as a result of increased revenues from Advantage IQ of $2.2 million and increased revenues from the Other business segment of $0.7 million. The increase in revenues from Advantage IQ was primarily due to customer growth as well as an increase in interest earnings on funds held for customers. The increase from the Other business segment was primarily due to increased sales at AM&D.

Utility resource costs increased $2.7 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005 primarily due to increased natural gas resource costs of $8.9 million partially offset by decreased electric resource costs of $6.2 million. The increase in natural gas resource costs reflects the net amortization of deferred natural gas costs reflecting higher retail rates (through purchased gas cost adjustments) to collect deferred natural gas costs. The decrease in electric resource costs primarily reflects a decrease in purchased power costs (primarily due to a decrease in purchased power volumes).

Utility taxes other than income taxes increased $1.1 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005 primarily due to increased retail electric and natural gas revenues and related taxes.

Non-utility resource costs decreased $10.7 million primarily due to decreased resource costs related to sales of natural gas to commercial and industrial end-user customers (primarily through Avista Energy Canada) and partially due to a decrease in transportation and transmission costs.

Other non-utility operating expenses increased $2.8 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005 primarily from increased incentive compensation at Avista Energy due to increased earnings, increased operating expenses for Advantage IQ due to expanding operations, as well as increased operating expenses in the Other business segment.

Interest expense (including interest expense to affiliated trusts) increased $1.1 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005 primarily due to the issuance of fixed rate long-term debt that replaced variable rate short-term debt (which had relatively low interest rates in 2005) in the fourth quarter of 2005 and partially due to the effect of rising interest rates on variable rate long-term debt to affiliated trusts.

Income taxes increased $8.7 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005 primarily due to increased income before income taxes, partially offset by certain tax adjustments. In the third quarter of 2006, the Company recognized adjustments related to Internal Revenue Service audits and adjustments for the 2005 filed federal tax return. In total, these adjustments had a favorable impact to recorded tax expense of $1.3 million, with a positive effect at Avista Utilities of $1.7 million, partially offset by a negative effect in the Other business segment of $0.4 million.

Nine months ended September 30, 2006 compared to the nine months ended September 30, 2005

Utility revenues increased $131.0 million to $910.7 million for the nine months ended September 30, 2006 due to increases in electric revenues of $47.2 million and natural gas revenues of $83.7 million. The increase in electric revenues reflects an increase in retail revenues and sales of fuel. The increase in natural gas revenues was primarily due to the increased volume of wholesale natural gas sales and increased retail natural gas rates.

Non-utility energy marketing and trading revenues increased $38.8 million to $123.6 million for the nine months ended September 30, 2006 primarily due to increased net trading margin on contracts accounted for under SFAS No. 133, partially offset by decreased revenues from sales of natural gas to commercial and industrial end-user customers (primarily through Avista Energy Canada).

Other non-utility revenues increased $8.7 million to $45.3 million for the nine months ended September 30, 2006 as a result of increased revenues from Advantage IQ of $5.9 million and increased revenues from the Other business segment of $2.8 million. The increase in revenues from Advantage IQ was primarily due to customer growth as well as an increase in interest earnings on funds held for customers. The increase from the Other business segment was primarily due to increased sales at AM&D.

Utility resource costs increased $102.0 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 primarily due to increased electric resource costs of $23.0 million and increased

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natural gas resource costs of $79.0 million. The increase in electric resource costs reflects an increase in base resource costs as set forth in the Washington general rate case implemented on January 1, 2006, as well as an increase in fuel for generation and other fuel costs (representing the economic sale of fuel that was not used in generation). The increase in natural gas resource costs reflects an increase in natural gas purchased due to an increase in both the volume and price of purchases.

Utility other operating expenses increased $5.7 million primarily due to increased generation maintenance costs of $2.1 million, increased administrative and general compensation expenses of $2.3 million, increased stock and performance based compensation of $1.7 million and increased injury and damages expenses of $1.2 million, partially offset by decreased regulatory commission expenses of $2.2 million.

Utility taxes other than income taxes increased $5.4 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 primarily due to increased retail electric and natural gas revenues and related taxes.

Other non-utility operating expenses increased $6.9 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 primarily from increased incentive compensation at Avista Energy due to increased earnings, increased operating expenses for Advantage IQ due to expanding operations, as well as increased operating expenses in the Other business segment.

Interest expense (including interest expense to affiliated trusts) increased $2.8 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 primarily due to the issuance of fixed rate long-term debt that replaced variable rate short-term debt (which had relatively low interest rates in 2005) in the fourth quarter of 2005 and partially due to the effect of rising interest rates on variable rate long-term debt to affiliated trusts.

Income taxes increased $18.4 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 primarily due to increased income before income taxes. The effective tax rate was 35.0 percent for the nine months ended September 30, 2006 compared to 36.5 percent for the nine months ended September 30, 2005. The decrease in the effective tax rate was primarily due to certain tax adjustments. In the third quarter of 2006, the Company recognized adjustments related to Internal Revenue Service audits and adjustments for the 2005 filed federal tax return. In total, these adjustments had a favorable impact to recorded tax expense of $1.3 million, with a positive effect at Avista Utilities of $1.7 million, partially offset by a negative effect in the Other business segment of $0.4 million.

Avista Utilities

Three months ended September 30, 2006 compared to the three months ended September 30, 2005

Net income for Avista Utilities was $0.5 million for the three months ended September 30, 2006 compared to a net loss of $1.8 million for the three months ended September 30, 2005. Avista Utilities’ income from operations was $18.7 million for the three months ended September 30, 2006 compared to $17.3 million for the three months ended September 30, 2005. The increase in income from operations was primarily due to increased gross margin (operating revenues less resource costs), partially offset by increases in utility taxes other than income taxes (consistent with an increase in retail revenues) and an increase in other utility operating expenses.

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

	Electric				Natural Gas				Total
	2006		2005		2006		2005		2006		2005
Operating revenues	$	171,741	$	173,210	$	57,594	$	48,499	$	229,335	$	221,709
Resource costs		85,902		92,061		43,344		34,450		129,246		126,511
Gross margin	$	85,839	$	81,149	$	14,250	$	14,049	$	100,089	$	95,198

Avista Utilities’ operating revenues increased $7.6 million and resource costs increased $2.7 million, which resulted in an increase of $4.9 million in gross margin for the three months ended September 30, 2006 as compared to the three months ended September 30, 2005. The gross margin on electric sales increased $4.7 million and the gross margin on natural gas sales increased $0.2 million. Electric resource costs were higher than the amount included in base retail rates resulting in the expense of $3.8 million of power supply costs above the amount included in base retail rates in Washington under the ERM during the third quarter of 2006, compared to the expense of an additional $8.2 million of power supply costs for the third quarter of 2005. The remaining increase in electric gross margin was due to the general rate increase implemented on January 1, 2006 and customer growth.

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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
	2006		2005		2006	2005
Residential	$	51,363	$	45,152	781	731
Commercial		58,437		51,816	827	769
Industrial		24,022		23,782	529	541
Public street and highway lighting		1,329		1,242	6	6
Total retail		135,151		121,992	2,143	2,047
Wholesale		26,542		40,260	411	597
Sales of fuel		5,776		6,869	—	—
Other		4,272		4,089	—	—
Total	$	171,741	$	173,210	2,554	2,644

Retail electric revenues increased $13.2 million for the three months ended September 30, 2006 as compared to the three months ended September 30, 2005. This increase was primarily due to an increase in revenue per MWh (increased revenues $7.1 million) and an increase in total MWhs sold (increased revenues $6.1 million). The increase in revenue per MWh was primarily due to the Washington general rate increase of 7.5 percent as well as a 1.0 percent increase in the ERM surcharge, both of which were implemented on January 1, 2006. The increase in total MWhs sold was primarily due to customer growth and partially due to an increase in use per customer.

Wholesale electric revenues decreased $13.7 million primarily due to a decrease in wholesale sales volumes (decreased revenues $11.9 million) and partially due to a slight decrease in wholesale sales prices (decreased revenues $1.8 million).

Sales of fuel decreased $1.1 million as less fuel was sold based on wholesale prices and resource needs. Sales of fuel represent 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.

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
	2006		2005		2006	2005
Residential	$	20,526	$	18,337	13,348	14,601
Commercial		14,124		12,052	11,362	12,144
Industrial		2,389		2,460	2,266	3,078
Total retail		37,039		32,849	26,976	29,823
Wholesale		18,129		13,255	33,619	18,490
Transportation		1,407		1,466	31,336	32,110
Other		1,019		929	13	18
Total	$	57,594	$	48,499	91,944	80,441

Natural gas revenues increased $9.1 million for the three months ended September 30, 2006 from the three months ended September 30, 2005 due to an increase in retail and wholesale natural gas revenues. The $4.2 million increase in retail natural gas revenues was primarily due to an increase in retail rates (increased revenues $8.1 million), partially offset by a decrease in volumes (decreased revenues $3.9 million). During September through November of 2005, retail rates for natural gas were increased in response to an increase in natural gas costs. The decrease in total therms sold was primarily due to a decrease in use per customer, partially offset by customer growth. The increase in wholesale revenues reflects the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process.

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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
	2006	2005	2006	2005
Residential	300,494	293,668	266,040	258,109
Commercial	37,863	37,239	31,654	31,127
Industrial	1,386	1,411	293	310
Public street and highway lighting	421	425	—	—
Total retail	340,164	332,743	297,987	289,546
Wholesale	46	46	17	10
Transportation	—	—	80	97
Total customers	340,210	332,789	298,084	289,653

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

	2006			2005
Electric resource costs:
Power purchased	$	45,184		$	54,935
Power cost amortizations (deferrals), net		(3,376	)		4,480
Fuel for generation		37,109			26,173
Other fuel costs		4,619			5,271
Other regulatory amortizations, net		(1,041	)		(1,271	)
Other electric resource costs		3,407			2,473
Total electric resource costs		85,902			92,061
Natural gas resource costs:
Natural gas purchased		40,356			41,475
Natural gas amortizations (deferrals), net		2,787			(7,291	)
Other regulatory amortizations, net		201			266
Total natural gas resource costs		43,344			34,450
Total resource costs	$	129,246		$	126,511

Power purchased for the three months ended September 30, 2006 decreased $9.8 million compared to the three months ended September 30, 2005 primarily due to a decrease in the volume of power purchases (decreased costs $8.0 million) and partially due to a decrease in the price of power purchases (decreased costs $1.8 million). The decrease in the volume of power purchases was primarily due to the higher cost of wholesale power relative to the cost of thermal generation (primarily based on fuel prices). The lower volume of power purchased is also consistent with a decrease in wholesale sales volumes and decreased resource optimization activities.

Net power cost deferrals were $3.4 million for the three months ended September 30, 2006 compared to $4.5 million of net amortization for the three months ended September 30, 2005. During the three months ended September 30, 2006, Avista Utilities recovered (collected as revenue) $7.4 million of previously deferred power costs in Washington and $1.1 million in Idaho. During the three months ended September 30, 2006, Avista Utilities deferred $7.1 million of power costs exceeding the amount included in base retail rates in Idaho. During the three months ended September 30, 2006, Avista Utilities reversed the previous deferral of $4.7 million of power costs below the amount included in base retail rates for the first half of 2006 as power costs were higher than the amount included in base retail rates for the third quarter of 2006.

Fuel for generation increased $10.9 million for the three months ended September 30, 2006 as compared to the three months ended September 30, 2005 primarily due to increased use of thermal generation due to higher retail electric energy demand, the lower cost of natural gas relative to wholesale electric market prices and decreased hydroelectric generation.

The expense for natural gas purchased for the three months ended September 30, 2006 decreased $1.1 million compared to the three months ended September 30, 2005 due to a decrease in the cost of natural gas (decreased costs $9.3 million), partially offset by an increase in total therms purchased (increased costs $8.2 million). The increase in total therms purchased was primarily related to an increase in wholesale sales as part of the balancing of loads and resources with the natural gas procurement process, partially offset by a decrease in retail sales volumes. During the three months ended September 30, 2006, Avista Utilities had $2.8 million of net amortization of deferred natural gas costs compared to $7.3 million of net deferrals for the three months ended September 30, 2005. The change reflects higher retail rates (through purchased gas cost adjustments) to collect deferred natural gas costs.

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Nine months ended September 30, 2006 compared to the nine months ended September 30, 2005

Net income for Avista Utilities was $43.5 million for the nine months ended September 30, 2006 compared to $35.6 million for the nine months ended September 30, 2005. Avista Utilities’ income from operations was $130.9 million for the nine months ended September 30, 2006 compared to $117.8 million for the nine months ended September 30, 2005. This increase was primarily due to increased gross margin (operating revenues less resource costs). The increase in gross margin was partially offset by increases in utility taxes other than income taxes (consistent with an increase in retail revenues) and an increase in other utility operating expenses, as well as the $4.1 million pre-tax gain related to the sale of the South Lake Tahoe natural gas distribution properties in 2005.

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

	Electric				Natural Gas				Total
	2006		2005		2006		2005		2006		2005
Operating revenues	$	566,243	$	519,002	$	344,458	$	260,741	$	910,701	$	779,743
Resource costs		258,004		235,012		264,933		185,934		522,937		420,946
Gross margin	$	308,239	$	283,990	$	79,525	$	74,807	$	387,764	$	358,797

Avista Utilities’ operating revenues increased $131.0 million and resource costs increased $102.0 million, which resulted in an increase of $29.0 million in gross margin for the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005. The gross margin on electric sales increased $24.3 million and the gross margin on natural gas sales increased $4.7 million. The increase in electric gross margin was partially due to a decrease in electric resource costs as compared to the amount included in base retail rates resulting in the benefit of $3.4 million of power supply costs in Washington below the amount included in base retail rates during the nine months ended September 30, 2006, compared to the expense of $7.5 million of power supply costs above the amount included in base retail rates for the nine months ended September 30, 2005. This was primarily a result of improved hydroelectric generation from higher than normal precipitation and snowpack resulting in increased streamflows to hydroelectric generating facilities during the first half of 2006. It is possible that some or all of this benefit may be reversed and additional expenses may be absorbed by Avista Utilities during the fourth quarter of 2006 if power supply costs exceed the amount included in base retail rates. The increase in electric gross margin was also partially due to the sale of claims against Enron-related entities in the first quarter of 2006, the Washington general rate increase implemented on January 1, 2006 and customer growth. The increase in the gross margin on natural gas sales was primarily due to customer growth in the Washington, Idaho and Oregon service territories. The effects of general rate increases and customer growth were partially offset by the sale of the South Lake Tahoe natural gas operations 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
	2006		2005		2006	2005
Residential	$	168,294	$	149,986	2,561	2,421
Commercial		164,420		150,615	2,309	2,217
Industrial		70,297		68,899	1,558	1,570
Public street and highway lighting		3,928		3,711	18	19
Total retail		406,939		373,211	6,446	6,227
Wholesale		98,971		100,737	1,815	1,959
Sales of fuel		45,023		33,122	—	—
Other		15,310		11,932	—	—
Total	$	566,243	$	519,002	8,261	8,186

Retail electric revenues increased $33.7 million for the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005. This increase was primarily due to an increase in revenue per MWh (increased revenues $19.9 million) and an increase in total MWhs sold (increased revenues $13.8 million). The increase in revenue per MWh was primarily due to the Washington general rate increase of 7.5 percent as well as a 1.0 percent increase in the ERM surcharge, both of which were implemented on January 1, 2006. The increase in total MWhs sold was primarily due to customer growth and partially due to an increase in use per customer.

Wholesale electric revenues decreased $1.8 million primarily due to a decrease in wholesale sales volumes (decreased revenues $7.9 million) partially offset by an increase in wholesale sales prices (increased revenues $6.1 million).

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Sales of fuel increased $11.9 million as a greater percentage of fuel purchases were not used in generation (during the first quarter of 2006). Sales of fuel represent 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. The increase primarily reflects an increase in the volume of sales of fuel.

Other electric revenues increased $3.4 million primarily as a result of revenues from the sale of Enron claims. During the first quarter of 2006, the Company made the decision to sell claims that it had against certain Enron-related entities. These claims were for damages that the Company suffered as a result of the breach of a construction agreement for the Coyote Springs 2 generation plant. The Company received approximately $8.5 million from the sale of these claims of which $5.5 million was applied to reduce the capitalized cost of the plant and the remaining $3.0 million was recorded as other electric revenues based on the lost margin opportunities from the plant in prior periods.

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
	2006		2005		2006	2005
Residential	$	164,120	$	140,491	121,751	128,042
Commercial		94,355		76,550	77,814	79,212
Industrial		8,544		7,674	8,089	9,506
Total retail		267,019		224,715	207,654	216,760
Wholesale		69,026		27,046	115,176	41,388
Transportation		4,772		5,899	111,567	115,283
Other		3,641		3,081	320	348
Total	$	344,458	$	260,741	434,717	373,779

Natural gas revenues increased $83.7 million for the nine months ended September 30, 2006 from the nine months ended September 30, 2005 due to an increase in retail and wholesale natural gas revenues. The $42.3 million increase in retail natural gas revenues was primarily due to an increase in retail rates (increased revenues $54.0 million), partially offset by a decrease in volumes (decreased revenues $11.7 million). During September through November of 2005, retail rates for natural gas were increased in response to an increase in natural gas costs. The decrease in total therms sold was primarily due to the sale of the South Lake Tahoe properties and a decrease in use per customer, partially offset by customer growth in the other service territories. The increase in wholesale revenues reflects the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process that was implemented at Avista Utilities effective April 1, 2005.

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
	2006	2005	2006	2005
Residential	299,856	293,072	266,378	266,008
Commercial	37,811	37,198	31,671	31,757
Industrial	1,390	1,411	295	309
Public street and highway lighting	428	419	—	—
Total retail	339,485	332,100	298,344	298,074
Wholesale	47	44	18	8
Transportation	—	—	77	93
Total customers	339,532	332,144	298,439	298,175

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

	2006			2005
Electric resource costs:
Power purchased	$	113,074		$	120,094
Power cost amortizations, net of deferrals		23,200			21,701
Fuel for generation		70,150			61,632
Other fuel costs		47,007			30,249
Other regulatory amortizations, net		(4,111	)		(5,134	)
Other electric resource costs		8,684			6,470
Total electric resource costs		258,004			235,012
Natural gas resource costs:
Natural gas purchased		245,330			189,064
Natural gas amortizations, net of deferrals		18,033			(5,499	)
Other regulatory amortizations, net		1,570			2,369
Total natural gas resource costs		264,933			185,934
Total resource costs	$	522,937		$	420,946

Power purchased for the nine months ended September 30, 2006 decreased $7.0 million compared to the nine months ended September 30, 2005 primarily due to a decrease in the price of power purchases (decreased costs $5.7 million) and a decrease in the volume of power purchases (decreased costs $1.3 million). The decrease in the volume of power purchases was primarily due to the higher cost of wholesale power relative to the cost of thermal generation (primarily based on fuel prices) during the third quarter of 2006.

Net amortization of deferred power costs was $23.2 million for the nine months ended September 30, 2006 compared to $21.7 million for the nine months ended September 30, 2005. During the nine months ended September 30, 2006, Avista Utilities recovered (collected as revenue) $22.6 million of previously deferred power costs in Washington and $3.5 million in Idaho. During the nine months ended September 30, 2006, Avista Utilities deferred $2.8 million in Idaho of power costs above the amount included in base retail rates. Avista Utilities did not defer any power cost expense or benefit in Washington during the nine months ended September 30, 2006, as costs were within the initial $4.0 million in power costs below the amount included in base retail rates under the ERM.

Fuel for generation increased $8.5 million for the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005 primarily due to higher natural gas fuel prices.

Other fuel costs increased $16.8 million for the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005. This natural gas fuel was sold as part of the resource optimization process with the associated revenues reflected as sales of fuel. Other fuel costs exceeded revenues from selling the natural gas. This excess cost is accounted for under the ERM in Washington and the PCA in Idaho. The increase in other fuel costs was primarily due to a reduced percentage of fuel used in generation (during the first quarter of 2006) and higher natural gas fuel prices.

The expense for natural gas purchased for the nine months ended September 30, 2006 increased $56.3 million compared to the nine months ended September 30, 2005 due to an increase in the cost of natural gas (increased costs $49.1 million) and an increase in total therms purchased (increased costs $7.2 million). The increase in total therms purchased is related to an increase in wholesale sales as part of the balancing of loads and resources with the natural gas procurement process, partially offset by a slight decrease in retail sales volumes. During the nine months ended September 30, 2006, Avista Utilities had $18.0 million of net amortization of deferred natural gas costs compared to net deferrals of $5.5 million for the nine months ended September 30, 2005. The change reflects higher retail rates (through purchased gas cost adjustments) to collect deferred natural gas costs.

Energy Marketing and Resource Management

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

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

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

• 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.

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• 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.

• Marketing natural gas to end-user industrial and commercial customers.

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 gains (losses) for the three and nine months ended September 30 (dollars in thousands):

	Three months ended September 30,					Nine months ended September 30
	2006		2005			2006		2005
Net realized gains	$	6,534	$	8,244		$	24,007	$	20,731
Net unrealized gains (losses)		11,379		(17,832	)		1,440		(35,129	)
Total gross margin (operating revenues less resource costs)	$	17,913	$	(9,588	)	$	25,447	$	(14,398	)

Overall segment results for the three months ended September 30, 2006 compared to the three months ended September 30, 2005

Energy Marketing and Resource Management had net income of $8.8 million for the three months ended September 30, 2006 compared to a net loss of $8.3 million for the three months ended September 30, 2005. The estimated difference between the economic management and the required accounting for certain contracts and physical assets under management increased net income by approximately $1.6 million for this segment for the three months ended September 30, 2006. This estimated difference increased the net loss by approximately $7.7 million for the three months ended September 30, 2005.

Overall segment results for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005

Energy Marketing and Resource Management had net income of $9.2 million for the nine months ended September 30, 2006 compared to a net loss of $16.9 million for the nine months ended September 30, 2005. The estimated difference between the economic management and the required accounting for certain contracts and physical assets under management reduced net income by approximately $3.7 million for this segment for the nine months ended September 30, 2006. A significant portion of this difference is expected to reverse in future periods when the contracts are settled or realized. The net loss for the nine months ended September 30, 2005 was due to losses in Avista Energy’s natural gas portfolio. The net loss for 2005 was increased by $11.6 million due to the effects of differences between the economic management and the required accounting for certain energy contracts and physical assets under management.

Differences in the economic management and the required accounting for certain contracts and physical assets under management

Avista Energy is affected by earnings variability associated with the estimated difference between the economic management and the required accounting for certain contracts and physical assets under management as disclosed above. The operations of Avista Energy are managed on an economic basis reflecting contracts and assets under management at estimated market value. 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 affect 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, although the amount of the difference could increase or decrease due to changes in forward market prices. These differences primarily relate to Avista Energy’s management of natural gas inventory and Avista Energy’s control of natural gas-fired generation through a power purchase agreement. Please refer to the 2005 Form 10-K for a detailed discussion of these differences. Avista Energy has other differences between the economic management and the required accounting for certain contracts and physical assets under management, which have not been as significant as those described in the 2005 Form 10-K. However, these items could become more significant in the future and Avista Energy could enter into new contracts and agreements that could result in significant differences in future periods.

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Analysis of operating revenues, resource costs and gross margin for the three months ended September 30, 2006 compared to the three months ended September 30, 2005

Operating revenues increased $16.8 million and resource costs decreased $10.7 million for the three months ended September 30, 2006 as compared to the three months ended September 30, 2005 resulting in an increase in gross margin of $27.5 million. Operating revenues increased primarily due to increased net trading margin on contracts accounted for under SFAS No. 133, partially offset by decreased revenues from sales of natural gas to commercial and industrial end-user customers (through Avista Energy Canada). Resource costs decreased primarily due to decreased resource costs related to sales of natural gas to commercial and industrial end-user customers (primarily through Avista Energy Canada) and partially due to a decrease in transportation and transmission costs.

Avista Energy’s gross margin (operating revenues less resource costs) was a gain of $17.9 million for the three months ended September 30, 2006 compared to a loss of $9.6 million for the three months ended September 30, 2005. The increase was primarily due to unrealized gains associated with the accounting for Avista Energy’s management of natural gas inventory (as compared to unrealized losses in 2005) and improved results from natural gas trading activities (which had significant losses in 2005).

Net realized gains decreased to $6.5 million for the three months ended September 30, 2006 from $8.2 million for the three months ended September 30, 2005. The decrease in net realized gains was due to decreased net gains on physical electric transactions and increased net losses on settled financial transactions, partially offset by decreased net losses on physical natural gas transactions. The total mark-to-market adjustment for Energy Marketing and Resource Management was a net unrealized gain of $11.4 million for the three months ended September 30, 2006 compared to a net unrealized loss of $17.8 million for the three months ended September 30, 2005.

Analysis of operating revenues, resource costs and gross margin for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005

Operating revenues increased $19.3 million and resource costs decreased $20.5 million for the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005 resulting in an increase in gross margin of $39.8 million. Operating revenues increased primarily due to increased net trading margin on contracts accounted for under SFAS No. 133, partially offset by decreased revenues from sales of natural gas to commercial and industrial end-user customers (primarily through Avista Energy Canada) and decreased revenues under the Agency Agreement with Avista Utilities as natural gas procurement operations were transitioned to Avista Utilities effective April 1, 2005. Resource costs decreased primarily due to decreased resource costs under the Agency Agreement with Avista Utilities and partially due to decreased resource costs related to sales of natural gas to commercial and industrial end-user customers.

Avista Energy’s gross margin (operating revenues less resource costs) was a gain of $25.4 million for the nine months ended September 30, 2006 compared to a loss of $14.4 million for the nine months ended September 30, 2005. The increase was primarily due to unrealized losses associated with the accounting for Avista Energy’s management of natural gas inventory in 2005 and improved results from natural gas trading activities (which had significant losses in 2005).

Net realized gains increased to $24.0 million for the nine months ended September 30, 2006 from $20.7 million for the nine months ended September 30, 2005. The increase in net realized gains was primarily due to decreased net losses on physical natural gas transactions, partially offset by decreased net gains on physical electric transactions and increased net losses on settled financial transactions. The total mark-to-market adjustment for Energy Marketing and Resource Management was a net unrealized gain of $1.4 million for the nine months ended September 30, 2006 compared to a net unrealized loss of $35.1 million for the nine months ended September 30, 2005.

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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, 2006 (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, 2005	$	18,682		$	15,769		$	34,451
Less contracts settled during 2006 (1)		(37,061	)		13,054			(24,007	)
Fair value of new contracts when entered into during 2006 (2)		—			—			—
Change in fair value due to changes in valuation techniques (3)		—			—			—
Change in fair value attributable to market prices and other market changes		47,539			(23,836	)		23,703
Fair value of contracts as of September 30, 2006	$	29,160		$	4,987		$	34,147

(1) Contracts settled during 2006 include those contracts that were open in 2005 but settled during the nine months ended September 30, 2006 as well as new contracts entered into and settled during 2006. Amount represents net realized gains associated with these settled transactions.

(2) Avista Energy did not enter into any origination transactions during the nine months ended September 30, 2006 in which dealer profit or mark-to-market gain or loss was recorded at inception.

(3) During the nine months ended September 30, 2006, 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, 2006 (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)	$	23,085		$	28,650		$	—		$	—		$	51,735
Fair value based on valuation models (2)		(973	)		(828	)		2,714			(23,488	)		(22,575	)
Total electric assets (liabilities), net	$	22,112		$	27,822		$	2,714		$	(23,488	)	$	29,160
Natural gas assets (liabilities), net
Prices from other external sources (1)	$	9,429		$	(3,852	)	$	—		$	—		$	5,577
Fair value based on valuation models (3)		698			(1,204	)		(77	)		(7	)		(590	)
Total natural gas assets (liabilities), net	$	10,127		$	(5,056	)	$	(77	)	$	(7	)	$	4,987

(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.

Avista Power

Rathdrum Power, LLC (RP LLC), an unconsolidated entity that was 49 percent owned by Avista Power, LLC, operates a 270 MW natural gas-fired combined cycle combustion turbine plant in northern Idaho. In October 2006, Avista Power completed the sale of its investment in RP LLC for approximately book value.

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Advantage IQ

Three months ended September 30, 2006 compared to the three months ended September 30, 2005

Net income for Advantage IQ was $1.9 million for the three months ended September 30, 2006 compared to $1.3 million for the three months ended September 30, 2005. Operating revenues for Advantage IQ increased $2.2 million and operating expenses increased $1.1 million. The increase in operating revenues was primarily due to the expansion of Advantage IQ’s customer base as well as an increase in interest earnings on funds held for customers. Advantage IQ has approximately 360 customers representing approximately 196,000 billed sites in North America. The number of billed sites increased by approximately 36,000, or 22 percent, from September 30, 2005. The increase in interest earnings on funds held for customers was due in part to an increase in interest rates. The increase in operating expenses primarily reflects increased labor costs necessary to serve an expanding customer base.

Nine months ended September 30, 2006 compared to the nine months ended September 30, 2005

Net income for Advantage IQ was $4.9 million for the nine months ended September 30, 2006 compared to $3.0 million for the nine months ended September 30, 2005. Operating revenues for Advantage IQ increased $5.9 million and operating expenses increased $3.0 million. The increase in operating revenues was primarily due to the expansion of Advantage IQ’s customer base as well as an increase in interest earnings on funds held for customers. The increase in interest earnings on funds held for customers was due in part to an increase in interest rates. The increase in operating expenses primarily reflects increased labor costs necessary to serve an expanding customer base. During the nine months ended September 30, 2006, Advantage IQ processed bills totaling $8.1 billion, an increase of $1.4 billion, or 20 percent, as compared to the nine months ended September 30, 2005.

Other Business Segment

Three months ended September 30, 2006 compared to the three months ended September 30, 2005

The net loss from this business segment was $1.1 million for the three months ended September 30, 2006 compared to a net loss of $0.2 million for the three months ended September 30, 2005. Operating revenues from this business segment increased $0.7 million and operating expenses increased $0.6 million, respectively. Net income for AM&D was $0.1 million for the three months ended September 30, 2006 compared to a net loss of less than $0.1 million for the three months ended September 30, 2005. In the third quarter of 2006, the results for the Other segment reflect adjustments related to Internal Revenue Service audits and adjustments for the 2005 filed federal tax return. In total, these adjustments had an unfavorable impact to recorded tax expense at the Other segment and increased the net loss by $0.4 million.

Nine months ended September 30, 2006 compared to the nine months ended September 30, 2005

The net loss from this business segment was $2.5 million for the nine months ended September 30, 2006 compared to a net loss of $2.0 million for the nine months ended September 30, 2005. Operating revenues from this business segment increased $2.8 million and operating expenses increased $2.3 million, respectively. Net income for AM&D was $0.2 million for the nine months ended September 30, 2006 compared to a net loss of $0.6 million for the nine months ended September 30, 2005. The improvement for AM&D was offset by the accrual for an environmental liability in the first quarter of 2006, an increase in the loss on certain investments in this segment not related to AM&D, as well as certain income tax adjustments recorded during the third quarter of 2006 as discussed above.

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. 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 2005 Form 10-K and have not changed materially from that discussion.

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New Accounting Standards

Effective January 1, 2006, the Company adopted SFAS No. 123R, which requires that compensation costs relating to share-based payment transactions be recognized in financial statements based on the fair value of the equity or liability instruments issued. The Company adopted SFAS No. 123R using the modified prospective method and, accordingly, financial statement amounts for prior periods presented have not been restated to reflect the fair value method of recognizing compensation expense relating to share-based payments. For the three and nine months ended September 30, 2006, the Company recorded $0.9 million and $2.9 million (pre-tax), respectively, of stock-based compensation expense, which is included in other operating expenses in the Consolidated Statements of Income. The Company expects to recognize total stock-based compensation expense (pre-tax) of $0.8 million, $2.0 million and $1.1 million during the fourth quarter of 2006, and the years 2007 and 2008, respectively, for stock-based awards granted to employees prior to September 30, 2006. For further information see “Notes 1, 2 and 12 of the Notes to Consolidated Financial Statements.”

In June 2006, the FASB issued FIN 48, which provides guidance for the recognition and measurement of a tax position taken or expected to be taken in a tax return. The Company will be required to adopt FIN 48 in 2007. The Company is evaluating the impact FIN 48 will have on its financial condition and results of operations. For further information see Note 2 of the Notes to Consolidated Financial Statements.

In September 2006, the FASB issued SFAS No. 157, which provides enhanced guidance for using fair value to measure assets and liabilities. The Company will be required to adopt SFAS No. 157 in 2008. The Company is evaluating the impact SFAS No. 157 will have on its financial condition and results of operations. For further information see Note 2 of the Notes to Consolidated Financial Statements.

In September 2006, the FASB issued SFAS No. 158, which will require the Company to recognize the overfunded or underfunded status of defined benefit postretirement plans in the Company’s Consolidated Balance Sheet measured as the difference between the fair value of plan assets and the projected benefit obligation. The Company is evaluating the impact this statement will have on its financial condition and results of operations. Based on the Company’s benefit obligations and fair value of plan assets as of December 31, 2005, the adoption of this statement would result in the recognition of an additional liability and corresponding charge to other comprehensive income (a component of stockholders’ equity). The actual impact of the adoption of this statement as of December 31, 2006 could differ significantly primarily due to plan asset performance for 2006 and the discount rate in effect as of December 31, 2006 when the projected benefit obligation is measured. The Company is also evaluating regulatory accounting treatment, which may allow the Company to recognize this item as a regulatory asset rather than as a charge to other comprehensive income. The adoption of this statement is not expected to have a material effect on the Company’s net income. For further information see Note 2 of the Notes to Consolidated Financial Statements.

In September 2006, the SEC issued SAB No. 108, which addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year financial statements. SAB No. 108 requires companies to quantify misstatements using a balance sheet and income statement approach and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. The Company is currently evaluating the impact, if any, of adopting SAB No. 108 in the fourth quarter of 2006.

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Liquidity and Capital Resources

Review of Cash Flow Statement

Overall During the nine months ended September 30, 2006, positive cash flows from operating activities of $171.5 million were used to fund the Company’s cash requirements, including utility capital expenditures of $116.6 million and dividends of $20.8 million. In addition, as cash flows from operating activities and other sources of cash inflows exceeded other funding requirements, total debt decreased $41.2 million during the nine months ended September 30, 2006 and the Company’s total cash and cash equivalents increased $5.7 million during the period.

Operating Activities Net cash provided by operating activities was $171.5 million for the nine months ended September 30, 2006 compared to $151.9 million for the nine months ended September 30, 2005. Net cash provided by working capital components was $38.4 million for the nine months ended September 30, 2006, compared to net cash used of $13.7 million for the nine months ended September 30, 2005. The net cash provided during 2006 primarily reflects a decrease in accounts receivable (representing net cash received from customers), other current liabilities (primarily due to an increase in customer fund obligations at Advantage IQ) and cash deposits from counterparties (representing cash received as collateral funds from counterparties), partially offset by a decrease in accounts payable (representing net cash paid to vendors) and other current assets (primarily due to an increase in funds held for customers at Advantage IQ). 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. Significant non-cash items included $40.6 million of power and natural gas cost amortizations, net of deferrals, for the nine months ended September 30, 2006, an increase from $15.8 million for the nine months ended September 30, 2005 primarily due to an increase in recoveries of previously deferred costs from customers. Significant changes in non-cash items also included a $36.6 million change in energy commodity assets and liabilities, representing the change to an unrealized gain of $1.4 million on energy trading activities for Avista Energy for the nine months ended September 30, 2006 as compared 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 $108.1 million for the nine months ended September 30, 2006, a decrease compared to $152.0 million for the nine months ended September 30, 2005. The decrease was primarily due to a decrease in utility property capital expenditures, which included $57.5 million for the purchase of Coyote Springs 2 in 2005. Investing activities for the nine months ended September 30, 2006 included the receipt of $5.5 million from the sale of a claim against an affiliate of Enron Corporation related to the construction of Coyote Springs 2 and proceeds of $6.8 million from the sale of a turbine at Avista Power. During the nine months ended September 30, 2005, the Company received $16.6 million for the sale of its South Lake Tahoe natural gas distribution properties.

Financing Activities Net cash used in financing activities was $57.7 million for the nine months ended September 30, 2006 compared to net cash used of $25.2 million for the nine months ended September 30, 2005. During the nine months ended September 30, 2006, the Company had debt redemptions and maturities of $39.7 million. Cash dividends paid increased to $20.8 million (or 42.5 cents per share) for the nine months ended September 30, 2006 from $19.6 million (or 40.5 cents per share) for the nine months ended September 30, 2005.

During the nine months ended September 30, 2005, short-term borrowings increased $89.0 million, which reflected 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.

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 for Avista Utilities 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.

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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.”

As of September 30, 2006, current liabilities exceeded current assets by $111.1 million primarily due to $170.8 million of current portion of long-term debt. Avista Corp. currently expects to issue long-term debt in the fourth quarter of 2006 to partially fund $170.0 million of debt that matures in December 2006 and January 2007. The Company expects that the new debt issuance would be at a lower rate than the maturing debt.

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.

The general rate increases that have been implemented at Avista Utilities since 2002 have improved the Company’s operating cash flows from regulated operations. In December 2005, the WUTC approved a settlement agreement (with certain conditions) related to Avista Utilities’ Washington general rate case that provides for electric and natural gas base rate increases. On August 31, 2006, Avista Utilities filed a request with the WUTC to increase electric rates for its Washington customers by an average of 8.8 percent, which is designed to increase annual revenues by $28.9 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 streamflows for hydroelectric generation, outages at generating facilities and failure of third parties to deliver on energy or capacity contracts. Hydroelectric generation has been below normal (based on a 70-year average) for five of the past six years. For 2006, Avista Utilities forecasts that hydroelectric generation will be 101 percent of normal, assuming normal conditions for the remainder of the year. This forecast may change based upon precipitation, temperatures and other variables during the fourth quarter.

The Company monitors the potential liquidity impacts of increasing energy commodity prices for both Avista Utilities and Avista Energy. The Company believes that it has adequate liquidity through current cash and cash equivalents, Avista Corp.’s $320.0 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 prices increase, deferral balances will increase, which will negatively affect the Company’s cash flow and liquidity.

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, 2006 and December 31, 2005 (dollars in thousands):

	September 30, 2006				December 31, 2005
	Amount		Percent of total		Amount		Percent of total
Current portion of long-term debt	$	170,760	8.5	%	$	39,524	2.0	%
Short-term borrowings		62,000	3.1			63,494	3.2
Long-term debt to affiliated trusts		113,403	5.6			113,403	5.6
Long-term debt		819,039	40.8			989,990	49.4
Total debt		1,165,202	58.0			1,206,411	60.2
Preferred stock-cumulative (including current portion)		26,250	1.3			28,000	1.4
Total liabilities		1,191,452	59.3			1,234,411	61.6
Stockholders’ equity		818,658	40.7			771,128	38.4
Total	$	2,010,110	100.0	%	$	2,005,539	100.0	%

The Company’s total debt decreased $41.2 million from December 31, 2005 to September 30, 2006 primarily due to the maturity of long-term debt. The decrease in total debt primarily reflects operating cash flows in excess of funding requirements, primarily for utility capital expenditures and dividends. 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

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Company’s stockholders’ equity increased $47.5 million during the nine months ended September 30, 2006 primarily due to net income, other comprehensive income and the issuance of common stock through equity compensation plans and the dividend reinvestment plan, partially offset by dividends.

The Company generally funds capital expenditures with a combination of internally generated cash and external financing. The level of cash generated internally and the amount that is available for capital expenditures fluctuates depending on a variety of factors. Cash provided by utility operating activities and cash generated by Avista Energy are expected to be the Company’s primary sources of funds for operating needs, dividends and capital expenditures for the fourth quarter of 2006. Borrowings under Avista Corp.’s committed line of credit may supplement these funds to the extent necessary and Avista Corp. currently expects to issue long-term debt in the fourth quarter of 2006 to partially fund debt that matures in December 2006 and January 2007. The Company expects that the new debt issuance would be at a lower rate than the maturing debt.

Avista Corp. has $529 million of long-term debt maturities and mandatory preferred stock redemptions between the fourth quarter of 2006 through the end of 2008. Avista Corp.’s forecasts indicate that it will need to issue new securities to fund a significant portion of these requirements. In 2004, Avista Corp. entered into forward-starting interest rate swap agreements effectively locking in market fixed interest rates, which were relatively low compared to historical interest rates, for $200 million of forecasted debt issuances.

On April 6, 2006, the Company amended its committed line of credit agreement with various banks to lower bank fees and borrowing costs. The committed line of credit was originally entered into on December 17, 2004. Amendments to the committed line of credit include a reduction in the total amount of the facility to $320.0 million from $350.0 million and an extension of the expiration date to April 5, 2011 from December 16, 2009. The Company chose to reduce the total amount of the facility based on forecasted liquidity needs. Under the amended credit agreement, the Company can request the issuance of up to $320.0 million in letters of credit, an increase from $150.0 million prior to the amendment. As of September 30, 2006 and December 31, 2005, the Company had $62.0 million and $63.0 million, respectively, of borrowings outstanding. As of September 30, 2006 and December 31, 2005, there were $51.0 million and $44.1 million in letters of credit outstanding, respectively. The amended committed line of credit is secured by $320.0 million of non-transferable First Mortgage Bonds of the Company issued to the agent bank. Such First Mortgage Bonds would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.

The amended committed line of credit agreement contains customary covenants and default provisions, including a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the preceding twelve-month period at the end of any fiscal quarter to be greater than 1.6 to 1. As of September 30, 2006, the Company was in compliance with this covenant with a ratio of 2.56 to 1. The committed line of credit agreement also has a covenant which does not 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. Under the amendment, this ratio limitation will be increased to 75 percent during the period between the completion of the proposed change in the Company’s corporate organization (see Note 14) and December 31, 2007. As of September 30, 2006, the Company was in compliance with this covenant with a ratio of 58 percent. If the proposed change in organization becomes effective, the committed line of credit agreement will remain at Avista Corp. (Avista Utilities).

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 September 30, 2006, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements.

As further discussed at “Avista Utilities - Regulatory Matters,” in December 2005, the WUTC issued an order approving the settlement agreement reached in the Company’s Washington general rate case with certain conditions. The Company agreed to increase the utility equity component to 35 percent by the end of 2007 and to 38 percent by the end of 2008. As further discussed at “Note 14 of the Notes to the Consolidated Financial Statements,” the IPUC accepted a stipulation entered into between Avista Corp. and the IPUC Staff that sets forth a variety of conditions related to the implementation of a holding company structure. One of the conditions provides for the same utility equity components that are required in the Washington general rate case. Failure by the Company to meet those targets could result in a reduction in base rates of 2 percent for each target in each of Washington and Idaho. The utility equity component was 33.3 percent as of September 30, 2006.

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In addition to expected earnings, the Company is implementing and evaluating additional ways to increase its utility equity ratio. Such measures include delivering original issue shares under the Company’s equity compensation and dividend reinvestment plans, as well as possibly making common stock issuances, from time to time, through underwriters or agents. Regulators in each of the Company’s jurisdictions have approved the issuance of up to 7 million shares of common stock, from time to time (not including shares under equity compensation and dividend reinvestment plans, which have been previously approved by regulators).

Pension Plan

As of September 30, 2006, 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 contributed $15 million to the pension plan in 2005 and 2006. The Company expects to contribute at least $15 million to the pension plan in 2007. Total pension plan contributions were $69 million from 2002 through September 30, 2006.

The Pension Protection Act of 2006 (the Pension Act) was signed into law in August 2006. The Pension Act provides new funding rules for pension plans to improve the funded status of corporate defined benefit plans. The new funding rules could increase the Company’s minimum required cash contributions to the pension in the future. The legislation is effective in 2008; however, the law contains a transition period related to the funding rules. The Company does not expect the Pension Act to have a material effect on the Company’s financial condition, results of operations or cash flows.

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 20, 2006, Avista Corporation (the Company), Avista Receivables Corporation (ARC) and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment was to extend the termination date from March 21, 2006 to March 20, 2007. The Receivables Purchase Agreement was originally entered into on May 29, 2002 and provides the Company with cost-effective funds for working capital requirements, capital expenditures and other general corporate needs. 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. The Receivables Purchase Agreement has financial covenants, which are substantially the same as those of Avista Corp.’s $320.0 million committed line of credit. As of September 30, 2006, $53.0 million in accounts receivable were sold under this revolving agreement.

Credit Ratings

The following table summarizes the Company’s credit ratings as of November 1, 2006:

	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	Positive

(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

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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.

As further discussed at “Note 14 of the Notes to the Consolidated Financial Statements,” the IPUC accepted a stipulation entered into between Avista Corp. and the IPUC Staff that sets forth a variety of conditions related to the implementation of a holding company structure. One of the conditions provides for IPUC approval for any dividend to the holding company that would lower utility common equity below 25 percent.

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 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. In September 2006, Avista Energy paid $6.0 million in dividends to Avista Capital and Avista Capital paid a $6.0 million dividend to Avista Corp.

Avista Utilities Operations

Avista Utilities held cash deposits from other parties in the amount of $40.9 million as of September 30, 2006, 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 6, 7 and 8 of Notes to Consolidated Financial Statements” for additional details related to financing activities.

Energy Marketing and Resource Management Operations

Avista Energy and its subsidiary, Avista Energy Canada, as co-borrowers, have a committed credit agreement with a group of banks in the aggregate amount of $145.0 million with an expiration date of 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 maximum amount available for cash advances under the credit agreement is $50.0 million. No cash advances were outstanding as of September 30, 2006. Letters of credit in the aggregate amount of $21.2 million were outstanding as of September 30, 2006. The cash deposits of Avista Energy at the respective banks collateralized these letters of credit as of September 30, 2006, which is reflected as restricted cash on the Consolidated Balance Sheets.

The Avista Energy credit agreement contains 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 contains 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 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, 2006.

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 $20.5 million as of September 30, 2006. The face value of all performance guarantees issued by Avista Capital for energy trading contracts at Avista Energy was $354.4 million as of September 30, 2006.

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, 2006,

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Avista Energy’s maximum total outstanding short-term loan to Avista Capital was $35.5 million. As of September 30, 2006, 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 $79.2 million as of September 30, 2006, an increase from $59.4 million as of December 31, 2005. Avista Energy held cash deposits from other parties in the amount of $3.7 million as of September 30, 2006, 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, 2006, Avista Energy had $32.3 million in cash, as well as $23.8 million of restricted cash.

Contractual Obligations

During the nine months ended September 30, 2006, the Company’s future contractual obligations have not changed materially from the amounts disclosed in the 2005 Form 10-K with the following exceptions:

The committed line of credit was amended in April 2006 to, among other things, decrease the available amount to $320.0 million from $350.0 million and extend the expiration date to April 5, 2011 from December 16, 2009.

The amount outstanding under Avista Utilities’ revolving accounts receivable sales financing facility decreased from $85.0 million as of December 31, 2005 to $53.0 million as of September 30, 2006. In March 2006, the termination date of Avista Utilities’ revolving accounts receivable sales financing facility was extended from March 21, 2006 to March 20, 2007.

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, 2006 (dollars in millions):

For the 12-month period ended September 30,	2007		2008		2009		2010		2011		Thereafter
Energy purchase contracts	$	455	$	265	$	212	$	199	$	69	$327

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

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 are exposed to terrorism risks or other malicious acts. See further reference to risks and uncertainties under “Forward-Looking Statements.”

The Company’s business risk has not materially changed during the nine months ended September 30, 2006. Please refer to the 2005 Form 10-K for further description and analysis of business risk including, but not limited to, 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 2005 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 2005 Form 10-K for further discussion of the VAR model. As of September 30, 2006, Avista Energy’s estimated potential one-day unfavorable impact on gross margin as measured by VAR was $0.8 million, compared to $0.8 million as of December 31, 2005. The average daily VAR for the nine months ended September 30, 2006 was $0.8 million. The high daily VAR was $1.8 million and the low daily VAR was $0.5 million during the nine months ended September 30, 2006. Avista Energy was in compliance with its one-day VAR limits during the nine months ended September 30, 2006. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.

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Environmental Issues and Other Contingencies

The Company monitors legislative developments at both the state and national level with respect to environmental issues, particularly those related to the potential for further restrictions on the operation of its generating plants. Compliance with such legislation could result in increases in capital expenditures and operating expenses.

Initiative Measure 937 (I-937) will appear on the General Election ballot in Washington on November 7, 2006. I-937 would require certain investor-owned, cooperative, and government-owned electric utilities (including the Company) to acquire new renewable energy resources and/or renewable energy credits in incremental amounts until those resources or credits equal 15 percent of the utility’s total retail load in 2020. I-937 would also require these utilities to meet biennial energy conservation targets. Failure to comply with renewable energy and conservation standards would result in penalties of at least $50 per MWh being assessed against a utility for each MWh it is deficient in meeting a standard. A utility would be deemed to comply with the renewable energy standard if it invests at least 4 percent of its total annual retail revenue requirement on the incremental costs of renewable resources and/or renewable credits. The Company is opposing I-937 and cannot predict whether or not I-937 will be passed into law. The Company’s most recent Electric Integrated Resource Plan (IRP) includes the acquisition of additional renewable resources such that, if I-937 is passed into law and the IRP is implemented, the Company would be compliant with the requirement by 2020 assuming that such renewable resources were cost effective. The amount of renewable resources in future IRP’s could change if the cost effectiveness of those resources changes.

For other environmental issues and other contingencies see “Note 13 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 information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers as appropriate to allow timely decisions regarding required disclosure. 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 a reasonable assurance level as of September 30, 2006.

There have been no changes in the Company’s internal control over financial reporting that occurred during the third quarter of 2006 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 13 of the Notes to Consolidated Financial Statements” which is incorporated by reference.

Item 1A. Risk Factors

Please refer to the 2005 Form 10-K for disclosure of risk factors that could have a significant impact on the operations, results of operations, financial condition or cash flows of Avista Corp. and could cause actual results or outcomes to differ materially from those discussed in Avista Corp.’s reports filed with the Securities and Exchange

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Commission (including this Quarterly Report on Form 10-Q), and elsewhere. These risk factors have not materially changed from the disclosures provided in the 2005 Form 10-K with the exception of the following risk factors:

Avista Corp. relies on access to credit from banks.

In April 2006, Avista Corp. amended its committed line of credit agreement with various banks. Amendments to the committed line of credit include a reduction in the total amount of the facility to $320 million from $350 million and an extension of the expiration date to April 2011 from December 2009. The Company chose to reduce the total amount of the facility based on forecasted liquidity needs.

Avista Corp. may not be able to relicense its hydroelectric facilities located on the Spokane River at a cost-effective level with reasonable terms and conditions.

Avista Corp. owns and operates six hydroelectric plants on the Spokane River, and five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls, which have a total present capability of 155.7 MW) are under one FERC license and are referred to, collectively, as the Spokane River Project. The license for the Spokane River Project expires on August 1, 2007; Avista Corp. filed its new license applications with the FERC in July 2005. Avista Corp. has requested the FERC to consider a license for Post Falls, which has a present capability of 18 MW, that is separate from the other four hydroelectric plants because Post Falls presents more complex issues that may take longer to resolve than those dealing with the rest of the Spokane River Project.

A number of parties (including the Coeur d’Alene Tribe, the State of Idaho, Washington State agencies, and the United States Department of Interior (DOI)) filed either recommended terms and conditions, or mandatory conditions related to the Post Falls license application. Avista Corp.’s initial estimate of the potential cost of the conditions proposed for Post Falls total between $400 million and $500 million over a 50-year period. This assumes all conditions, both mandatory and recommended, as well as Avista Corp.’s proposed conditions, would be included in a final license issued by the FERC, which Avista Corp. believes to be unlikely. For the rest of the Spokane River Project, which is located in Washington, Avista Corp.’s initial estimate of the cost of meeting the recommended conditions, should they be included in a final license, totals between $175 million and $225 million over a 50-year period. These cost estimates are based on the preliminary conditions and recommendations and will be updated based on the outcome of the FERC proceedings. The Company has requested a trial-type hearing on facts in front of a DOI administrative law judge related to the DOI’s mandatory conditions. DOI has responded to that request, and several parties have intervened. The request was formally referred for docketing on October 10, 2006. 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. Avista Corp. plans to request regulatory approval to recover its licensing costs. However, Avista Corp. cannot provide certainty that these costs will be recovered through the rate making process.

In addition to these risk factors, please also see “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements” for additional factors 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.

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 3, 2006	/s/ Malyn K. Malquist
	Malyn K. Malquist Executive Vice President and Chief Financial Officer (Principal Accounting and Financial Officer)

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