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Document And Entity Information - shares	9 Months Ended
Document And Entity Information - shares	Sep. 30, 2013	Oct. 31, 2013
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Trading Symbol	ava
Entity Registrant Name	AVISTA CORP
Entity Central Index Key	0000104918
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		60,036,179

Consolidated Statements Of Income - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Operating Revenues:
Utility revenues	$ 278,473	$ 292,085	$ 1,007,319	$ 990,860
Ecova revenues	46,398	38,617	133,365	115,707
Other non-utility revenues	11,004	9,930	30,145	29,907
Total operating revenues	335,875	340,632	1,170,829	1,136,474
Utility operating expenses:
Resource costs	131,136	153,801	487,277	500,805
Other operating expenses	69,596	66,456	200,824	196,759
Depreciation and amortization	29,823	28,255	86,783	83,327
Taxes other than income taxes	18,712	18,122	66,137	63,723
Ecova operating expenses:
Other operating expenses	37,047	33,868	110,753	104,392
Depreciation and Amortization	3,909	3,260	11,474	9,455
Other non-utility operating expenses:
Other operating expenses	10,212	10,131	28,972	28,480
Depreciation and amortization	171	131	536	511
Total operating expenses	300,606	314,024	992,756	987,452
Income from operations	35,269	26,608	178,073	149,022
Interest expense	19,566	19,128	59,119	57,453
Interest expense to affiliated trusts	117	136	352	413
Capitalized interest	(820)	(644)	(2,702)	(1,765)
Other income-net	(984)	418	(5,565)	(2,892)
Income before income taxes	17,390	7,570	126,869	95,813
Income tax expense	5,459	1,608	46,107	33,106
Net income	11,931	5,962	80,762	62,707
Net income attributable to noncontrolling interests	(518)	(176)	(1,351)	(355)
Net income attributable to Avista Corporation shareholders	$ 11,413	$ 5,786	$ 79,411	$ 62,352
Weighted-average common shares outstanding (thousands), basic	59,994	59,047	59,933	58,778
Weighted-average common shares outstanding (thousands), diluted	60,032	59,123	59,964	59,026
Earnings per common share attributable to Avista Corporation shareholders:
Basic (usd per share)	$ 0.19	$ 0.10	$ 1.32	$ 1.06
Diluted (usd per share)	0.19	0.10	1.32	1.06
Dividends paid per common share	$ 0.305	$ 0.29	$ 0.915	$ 0.87

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Net income	$ 11,931	$ 5,962	$ 80,762	$ 62,707
Other Comprehensive Income (Loss):
Unrealized investment gains - net of taxes	(395)	110	(1,687)	409
Reclassification adjustment for realized gains on investment securities included in net income - net of taxes	(1)	(17)	(12)	(158)
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes	184	168	551	489
Total other comprehensive loss	(212)	261	(1,148)	740
Comprehensive income	11,719	6,223	79,614	63,447
Comprehensive income attributable to noncontrolling interests	(518)	(176)	(1,351)	(355)
Comprehensive income attributable to Avista Corporation shareholders	$ 11,201	$ 6,047	$ 78,263	$ 63,092

Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Unrealized investment gains - taxes	$ (233)	$ 68	$ (993)	$ 244
Realized investment gains - taxes	(1)	(11)	(8)	(94)
Change in unfunded benefit obligation for pension and other postretirement benefit plans - taxes	$ 99	$ 90	$ 297	$ 263

Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2013	Dec. 31, 2012
Current Assets:
Cash and cash equivalents	$ 91,979	$ 75,464
Accounts and notes receivable-less allowances of $44,103 and $44,155, respectively	139,512	193,683
Utility energy commodity derivative assets	3,430	4,139
Regulatory asset for utility derivatives	20,399	35,082
Investments and funds held for clients	92,870	88,272
Materials and supplies, fuel stock and natural gas stored	56,843	47,455
Deferred income taxes	28,740	34,281
Income taxes receivable	12,350	2,777
Other current assets	39,721	24,641
Total current assets	485,844	505,794
Net Utility Property:
Utility plant in service	4,252,299	4,054,644
Construction work in progress	137,565	143,098
Total	4,389,864	4,197,742
Less: Accumulated depreciation and amortization	1,232,547	1,174,026
Total net utility property	3,157,317	3,023,716
Other Non-current Assets:
Investment in exchange power-net	14,496	16,333
Investment in affiliated trusts	11,547	11,547
Goodwill	76,762	75,959
Intangible assets-net of accumulated amortization of $33,886 and $26,030, respectively	41,153	46,256
Long-term energy contract receivable of Spokane Energy	43,563	52,033
Other property and investments-net	66,486	46,542
Total other non-current assets	254,007	248,670
Deferred Charges:
Regulatory assets for deferred income tax	67,691	79,406
Regulatory assets for pensions and other postretirement benefits	292,359	306,408
Other regulatory assets	105,608	103,946
Non-current utility energy commodity derivative assets	293	1,093
Non-current regulatory asset for utility derivatives	24,729	25,218
Other deferred charges	14,154	18,928
Total deferred charges	504,834	534,999
Total assets	4,402,002	4,313,179
Current Liabilities:
Accounts payable	158,360	198,914
Client fund obligations	95,214	87,839
Current portion of long-term debt	50,330	50,372
Current portion of nonrecourse long-term debt of Spokane Energy	16,022	14,965
Short-term borrowings	66,000	52,000
Utility energy commodity derivative liabilities	18,708	29,515
Other current liabilities	145,602	142,544
Total current liabilities	550,236	576,149
Long-term debt	1,272,260	1,178,367
Nonrecourse long-term debt of Spokane Energy	5,666	17,838
Long-term debt to affiliated trusts	51,547	51,547
Long-term borrowings under committed line of credit	50,000	54,000
Regulatory liability for utility plant retirement costs	249,980	234,128
Pensions and other postretirement benefits	252,331	283,985
Deferred income taxes	528,981	524,877
Other non-current liabilities and deferred credits	122,214	110,215
Total liabilities	3,083,215	3,031,106
Commitments and Contingencies (See Notes to Consolidated Financial Statements)
Redeemable Noncontrolling Interests	8,330	4,938
Avista Corporation Stockholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 60,029,209 and 59,812,796 shares outstanding, respectively	898,199	889,237
Accumulated other comprehensive loss	(7,848)	(6,700)
Retained earnings	399,053	376,940
Total Avista Corporation stockholders’ equity	1,289,404	1,259,477
Noncontrolling Interests	21,053	17,658
Total equity	1,310,457	1,277,135
Total liabilities and equity	$ 4,402,002	$ 4,313,179

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]
Accounts and notes receivable, allowances	$ 44,103	$ 44,155
Accumulated Amortization	$ 33,886	$ 26,030
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares outstanding	60,029,209	59,812,796

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Operating Activities:
Net income	$ 80,762	$ 62,707
Non-cash items included in net income:
Depreciation and amortization	98,793	93,293
Provision for deferred income taxes	16,512	18,380
Power and natural gas cost amortizations (deferrals), net	(10,149)	10,418
Amortization of debt expense	2,841	2,876
Amortization of investment in exchange power	1,838	1,838
Stock-based compensation expense	4,718	4,539
Equity-related AFUDC	(4,341)	(2,875)
Pension and other postretirement benefit expense	31,894	29,785
Amortization of Spokane Energy contract	8,470	7,786
Write-off of Reardan wind generation capitalized costs	2,534	0
Other	6,889	8,911
Contributions to defined benefit pension plan	(44,000)	(44,000)
Changes in working capital components:
Accounts and notes receivable	50,681	61,106
Materials and supplies, fuel stock and natural gas stored	(9,388)	941
Other current assets	(23,165)	7,209
Accounts payable	(23,756)	(10,783)
Other current liabilities	11,269	5,277
Net cash provided by operating activities	202,402	257,408
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	(220,712)	(178,440)
Other capital expenditures	(1,725)	(3,908)
Federal grant payments received	2,631	5,902
Cash paid by subsidiaries for acquisitions, net of cash received	0	(50,310)
Decrease (increase) In Money Market Funds Held For Clients	11,723	(9,599)
Purchase of securities available for sale	(35,949)	(88,843)
Sale and maturity of securities available for sale	16,955	103,545
Other	(6,481)	(7,412)
Net cash used in investing activities	(233,558)	(229,065)
Financing Activities:
Net increase in short-term borrowings	14,000	21,000
Borrowings from Ecova line of credit	3,000	28,000
Repayment of borrowings from Ecova line of credit	(7,000)	(5,000)
Proceeds from Issuance of Long-term Debt	90,000	0
Redemption and maturity of long-term debt	(415)	(11,363)
Maturity of nonrecourse long-term debt of Spokane Energy	(11,115)	(10,153)
Long-term debt and short-term borrowing issuance costs	(471)	(177)
Cash received (paid) for settlement of interest rate swap agreements	2,901	(18,547)
Issuance of common stock	4,479	28,699
Cash dividends paid	(54,963)	(51,215)
Purchase of subsidiary noncontrolling interest	(379)	(917)
Increase (decrease) in client fund obligations	7,375	(5,220)
Issuance of subsidiary noncontrolling interest	0	3,714
Other	259	1,126
Net cash provided by (used in) financing activities	47,671	(20,053)
Net cash provided by (used in) financing activities	16,515	8,290
Cash and cash equivalents at beginning of period	75,464	74,662
Cash and cash equivalents at end of period	91,979	82,952
Cash paid during the year:
Interest	45,633	43,487
Income taxes	33,522	12,527
Non-cash financing and investing activities:
Accounts payable for capital expenditures	4,313	3,556
Redeemable noncontrolling interests	$ 3,246	$ (8,274)

Consolidated Statements Of Equity And Redeemable Noncontrolling Interests - USD ($) $ in Thousands	Total	Common Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Noncontrolling Interests [Member]	Redeemable Noncontrolling Interests [Member]
Noncontrolling Interest in Net Income (Loss) Other Noncontrolling Interests, Redeemable						$ 121
Noncontrolling Interest in Net Income (Loss) Other Noncontrolling Interests, Nonredeemable					$ 234
Beginning Balance (in shares) at Dec. 31, 2011		58,422,781
Issuance of common stock		1,332,089
Beginning Balance at Dec. 31, 2011		$ 855,188	$ (5,637)	$ 336,150	174	51,809
Equity compensation expense		3,354
Issuance of common stock, net of issuance costs		28,699
Equity transactions of consolidated subsidiaries		289
Other comprehensive loss	$ 740		740
Net income attributable to Avista Corporation shareholders	62,352			62,352
Cash dividends paid (common stock)				(51,215)
Issuance of subsidiary noncontrolling interests	3,714					3,714
Deconsolidation of variable interest entity					(673)
Expiration Of Subsidiary Noncontrolling Interests Redemption Rights				23,805	17,790	(41,595)
Other					30
Purchase of subsidiary noncontrolling interests					(117)	(784)
Valuation adjustments and other noncontrolling interests activity				6,019		(6,539)
Ending Balance at Sep. 30, 2012	1,259,744	$ 887,530	(4,897)	377,111	17,438	6,726
Ending Balance (in shares) at Sep. 30, 2012		59,754,870
Total equity	1,277,182
Total equity	$ 1,277,135
Noncontrolling Interest in Net Income (Loss) Other Noncontrolling Interests, Redeemable						119
Noncontrolling Interest in Net Income (Loss) Other Noncontrolling Interests, Nonredeemable					1,232
Beginning Balance (in shares) at Dec. 31, 2012	59,812,796	59,812,796
Issuance of common stock		216,413
Beginning Balance at Dec. 31, 2012	$ 1,259,477	$ 889,237	(6,700)	376,940	17,658	4,938
Equity compensation expense		4,490
Issuance of common stock, net of issuance costs		4,479
Equity transactions of consolidated subsidiaries		(7)
Other comprehensive loss	(1,148)		(1,148)
Net income attributable to Avista Corporation shareholders	79,411			79,411
Cash dividends paid (common stock)				(54,963)
Issuance of subsidiary noncontrolling interests	0					0
Deconsolidation of variable interest entity					0
Expiration Of Subsidiary Noncontrolling Interests Redemption Rights				0	0	0
Other					2,163
Purchase of subsidiary noncontrolling interests					0	(379)
Valuation adjustments and other noncontrolling interests activity				(2,335)		3,652
Ending Balance at Sep. 30, 2013	$ 1,289,404	$ 898,199	$ (7,848)	$ 399,053	$ 21,053	$ 8,330
Ending Balance (in shares) at Sep. 30, 2013	60,029,209	60,029,209
Total equity	$ 1,310,457

Summary Of Significant Accounting Policies

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corporation 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, northern Idaho, and Montana. In addition, Avista Utilities has electric generating facilities in northern Oregon. Avista Utilities also provides natural gas distribution service in parts of eastern Washington and northern Idaho, as well as parts of northeastern and southwestern 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 businesses, except Spokane Energy, LLC (Spokane Energy). Avista Capital’s subsidiaries include Ecova, Inc. (Ecova), a 78.9 percent owned subsidiary as of September 30, 2013. Ecova is a provider of energy efficiency and other facility information and cost management programs and services for multi-site customers and utilities throughout North America. See Note 12 for business segment information.

Basis of Reporting

The condensed consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries, including Ecova and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Intercompany balances were eliminated in consolidation. The accompanying condensed consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants.

Taxes Other Than Income Taxes

Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled the following amounts for the three and nine months ended September 30 (dollars in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Utility taxes	$	10,901	$	10,741	$	41,045	$	41,353

Other (Income)/Expense-Net

Other (Income)/Expense-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,
	2013			2012			2013			2012
Interest income	$	(124	)	$	(166	)	$	(620	)	$	(804	)
Interest income on regulatory deferrals	(27		)	(19		)	(48		)	(43		)
Equity-related AFUDC	(1,595		)	(1,127		)	(4,341		)	(2,875		)
Net loss on investments	1,299			2,430			1,543			2,957
Other income	(537		)	(700		)	(2,099		)	(2,127		)
Total	$	(984	)	$	418		$	(5,565	)	$	(2,892	)

Materials and Supplies, Fuel Stock and Natural Gas Stored

Inventories of materials and supplies, fuel stock and natural gas stored are recorded at average cost for our regulated operations and the lower of cost or market for our non-regulated operations and consisted of the following as of September 30, 2013 and December 31, 2012 (dollars in thousands):



	September 30,		December 31,
	2013		2012
Materials and supplies	$	29,334	$	26,058
Fuel stock	3,750		4,121
Natural gas stored	23,759		17,276
Total	$	56,843	$	47,455

Investments and Funds Held for Clients and Client Fund Obligations

In connection with the bill paying services, Ecova collects funds from its clients and remits the funds to the appropriate utility or other service provider. Some of the funds collected are invested by Ecova and classified as investments and funds held for clients, and a related liability for client fund obligations is recorded. Investments and funds held for clients include cash and cash equivalent investments, money market funds and investment securities classified as available for sale. Ecova does not invest the funds directly for the clients' benefit; therefore, Ecova bears the risk of loss associated with the investments. Investments and funds held for clients as of September 30, 2013 are as follows (dollars in thousands):



	Amortized Cost (1)		Unrealized Gain (Loss)			Fair Value
Cash and cash equivalents	$	14,155	$	—		$	14,155
Money market funds	3,238		—			3,238
Securities available for sale:
U.S. government agency	68,631		(2,466		)	66,165
Municipal	3,529		13			3,542
Corporate fixed income – financial	3,000		4			3,004
Corporate fixed income – industrial	1,753		13			1,766
Certificates of deposit	1,000		—			1,000
Total securities available for sale	77,913		(2,436		)	75,477
Total investments and funds held for clients	$	95,306	$	(2,436	)	$	92,870

Investments and funds held for clients as of December 31, 2012 are as follows (dollars in thousands):



	Amortized Cost (1)		Unrealized Gain (Loss)		Fair Value
Cash and cash equivalents	$	13,867	$	—	$	13,867
Money market funds	15,084		—		15,084
Securities available for sale:
U.S. government agency	48,340		156		48,496
Municipal	820		28		848
Corporate fixed income – financial	5,010		16		5,026
Corporate fixed income – industrial	3,887		49		3,936
Certificates of deposit	1,000		15		1,015
Total securities available for sale	59,057		264		59,321
Total investments and funds held for clients	$	88,008	$	264	$	88,272


(1)	Amortized cost represents the original purchase price of the investments, plus or minus any amortized purchase premiums or accreted purchase discounts.

Investments and funds held for clients are classified as a current asset since these funds are held for the purpose of satisfying the client fund obligations. As of September 30, 2013 and December 31, 2012 approximately 95 percent and 97 percent of the investment portfolio, respectively, was rated AA-, Aa3 and higher by nationally recognized statistical rating organizations. All fixed income securities were rated as investment grade as of September 30, 2013 and December 31, 2012.

Ecova reviews its investments continuously for indicators of other-than-temporary impairment. To make this determination, Ecova employs a methodology that considers available quantitative and qualitative evidence in evaluating potential impairment of its investments. If the cost of an investment exceeds its fair value, Ecova evaluates, among other factors, general market conditions, credit quality of instrument issuers, the length of time and extent to which the fair value is less than cost, and whether it has plans to sell the security or it is more-likely-than not that Ecova will be required to sell the security before recovery. Ecova also considers specific adverse conditions related to the financial health of and specific prospects for the issuer as well as other cash flow factors. Once a decline in fair value is determined to be other-than-temporary, an impairment charge is recorded in earnings and a new cost basis in the investment is established. Based on Ecova’s analysis, securities available for sale do not meet the criteria for other-than-temporary impairment as of September 30, 2013 or December 31, 2012.

The following is a summary of the disposition of available-for-sale securities for the three and nine months ended September 30 (dollars in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Proceeds from sales, maturities and calls	$	1,825	$	32,053	$	16,955	$	103,545
Gross realized gains	2		111		20		252
Gross realized losses	—		—		—		—

Contractual maturities of securities available for sale as of September 30, 2013 and December 31, 2012 are as follows (dollars in thousands):



	Due within 1 year		After 1 but within 5 years		After 5 but within 10 years		After 10 years		Total
September 30, 2013	$	5,655	$	18,479	$	48,437	$	2,906	$	75,477
December 31, 2012	3,047		11,786		41,485		3,003		59,321

Actual maturities may differ due to call or prepayment rights and the effective maturity was 3.1 years as of September 30, 2013 and 1.9 years as of December 31, 2012.

Goodwill

Goodwill arising from acquisitions represents the excess of the purchase price over the estimated fair value of net assets acquired. The Company evaluates goodwill for impairment using a discounted cash flow model on at least an annual basis or more frequently if impairment indicators arise. The Company completed its annual evaluation of goodwill for potential impairment as of December 31, 2012 for Ecova and as of November 30, 2012 for the other businesses and determined that goodwill was not impaired at that time.

The changes in the carrying amount of goodwill are as follows (dollars in thousands):



	Ecova		Other		Accumulated Impairment Losses			Total
Balance as of December 31, 2012	$	70,713	$	12,979	$	(7,733	)	$	75,959
Adjustments	803		—		—			803
Balance as of September 30, 2013	$	71,516	$	12,979	$	(7,733	)	$	76,762

Accumulated impairment losses are attributable to the other businesses. The adjustment to goodwill recorded represents a purchase accounting adjustment for Ecova's acquisition of LPB based upon final review of the fair market value of the noncontrolling interests associated with a portion of the LPB business and based on review of the fair market value of the client relationship intangible asset.

Intangible Assets

Amortization expense related to Intangible Assets was as follows for the three and nine months ended September 30 (dollars in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Intangible asset amortization	$	2,765	$	2,436	$	8,442	$	7,091

The following table details the estimated amortization expense related to Intangible Assets for each of the five years ending December 31 (dollars in thousands):



	Remaining
	2013		2014		2015		2016		2017
Estimated amortization expense	$	2,292	$	10,460	$	8,484	$	7,359	$	6,516

The gross carrying amount and accumulated amortization of Intangible Assets as of September 30, 2013 and December 31, 2012 are as follows (dollars in thousands):



	Estimated	September 30,			December 31,
	Useful Lives	2013			2012
Client backlog and relationships	2 - 12 years	$	33,559		$	32,059
Software development costs	3 - 7 years	38,148			33,990
Other	1 - 10 years	3,332			6,237
Total intangible assets		75,039			72,286
Client relationships accumulated amortization		(11,255		)	(7,793		)
Software development costs accumulated amortization		(20,383		)	(16,557		)
Other accumulated amortization		(2,248		)	(1,680		)
Total accumulated amortization		(33,886		)	(26,030		)
Total intangible assets - net		$	41,153		$	46,256

Of the total net intangible assets above, intangible assets associated with Ecova represent approximately $40.4 million and $45.4 million at September 30, 2013 and December 31, 2012, respectively.

Derivative Assets and Liabilities

Derivatives are recorded as either assets or liabilities on the Condensed Consolidated Balance Sheets measured at estimated fair value. In certain defined conditions, a derivative may be specifically designated as a hedge for a particular exposure. The accounting for any particular derivative depends on the intended use of that derivative and the resulting designation.

The Washington Utilities and Transportation Commission (UTC) and the Idaho Public Utilities Commission (IPUC) issued accounting orders authorizing Avista Utilities to offset commodity 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 delivery. The orders provide for Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Condensed Consolidated Statements of Income. Realized gains or losses are recognized in the period of delivery, 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 Energy Recovery Mechanism (ERM) in Washington, the Power Cost Adjustment (PCA) mechanism in Idaho, and periodic general rates cases. Regulatory assets are assessed regularly and are probable for recovery through future rates.

Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are delivered or realized, unless there is a decline in the fair value of the contract that is determined to be other-than-temporary.

Fair Value Measurements

Fair value represents the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, investments and funds held for clients, deferred compensation assets, as well as derivatives related to interest rate swap agreements and foreign currency exchange contracts, are reported at estimated fair value on the Condensed Consolidated Balance Sheets. See Note 9 for the Company’s fair value disclosures.

Regulatory Deferred Charges and Credits

The Company prepares its condensed consolidated financial statements in accordance with regulatory accounting practices because:


•	rates for regulated services are established by or subject to approval by independent third-party regulators,


•	the regulated rates are designed to recover the cost of providing the regulated services, and


•	in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover costs.

Regulatory accounting practices require that certain costs and/or obligations (such as incurred power and natural gas costs not currently included in rates, but expected to be recovered or refunded in the future) are reflected as deferred charges or credits on the Condensed Consolidated Balance Sheets. These costs and/or obligations are not reflected in the Condensed Consolidated Statements of Income until the period during which matching revenues are recognized. If at some point in the future the Company determines that it no longer meets the criteria for continued application of regulatory accounting practices for all or a portion of its regulated operations, the Company could be:


•	required to write off its regulatory assets, and


•	precluded from the future deferral of costs not recovered through rates at the time such costs are incurred, even if the Company expected to recover such costs in the future.

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, net of tax, consisted of the following as of September 30, 2013 and December 31, 2012 (dollars in thousands):



	September 30,			December 31,
	2013			2012
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $(3,401) and $(3,698), respectively	$	(6,316	)	$	(6,867	)
Unrealized gain (loss) on securities available for sale - net of taxes of $(904) and $97, respectively	(1,532		)	167
Total accumulated other comprehensive loss	$	(7,848	)	$	(6,700	)

The following table details the reclassifications out of accumulated other comprehensive loss by component for the three and nine months ended September 30, 2013 (dollars in thousands):



	Amounts Reclassified from Accumulated Other Comprehensive Loss
Details about Accumulated Other Comprehensive Loss Components	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013			Affected Line Item in Statement of Income
Realized gains on investment securities	$	2		$	20		Other income-net
	2			20			Total before tax
	(1		)	(8		)	Tax expense
	$	1		$	12		Net of tax
Amortization of defined benefit pension items
Amortization of net loss	$	(4,891	)	$	(14,673	)	(a)
Adjustment due to effects of regulation	4,608			13,825			(a)
	(283		)	(848		)	Total before tax
	99			297			Tax benefit
	$	(184	)	$	(551	)	Net of tax


(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 6 for additional details).

Contingencies

The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses losses that do not meet these conditions for accrual, if there is a reasonable possibility that a loss may be incurred.

Voluntary Severance Incentive Program

At December 31, 2012, the Company accrued total severance costs of $7.3 million (pre-tax) related to the voluntary termination of 55 employees. The total severance costs were made up of the severance payments and the related payroll taxes and employee benefit costs. All terminations under the voluntary severance incentive program were completed by December 31, 2012. The cost of the program was recognized as expense during the fourth quarter of 2012 and severance pay was distributed in a single lump sum cash payment to each participant during January 2013. As of September 30, 2013, there was no remaining liability accrued.

Correction of an Immaterial Error

Subsequent to the issuance of the Company's condensed consolidated financial statements for the three and nine months ended September 30, 2012, the Company's management identified certain employee-related operating expenses, dues and donations, and other operating expenses totaling $3.4 million and $8.0 million for the three and nine months ended September 30, 2012, respectively, which had been erroneously included in “Other expense-net” in the previously issued financial statements rather than as a reduction to “Income from operations.” Accordingly, such classification has been corrected in the accompanying Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2012 by including $2.0 million and $5.4 million of other operating expenses within utility operating expense, $1.4 million and $2.5 million of other operating expenses within other non-utility operating expenses and $0.03 million and $0.1 million of taxes other than income taxes within utility operating expenses, respectively. Such items had no effect on net income or earnings per share.

Reclassifications

Certain prior year amounts on the Company's Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Cash Flows have been reclassified to conform to the current year presentation. In the current year Condensed Consolidated Statements of Income, Ecova operating revenues and operating expenses have been reclassified to separate line items. Previously, such amounts had been classified within the line items captioned "Other non-utility revenues" and “Other non-utility operating expenses,” respectively. Such items had no effect on net income or earnings per share. In the current year Condensed Consolidated Statements of Cash Flows, "Amortization of investment in exchange power," "Stock-based compensation expense," "Pension and other postretirement benefit expense" and "Amortization of Spokane Energy contract" have been added as their own line items. These were previously included in "Other" in the operating activities section.

New Accounting Standards	9 Months Ended
New Accounting Standards	Sep. 30, 2013
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Standards	NEW ACCOUNTING STANDARDS In February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU does not change current requirements for reporting net income or other comprehensive income in financial statements; however, it requires entities to disclose the effect on the line items of net income for reclassifications out of accumulated other comprehensive income if the item being reclassified is required to be reclassified in its entirety to net income under U.S. GAAP. For other items that are not required to be reclassified in their entirety to net income under U.S. GAAP, an entity is required to cross-reference other disclosures required under U.S. GAAP to provide additional detail about those items. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU required additional disclosures in the Company's financial statements; however, it did not have any impact on the Company's financial condition, results of operations and cash flows. In December 2011, the FASB issued ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” This ASU enhances disclosure requirements about the nature of an entity's right to offset and related arrangements associated with its financial instruments and derivative instruments. ASU No. 2011-11 requires the disclosure of the gross amounts subject to rights of set off, amounts offset in accordance with the accounting standards followed, and the related net exposure. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU required additional disclosures in the Company's financial statements; however, it did not have any impact on the Company's financial condition, results of operations and cash flows. In January 2013, the FASB issued ASU No. 2013-01, “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” This ASU clarifies which instruments and transactions are subject to the enhanced disclosure requirements of ASU 2011-11 regarding the offsetting of financial assets and liabilities. ASU No. 2013-01 limits the scope of ASU No. 2011-11 to only recognized derivative instruments, repurchase agreements and reverse repurchase agreements, and borrowing and lending securities transactions that are offset in accordance with either Accounting Standards Codification (ASC) 210-20-45 or ASC 815-10-45. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU did not have any impact on the Company's financial condition, results of operations and cash flows.

- Definition

The entire disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6507316

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Glossary Direct Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6510796

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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 01
-Paragraph b
-Subparagraph 6
-Article 10

+ Details

Variable Interest Entities	9 Months Ended
Variable Interest Entities	Sep. 30, 2013
Variable Interest Entities [Abstract]
Variable Interest Entities	VARIABLE INTEREST ENTITIES Lancaster Power Purchase Agreement The Company has a power purchase agreement (PPA) for the purchase of all the output of the Lancaster Plant, a 270 MW natural gas-fired combined cycle combustion turbine plant located in Idaho, owned by an unrelated third-party (Rathdrum Power LLC), through 2026. Avista Corp. has a variable interest in the PPA. Accordingly, Avista Corp. made an evaluation of which interest holders have the power to direct the activities that most significantly impact the economic performance of the entity and which interest holders have the obligation to absorb losses or receive benefits that could be significant to the entity. Avista Corp. pays a fixed capacity and operations and maintenance payment and certain monthly variable costs under the PPA. Under the terms of the PPA, Avista Corp. makes the dispatch decisions, provides all natural gas fuel and receives all of the electric energy output from the Lancaster Plant. However, Rathdrum Power LLC (the owner) controls the daily operation of the Lancaster Plant and makes operating and maintenance decisions. Rathdrum Power LLC controls all of the rights and obligations of the Lancaster Plant after the expiration of the PPA in 2026. It is estimated that the plant will have 15 to 25 years of useful life after that time. Rathdrum Power LLC bears the maintenance risk of the plant and will receive the residual value of the Lancaster Plant. Avista Corp. has no debt or equity investments in the Lancaster Plant and does not provide financial support through liquidity arrangements or other commitments (other than the PPA). Based on its analysis, Avista Corp. does not consider itself to be the primary beneficiary of the Lancaster Plant. Accordingly, neither the Lancaster Plant nor Rathdrum Power LLC is included in Avista Corp.’s condensed consolidated financial statements. The Company has a future contractual obligation of approximately $303 million under the PPA (representing the fixed capacity and operations and maintenance payments through 2026) and believes this would be its maximum exposure to loss. However, the Company believes that such costs will be recovered through retail rates. Palouse Wind Power Purchase Agreement In June 2011, the Company entered into a 30-year PPA with Palouse Wind, LLC (Palouse Wind), an affiliate of First Wind Holdings, LLC. The PPA relates to a wind project that was developed by Palouse Wind in Whitman County, Washington and under the terms of the PPA, the Company acquires all of the power and renewable attributes produced by the wind project for a fixed price per MWh, which escalates annually, without consideration for market fluctuations. The wind project has a nameplate capacity of approximately 105 MW and is expected to produce approximately 40 aMW annually. The project was completed and energy deliveries began during the fourth quarter of 2012. Under the PPA, the Company has an annual option to purchase the wind project following the 10^th anniversary of the commercial operation date at a fixed price determined under the contract. The Company evaluated this agreement to determine if it has a variable interest which must be consolidated. Based on its analysis, Avista Corp. does not consider itself to be the primary beneficiary of the Palouse Wind facility due to the fact that it pays a fixed price per MWh, which represents the only financial obligation, and does not have any input into the management of the day-to-day operations of the facility. Accordingly, Palouse Wind is not included in Avista Corp.’s condensed consolidated financial statements. The Company has a future contractual obligation of approximately $562 million under the PPA (representing the charges associated with purchasing the energy and renewable attributes through 2042) and believes this would be its maximum exposure to loss. However, the Company believes that such costs will be recovered through retail rates.

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

Redeemable Noncontrolling Interests And Subsidiary Acquisitions

9 Months Ended

Sep. 30, 2013

Business Combinations [Abstract]

Redeemable Noncontrolling Interests And Subsidiary Acquisitions

REDEEMABLE NONCONTROLLING INTERESTS AND SUBSIDIARY ACQUISITIONS

Certain minority shareholders and option holders of Ecova have the right to put their shares back to Ecova at their discretion during an annual put window which is in March of each year. Stock options and other outstanding redeemable stock are valued at their maximum redemption amount which is equal to their intrinsic value (fair value less exercise price).

The following details redeemable noncontrolling interests as of September 30, 2013 and December 31, 2012 (dollars in thousands):



	September 30,		December 31,
	2013		2012
Stock options and other outstanding redeemable stock	$	8,330	$	4,938

On January 31, 2012, Ecova acquired all of the capital stock of LPB Energy Management (LPB), a Dallas, Texas-based energy management company. The cash paid for the acquisition of LPB of $50.6 million was funded by Ecova through $25.0 million of borrowings under its committed credit agreement, a $20.0 million equity infusion from existing shareholders (including Avista Capital and the other owners of Ecova), and available cash. The acquired assets and assumed liabilities of LPB were recorded at their respective estimated fair values as of the date of acquisition. The results of operations of LPB are included in the condensed consolidated financial statements beginning February 1, 2012. The sellers of LPB did not receive additional purchase price payments in 2012 and will not receive additional payments in 2013; however, they have the potential to receive additional purchase price payments of $1.5 million in 2014. These payments are contingent upon reaching certain revenue thresholds for certain customer contracts. As of September 30, 2013, Ecova has recorded a contingent liability of $0.2 million based on management's assessment of the probability of the revenue thresholds being achieved.

Pro forma disclosures reflecting the effects of Ecova’s acquisition are not presented, as the acquisition is not material to Avista Corp.’s condensed consolidated financial condition or results of operations.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Derivatives And Risk Management

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedges, Assets [Abstract]

Derivatives And Risk Management

DERIVATIVES AND RISK MANAGEMENT

Energy Commodity Derivatives

Avista Utilities is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista Utilities utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these commodity price exposures. The Company has an energy resources risk policy and control procedures to manage these risks. The Company’s Risk Management Committee establishes the Company’s energy resources risk policy and monitors compliance. The Risk Management Committee is comprised of certain Company officers and other members of management. The Audit Committee of the Company’s Board of Directors periodically reviews and discusses enterprise risk management processes, and it focuses on the Company’s material financial and accounting risk exposures and the steps management has undertaken to control them.

As part of our resource procurement and management operations in the electric business, we engage in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve our load obligations and the use of these resources to capture available economic value. We transact in wholesale markets by selling and purchasing electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with our load obligations and hedging the related financial risks. These transactions range from terms of intra-hour up to multiple years.

Avista Utilities makes continuing projections of:


•	electric loads at various points in time (ranging from intra-hour to multiple years) based on, among other things, estimates of customer usage and weather, historical data and contract terms, and


•	resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of streamflows, availability of generating units, historic and forward market information, contract terms, and experience.

On the basis of these projections, we make purchases and sales of electric capacity and energy, fuel for electric generation, and related derivative instruments to match expected resources to expected electric load requirements and reduce our exposure to electricity (or fuel) market price changes. Resource optimization involves generating plant dispatch and scheduling available resources and also includes transactions such as:


•	purchasing fuel for generation,


•	when economical, selling fuel and substituting wholesale electric purchases, and


•	other wholesale transactions to capture the value of generation and transmission resources and fuel delivery capacity contracts.

Avista Utilities’ optimization process includes entering into hedging transactions to manage risks. Transactions include both physical energy contracts and related derivative instruments.

As part of its resource procurement and management of its natural gas business, Avista Utilities makes continuing projections of its natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Utilities’ distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, Avista Utilities plans and executes a series of transactions to hedge a significant portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as four natural gas operating years (November through October) into the future. Avista Utilities also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.

Natural gas resource optimization activities include:


•	wholesale market sales of surplus natural gas supplies,


•	optimization of interstate pipeline transportation capacity not needed to serve daily load, and


•	purchases and sales of natural gas to optimize use of storage capacity.

The following table presents the underlying energy commodity derivative volumes as of September 30, 2013 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):



	Purchases				Sales
	Electric Derivatives		Gas Derivatives		Electric Derivatives		Gas Derivatives
Year	Physical (1) MWH	Financial (1) MWH	Physical (1) mmBTUs	Financial (1) mmBTUs	Physical MWH	Financial MWH	Physical mmBTUs	Financial mmBTUs
2013	385	997	11,576	36,932	230	1,123	906	26,934
2014	702	1,942	22,613	115,004	345	2,839	1,786	84,108
2015	379	1,013	4,523	72,320	254	2,542	—	46,840
2016	367	—	2,505	38,210	287	1,634	—	13,380
2017	366	—	675	—	286	—	—	—
Thereafter	583	—	—	—	443	—	—	—


(1)	Physical transactions represent commodity transactions where Avista Utilities will take delivery of either electricity or natural gas and financial transactions represent derivative instruments with no physical delivery, such as futures, swaps or options.

The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during the period they are delivered and will be included in the various recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to be collected through retail rates from customers.

Foreign Currency Exchange Contracts

A significant portion of Avista Utilities’ natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Utilities’ short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled within sixty days with U.S. dollars. Avista Utilities hedges a portion of the foreign currency risk by purchasing Canadian currency contracts when such commodity transactions are initiated. This risk has not had a material effect on the Company’s financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations were included with natural gas supply costs for ratemaking.

The following table summarizes the foreign currency hedges that the Company has entered into as of September 30, 2013 and December 31, 2012 (dollars in thousands):



	September 30,		December 31,
	2013		2012
Number of contracts	14		20
Notional amount (in United States dollars)	$	1,852	$	12,621
Notional amount (in Canadian dollars)	1,929		12,502

Interest Rate Swap Agreements

Avista Corp. hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate swaps and U.S. Treasury lock agreements. These interest rate swap agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances.

The following table summarizes the interest rate swaps that the Company has entered into as of September 30, 2013 and December 31, 2012 (dollars in thousands):



Balance Sheet Date	Number of Contracts	Notional Amount		Mandatory Cash Settlement Date
September 30, 2013	2	$	50,000	October 2014
	2	45,000		October 2015
	1	20,000		October 2016
	2	50,000		June 2018
December 31, 2012	2	85,000		June 2013
	2	50,000		October 2014
	1	25,000		October 2015

In June 2013, the Company cash settled two interest rate swap contracts (notional amount of $85.0 million) and received a total of $2.9 million. The interest rate swap contracts were settled in connection with the pricing of $90.0 million of First Mortgage Bonds that were issued in August 2013 (see Note 8). Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt.

Derivative Instruments Summary

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of September 30, 2013 (in thousands):



		Fair Value
Derivative	Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netting		Net Asset (Liability) in Balance Sheet			Gross Assets Not Offset		Gross Liabilities Not Offset		Net Asset (Liability)
Foreign currency contracts	Other current assets	$	19	$	(1	)	$	—	$	18		$	—	$	—	$	18
Interest rate contracts	Other non-current liabilities and deferred credits	—		(471		)	—		(471		)	—		—		(471		)
Interest rate contracts	Other property and investments - net	25,178		—			—		25,178			—		—		25,178
Commodity contracts (1)	Current utility energy commodity derivative assets	4,078		(648		)	—		3,430			—		—		3,430
Commodity contracts (1)	Non-current utility energy commodity derivative assets	7,191		(6,898		)	—		293			—		—		293
Commodity contracts (1)	Current utility energy commodity derivative liabilities	34,858		(58,687		)	5,121		(18,708		)	—		—		(18,708		)
Commodity contracts (1)	Other non-current liabilities and deferred credits	23,274		(48,296		)	5,292		(19,730		)	—		—		(19,730		)
Total derivative instruments recorded on the balance sheet		$	94,598	$	(115,001	)	$	10,413	$	(9,990	)	$	—	$	—	$	(9,990	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2012 (in thousands):



		Fair Value
Derivative	Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netting		Net Asset (Liability) in Balance Sheet			Gross Assets Not Offset			Gross Liabilities Not Offset			Net Asset (Liability)
Foreign currency contracts	Other current liabilities	$	7	$	(34	)	$	—	$	(27	)	$	—		$	—		$	(27	)
Interest rate contracts	Other current liabilities	—		(1,406		)	—		(1,406		)	—			—			(1,406		)
Interest rate contracts	Other property and investments - net	7,265		—			—		7,265			—			—			7,265
Commodity contracts (1)	Current utility energy commodity derivative assets	10,772		(6,633		)	—		4,139			(9,678		)	6,572			1,033
Commodity contracts (1)	Non-current utility energy commodity derivative assets	18,779		(17,686		)	—		1,093			—			—			1,093
Commodity contracts (1)	Current utility energy commodity derivative liabilities	50,227		(89,449		)	9,707		(29,515		)	9,678			(6,572		)	(26,409		)
Commodity contracts (1)	Other non-current liabilities and deferred credits	2,247		(28,558		)	—		(26,311		)	—			—			(26,311		)
Total derivative instruments recorded on the balance sheet		$	89,297	$	(143,766	)	$	9,707	$	(44,762	)	$	—		$	—		$	(44,762	)

(1)

Avista Corp. has a master netting agreement that governs the transactions of multiple affiliated legal entities under this single master netting agreement. This master netting agreement allows for cross-commodity netting (i.e. netting physical power, physical natural gas, and financial transactions) and cross-affiliate netting for the parties to the agreement. Avista Corp. performs cross-commodity netting for each legal entity that is a party to the master netting agreement for presentation in the Condensed Consolidated Balance Sheets; however, Avista Corp. does not perform cross-affiliate netting because the Company believes that cross-affiliate netting may not be enforceable. Therefore, the requirements for cross-affiliate netting under ASC 210-20-45 are not applicable for Avista Corp. As of September 30, 2013, all derivatives for each affiliated entity under this master netting agreement were in a net liability position. As such, there is no additional netting which requires disclosure.

Exposure to Demands for Collateral

The Company's derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement in the event of a downgrade in the Company's credit ratings or changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against the Company's credit facilities and cash. The Company actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements. As of September 30, 2013, the Company had cash deposited as collateral of $23.8 million and letters of credit of $20.1 million outstanding related to its energy derivative contracts. The Condensed Consolidated Balance Sheet at September 30, 2013 reflects the offsetting of $10.4 million of cash collateral against net derivative positions where a legal right of offset exists.

Certain of the Company’s derivative instruments contain provisions that require the Company to maintain an "investment grade" credit rating from the major credit rating agencies. If the Company’s credit ratings were to fall below “investment grade,” it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position as of September 30, 2013 was $23.3 million. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2013, the Company could be required to post $18.5 million of additional collateral to its counterparties.

Credit Risk

Credit risk relates to the potential losses that the Company would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy or make financial settlements. The Company often extends credit to counterparties and customers and is exposed to the risk that it may not be able to collect amounts owed to the Company. Credit risk includes potential counterparty default due to circumstances:


•	relating directly to it,


•	caused by market price changes, and


•	relating to other market participants that have a direct or indirect relationship with such counterparty.

Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits are established. Should a counterparty fail to perform, the Company may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices.

We enter into bilateral transactions between Avista and various counterparties. We also trade energy and related derivative instruments through clearinghouse exchanges.

The Company seeks to mitigate bilateral credit risk by:


•	entering into bilateral contracts that specify credit terms and protections against default,


•	applying credit limits and duration criteria to existing and prospective counterparties,


•	actively monitoring current credit exposures,


•	asserting our collateral rights with counterparties,


•	carrying out transaction settlements timely and effectively, and


•	conducting transactions on exchanges with fully collateralized clearing arrangements that significantly reduce counterparty default risk.

The Company's credit policy includes an evaluation of the financial condition of counterparties. Credit risk management includes collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees. The Company enters into various agreements that address credit risks including standardized agreements that allow for the netting or offsetting of positive and negative exposures.

The Company has concentrations of suppliers and customers in the electric and natural gas industries including:


•	electric and natural gas utilities,


•	electric generators and transmission providers,


•	natural gas producers and pipelines,


•	financial institutions including commodity clearing exchanges and related parties, and


•	energy marketing and trading companies.

In addition, the Company has concentrations of credit risk related to geographic location as it operates in the western United States and western Canada. These concentrations of counterparties and concentrations of geographic location may impact the Company’s overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions.

The Company maintains credit support agreements with certain counterparties and margin calls are periodically made and/or received. Margin calls are triggered when exposures exceed contractual limits or when there are changes in a counterparty’s creditworthiness. Price movements in electricity and natural gas can generate exposure levels in excess of these contractual limits. Negotiating for collateral in the form of cash, letters of credit, or performance guarantees is common industry practice.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 815
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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Reference 20: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Pension Plans And Other Postretirement Benefit Plans

9 Months Ended

Sep. 30, 2013

General Discussion of Pension and Other Postretirement Benefits [Abstract]

Pension Plans and Other Postretirement Benefit Plans

PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

The Company has a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities. Individual benefits under this plan are based upon the employee’s years of service, date of hire 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 $44.0 million in cash to the pension plan for the nine months ended September 30, 2013. No further contributions are expected for the remainder of 2013. The Company contributed $44 million in cash to the pension plan in 2012.

In October 2013, the Company revised its defined benefit pension plan such that as of January 1, 2014 the plan will be closed to all non-union employees hired or rehired by the Company on or after January 1, 2014. All actively employed non-union employees that were hired prior to January 1, 2014 and are currently covered under the defined benefit pension plan will continue accruing benefits as originally specified in the plan. A defined contribution 401(k) plan will replace the defined benefit pension plan for all non-union employees hired or rehired on or after January 1, 2014. Under the defined contribution plan the company will provide a non-elective contribution as a percentage of each employee's pay based on his or her age. This defined contribution is in addition to the existing 401(k) contribution in which the Company matches a portion of the pay deferred by each participant. In addition to the above changes, the Company has also revised its lump sum calculation for non-union participants who retire under the defined benefit pension plan to provide non-union retirees on or after January 1, 2014 with a lump sum amount equivalent to the present value of the annuity based upon applicable discount rates.

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 liability and expense for this plan are included as pension benefits in the tables included in this Note.

The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. In October 2013, the Company revised the health care benefit plan such that beginning on January 1, 2020, the method for calculating health insurance premiums for non-union retirees under age 65 and active Company employees will be revised. The revisions will result in separate health insurance premium calculations for each group. In addition, for non-union employees hired or rehired on or after January 1, 2014, upon retirement the Company will no longer provide a contribution towards his or her medical premiums. The Company will provide access to its retiree medical plan, but the non-union employees hired or rehired on or after January 1, 2014 will pay the full cost of premiums upon retirement.

The Company has a Health Reimbursement Arrangement to provide employees with tax-advantaged funds to pay for allowable medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on the employee’s years of service and the ending salary. The liability and expense of this plan are included as other postretirement benefits.

The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement for those who became executive officers on or before December 31, 2007. Under the plan, an executive officer’s designated beneficiary will receive a payment equal to twice the executive officer’s annual base salary at the time of death (or if death occurs after retirement, a payment equal to twice the executive officer’s total annual pension benefit). The liability and expense for this plan are included as other postretirement benefits.

The Company uses a December 31 measurement date for its pension and other postretirement benefit 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
	2013			2012			2013			2012
Three months ended September 30:
Service cost	$	4,743		$	3,891		$	971		$	689
Interest cost	5,978			6,084			1,373			1,256
Expected return on plan assets	(6,900		)	(5,950		)	(402		)	(375		)
Transition obligation recognition	—			—			—			125
Amortization of prior service cost	75			75			(37		)	(37		)
Net loss recognition	3,220			3,019			1,395			1,250
Net periodic benefit cost	$	7,116		$	7,119		$	3,300		$	2,908
Nine months ended September 30:
Service cost	$	14,229		$	11,573		$	3,035		$	2,067
Interest cost	17,934			18,277			4,153			3,793
Expected return on plan assets	(20,700		)	(17,900		)	(1,202		)	(1,125		)
Transition obligation recognition	—			—			—			375
Amortization of prior service cost	225			225			(111		)	(111		)
Net loss recognition	9,989			8,797			4,342			3,814
Net periodic benefit cost	$	21,677		$	20,972		$	10,217		$	8,813

Committed Lines of Credit

9 Months Ended

Sep. 30, 2013

Short-term Debt [Abstract]

Committed Lines of Credit

COMMITTED LINES OF CREDIT

Avista Corp.

Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400 million with an expiration date of February 2017. The committed line of credit is secured by 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 committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time. As of September 30, 2013, the Company was in compliance with this covenant.

Balances outstanding and interest rates of borrowings under the Company’s revolving committed line of credit were as follows as of September 30, 2013 and December 31, 2012 (dollars in thousands):



	September 30,			December 31,
	2013			2012
Borrowings outstanding at end of period	$	66,000		$	52,000
Letters of credit outstanding at end of period	$	27,994		$	35,885
Average interest rate on borrowings at end of period	1.10		%	1.12		%

As of September 30, 2013 the borrowings outstanding under Avista Corp.'s committed line of credit were classified as short-term borrowings on the Condensed Consolidated Balance Sheet.

Ecova

Ecova has a $125.0 million committed line of credit agreement with various financial institutions that has an expiration date of July 2017. The credit agreement is secured by all of Ecova's assets excluding investments and funds held for clients.

The committed line of credit agreement contains customary covenants and default provisions, including a covenant which requires that Ecova's “Consolidated Total Funded Debt to EBITDA Ratio” (as defined in the credit agreement) must be 2.50 to 1.00 or less, with provisions in the credit agreement allowing for a temporary increase of this ratio if a qualified acquisition is consummated by Ecova. In addition, Ecova's “Consolidated Fixed Charge Coverage Ratio” (as defined in the credit agreement) must be greater than 1.50 to 1.00 as of the last day of any fiscal quarter. As of September 30, 2013, Ecova was in compliance with these covenants.

Balances outstanding and interest rates of borrowings under Ecova’s credit agreements were as follows as of September 30, 2013 and December 31, 2012 (dollars in thousands):



	September 30,			December 31,
	2013			2012
Borrowings outstanding at end of period	$	50,000		$	54,000
Average interest rate on borrowings at end of period	2.19		%	2.21		%

As of September 30, 2013 the borrowings outstanding under Ecova's committed line of credit were classified as long-term borrowings under committed line of credit on the Condensed Consolidated Balance Sheet.

Long-Term Debt

9 Months Ended

Sep. 30, 2013

Long-term Debt, Unclassified [Abstract]

Long-Term Debt

LONG-TERM DEBT

The following details long-term debt outstanding as of September 30, 2013 and December 31, 2012 (dollars in thousands):



Maturity		Interest	September 30,			December 31,
Year	Description	Rate	2013			2012
2013	First Mortgage Bonds	1.68%	$	50,000		$	50,000
2016	First Mortgage Bonds	0.84%	90,000			—
2018	First Mortgage Bonds	5.95%	250,000			250,000
2018	Secured Medium-Term Notes	7.39%-7.45%	22,500			22,500
2019	First Mortgage Bonds	5.45%	90,000			90,000
2020	First Mortgage Bonds	3.89%	52,000			52,000
2022	First Mortgage Bonds	5.13%	250,000			250,000
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	Secured Pollution Control Bonds (1)	(1)	66,700			66,700
2034	Secured Pollution Control Bonds (2)	(2)	17,000			17,000
2035	First Mortgage Bonds	6.25%	150,000			150,000
2037	First Mortgage Bonds	5.70%	150,000			150,000
2040	First Mortgage Bonds	5.55%	35,000			35,000
2041	First Mortgage Bonds	4.45%	85,000			85,000
2047	First Mortgage Bonds	4.23%	80,000			80,000
	Total secured long-term debt		1,426,700			1,336,700
	Other long-term debt and capital leases		4,680			5,092
	Settled interest rate swaps (3)		(23,760		)	(27,900		)
	Unamortized debt discount		(1,330		)	(1,453		)
	Total		1,406,290			1,312,439
	Secured Pollution Control Bonds held by Avista Corporation (1) (2)		(83,700		)	(83,700		)
	Current portion of long-term debt		(50,330		)	(50,372		)
	Total long-term debt		$	1,272,260		$	1,178,367

(1)

In December 2010, $66.7 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due 2032, which had been held by Avista Corp. since 2008, were refunded by a new bond issue (Series 2010A). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, these bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s Condensed Consolidated Balance Sheet.

(2)

In December 2010, $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds, (Avista Corporation Colstrip Project) due 2034, which had been held by Avista Corp. since 2009, were refunded by a new bond issue (Series 2010B). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, the bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s Condensed Consolidated Balance Sheet.


(3)	Upon settlement of interest rate swaps, these are recorded as a regulatory asset or liability and included as part of long-term debt above. They are amortized as a component of interest expense over the life of the associated debt and included as a part of the Company's cost of debt calculation for ratemaking purposes.

In August 2013, Avista Corp. entered into a $90.0 million term loan agreement with an institutional investor that bears an annual interest rate of 0.84 percent and matures in 2016. The term loan agreement is secured by non-transferable First Mortgage Bonds of the Company issued to the agent bank that will only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the term loan agreement. The net proceeds from the $90.0 million term loan agreement were used to repay a portion of corporate indebtedness in anticipation of $50.0 million in First Mortgage Bonds maturing in December 2013.

Nonrecourse Long-Term Debt

Nonrecourse long-term debt (including current portion) represents the long-term debt of Spokane Energy. To provide funding to acquire a long-term fixed rate electric capacity contract from Avista Corp., Spokane Energy borrowed $145.0 million from a funding trust in December 1998. The long-term debt has scheduled monthly installments and interest at a fixed rate of 8.45 percent with the final payment due in January 2015. Spokane Energy bears full recourse risk for the debt, which is secured by the fixed rate electric capacity contract and $1.6 million of funds held in a trust account.

Fair Value

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value

FAIR VALUE

The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable and short-term borrowings are reasonable estimates of their fair values. Long-term debt (including current portion, but excluding capital leases), nonrecourse long-term debt and long-term debt to affiliated trusts are reported at carrying value on the Condensed Consolidated Balance Sheets.

The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), but also the impact of Avista Corp.’s nonperformance risk on its liabilities.

The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012 (dollars in thousands):



	September 30, 2013				December 31, 2012
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	951,000	$	1,083,214	$	951,000	$	1,164,639
Long-term debt (Level 3)	392,000		382,426		302,000		320,892
Nonrecourse long-term debt (Level 3)	21,688		22,875		32,803		35,297
Long-term debt to affiliated trusts (Level 3)	51,547		36,861		51,547		43,686

These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information. Due to the unique nature of the long-term fixed rate electric capacity contract securing the long-term debt of Spokane Energy (nonrecourse long-term debt), the estimated fair value of nonrecourse long-term debt was determined based on a discounted cash flow model using available market information.

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012 at fair value on a recurring basis (dollars in thousands):



	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
September 30, 2013
Assets:
Energy commodity derivatives	$	—	$	69,334	$	—	$	(65,611	)	$	3,723
Level 3 energy commodity derivatives:
Power exchange agreement	—		—		67		(67		)	—
Foreign currency derivatives	—		19		—		—			19
Interest rate swaps	—		25,178		—		—			25,178
Investments and funds held for clients:
Money market funds	3,238		—		—		—			3,238
Securities available for sale:
U.S. government agency	—		66,165		—		—			66,165
Municipal	—		3,542		—		—			3,542
Corporate fixed income – financial	—		3,004		—		—			3,004
Corporate fixed income – industrial	—		1,766		—		—			1,766
Certificate of deposits	—		1,000		—		—			1,000
Funds held in trust account of Spokane Energy	1,600		—		—		—			1,600
Deferred compensation assets:
Fixed income securities (2)	1,829		—		—		—			1,829
Equity securities (2)	6,213		—		—		—			6,213
Total	$	12,880	$	170,008	$	67	$	(65,678	)	$	117,277
Liabilities:
Energy commodity derivatives	$	—	$	96,464	$	—	$	(76,024	)	$	20,440
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		1,193		—			1,193
Power exchange agreement	—		—		16,111		(67		)	16,044
Power option agreement	—		—		761		—			761
Foreign currency derivatives	—		1		—		—			1
Interest rate swaps	—		471		—		—			471
Total	$	—	$	96,936	$	18,065	$	(76,091	)	$	38,910



	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
December 31, 2012
Assets:
Energy commodity derivatives	$	—	$	81,640	$	—	$	(76,408	)	$	5,232
Level 3 energy commodity derivatives:
Power exchange agreement	—		—		385		(385		)	—
Foreign currency derivatives	—		7		—		(7		)	—
Interest rate swaps	—		7,265		—		—			7,265
Investments and funds held for clients:
Money market funds	15,084		—		—		—			15,084
Securities available for sale:
U.S. government agency	—		48,496		—		—			48,496
Municipal	—		848		—		—			848
Corporate fixed income – financial	—		5,026		—		—			5,026
Corporate fixed income – industrial	—		3,936		—		—			3,936
Certificate of deposits	—		1,015		—		—			1,015
Funds held in trust account of Spokane Energy	1,600		—		—		—			1,600
Deferred compensation assets:
Fixed income securities (2)	2,010		—		—		—			2,010
Equity securities (2)	5,955		—		—		—			5,955
Total	$	24,649	$	148,233	$	385	$	(76,800	)	$	96,467
Liabilities:
Energy commodity derivatives	$	—	$	119,390	$	—	$	(86,115	)	$	33,275
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		2,379		—			2,379
Power exchange agreement	—		—		19,077		(385		)	18,692
Power option agreement	—		—		1,480		—			1,480
Foreign currency derivatives	—		34		—		(7		)	27
Interest rate swaps	—		1,406		—		—			1,406
Total	$	—	$	120,830	$	22,936	$	(86,507	)	$	57,259


(1)	The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.


(2)	These assets are trading securities and are included in other property and investments-net on the Condensed Consolidated Balance Sheets.

Avista Corp. enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of Avista Corp.’s management of loads and resources and certain contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in respective levels and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of utility derivative commodity instruments included in Level 2. In particular, electric derivative valuations are performed using broker quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange (NYMEX) pricing for similar instruments, adjusted for basin differences, using broker quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2.

For securities available for sale (held at Ecova) Ecova uses a nationally recognized third party to obtain fair value and reviews these prices for accuracy using a variety of market tools and analysis. Ecova's pricing vendor uses a generic model which uses standard inputs, including (listed in order of priority for use) benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, market bids/offers and other reference data. The pricing vendor also monitors market indicators, as well as industry and economic events. All securities available for sale were deemed Level 2.

Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table above excludes cash and cash equivalents of $0.8 million as of September 30, 2013 and December 31, 2012.

Level 3 Fair Value

For the power exchange agreement, the Company compares the Level 2 brokered quotes and forward price curves described above to an internally developed forward price which is based on the average operating and maintenance (O&M) charges from four surrogate nuclear power plants around the country for the current year. Because the nuclear power plant O&M charges are only known for one year, all forward years are estimated assuming an annual escalation. In addition to the forward price being estimated using unobservable inputs, the Company also estimates the volumes of the transactions that will take place in the future based on historical average transaction volumes per delivery year (November to April). Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, a change in the current year O&M charges for the surrogate plants is accompanied by a directionally similar change in O&M charges in future years. There is generally not a correlation between external market prices and the O&M charges used to develop the internal forward price.

For the power commodity option agreement, the Company uses the Black-Scholes-Merton valuation model to estimate the fair value, and this model includes significant inputs not observable or corroborated in the market. These inputs include 1) the strike price (which is an internally derived price based on a combination of generation plant heat rate factors, natural gas market pricing, delivery and other O&M charges, 2) estimated delivery volumes for years beyond 2013, and 3) volatility rates for periods beyond October 2016. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, changes in overall commodity market prices and volatility rates are accompanied by directionally similar changes in the strike price and volatility assumptions used in the calculation.

For the natural gas commodity exchange agreement, the Company uses the same Level 2 brokered quotes described above; however, the Company also estimates the sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated with market prices and market volatility. As of September 30, 2013, all contractual purchases have been made by Avista Corp. under the natural gas commodity exchange agreement; therefore, the Company no longer estimates forward purchase volumes and forward purchase prices as these are not significant inputs to the calculation.

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of September 30, 2013 (dollars in thousands):



	Fair Value (Net) at
	September 30, 2013			Valuation Technique	Unobservable Input	Range
Power exchange agreement	$	(16,044	)	Surrogate facility pricing	O&M charges	$30.18-$53.90/MWh (1)
					Escalation factor	3% - 2014 to 2019
					Transaction volumes	365,619 - 394,255 MWhs
Power option agreement	(761		)	Black-Scholes- Merton	Strike price	$55.53/MWh - 2015
					Strike price	$69.60/MWh - 2019
					Delivery volumes	157,517 - 287,147 MWhs
					Volatility rates	0.20 (2)
Natural gas exchange agreement	(1,193		)	Internally derived weighted average cost of gas	Forward purchase prices	(3)
					Forward purchase prices	(3)
					Forward sales prices	$3.64 - $4.19/mmBTU
					Purchase volumes	(3)
					Sales volumes	139,980 - 310,000 mmBTUs

(1) The average O&M charges for 2013 were $40.93 per MWh.

(2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.32 for 2013 to 0.21 in October 2016.


(3)	As of September 30, 2013, all contractual purchases have been made by Avista Corp. under the natural gas exchange agreement; therefore, the Company no longer estimates forward purchase volumes and forward purchase prices as these are not significant inputs to the calculation.

Avista Corp.'s risk management team and accounting team are responsible for developing the valuation methods described above and both groups report to the Chief Financial Officer. The valuation methods, the significant inputs, and the resulting fair values described above are reviewed on at least a quarterly basis by the risk management team and the accounting team to ensure they provide a reasonable estimate of fair value each reporting period.

The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the three and nine months ended September 30, 2013 and 2012 (dollars in thousands):



	Natural Gas Exchange Agreement			Power Exchange Agreement			Power Option Agreement			Total
Three months ended September 30, 2013:
Balance as of July 1, 2013	$	(1,022	)	$	(22,179	)	$	(596	)	$	(23,797	)
Total gains or losses (realized/unrealized):
Included in net income	—			—			—			—
Included in other comprehensive income	—			—			—			—
Included in regulatory assets/liabilities (1)	(170		)	6,135			(165		)	5,800
Purchases	—			—			—			—
Issuance	—			—			—			—
Settlements	(1		)	—			—			(1		)
Transfers to/from other categories	—			—			—			—
Ending balance as of September 30, 2013	$	(1,193	)	$	(16,044	)	$	(761	)	$	(17,998	)



	Natural Gas Exchange Agreement			Power Exchange Agreement			Power Option Agreement			Total
Three months ended September 30, 2012:
Balance as of July 1, 2012	$	(2,727	)	$	(10,438	)	$	(1,756	)	$	(14,921	)
Total gains or losses (realized/unrealized):
Included in net income	—			—			—			—
Included in other comprehensive income	—			—			—			—
Included in regulatory assets/liabilities (1)	(377		)	(7,438		)	171			(7,644		)
Purchases	—			—			—			—
Issuance	—			—			—			—
Settlements	(1		)	—			—			(1		)
Transfers to/from other categories	—			—			—			—
Ending balance as of September 30, 2012	$	(3,105	)	$	(17,876	)	$	(1,585	)	$	(22,566	)
Nine months ended September 30, 2013:
Balance as of January 1, 2013	$	(2,379	)	$	(18,692	)	$	(1,480	)	$	(22,551	)
Total gains or losses (realized/unrealized):
Included in net income	—			—			—			—
Included in other comprehensive income	—			—			—			—
Included in regulatory assets/liabilities (1)	1,637			(113		)	719			2,243
Purchases	—			—			—			—
Issuance	—			—			—			—
Settlements	(451		)	2,761			—			2,310
Transfers to/from other categories	—			—			—			—
Ending balance as of September 30, 2013	$	(1,193	)	$	(16,044	)	$	(761	)	$	(17,998	)
Nine months ended September 30, 2012:
Balance as of January 1, 2012	$	(1,688	)	$	(9,910	)	$	(1,260	)	$	(12,858	)
Total gains or losses (realized/unrealized):
Included in net income	—			—			—			—
Included in other comprehensive income	—			—			—			—
Included in regulatory assets/liabilities (1)	(364		)	(12,216		)	(325		)	(12,905		)
Purchases	—			—			—			—
Issuance	—			—			—			—
Settlements	(1,053		)	4,250			—			3,197
Transfers from other categories	—			—			—			—
Ending balance as of September 30, 2012	$	(3,105	)	$	(17,876	)	$	(1,585	)	$	(22,566	)

(1)

The UTC and the IPUC issued accounting orders authorizing Avista Utilities to offset commodity 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 delivery. The orders provide for Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Condensed Consolidated Statements of Income. Realized gains or losses are recognized in the period of delivery, 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 in Washington, the PCA mechanism in Idaho, and periodic general rates cases.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Earnings Per Common Share Attributable To Avista Corporation

9 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Earnings Per Common Share Attributable To Avista Corporation Shareholders

EARNINGS PER COMMON SHARE ATTRIBUTABLE TO AVISTA CORPORATION SHAREHOLDERS

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



	Three months ended						Nine months ended
	September 30,						September 30,
	2013			2012			2013			2012
Numerator:
Net income attributable to Avista Corporation shareholders	$	11,413		$	5,786		$	79,411		$	62,352
Subsidiary earnings adjustment for dilutive securities	(81		)	(16		)	(163		)	(25		)
Adjusted net income attributable to Avista Corporation shareholders for computation of diluted earnings per common share	$	11,332		$	5,770		$	79,248		$	62,327
Denominator:
Weighted-average number of common shares outstanding-basic	59,994			59,047			59,933			58,778
Effect of dilutive securities:
Performance and restricted stock awards	38			71			31			234
Stock options	—			5			—			14
Weighted-average number of common shares outstanding-diluted	60,032			59,123			59,964			59,026
Earnings per common share attributable to Avista Corporation shareholders:
Basic	$	0.19		$	0.10		$	1.32		$	1.06
Diluted	$	0.19		$	0.10		$	1.32		$	1.06

There were no shares excluded from the calculation because they were antidilutive. All stock options had exercise prices which were less than the average market price of Avista Corp. common stock during the respective periods.

Commitments And Contingencies	9 Months Ended
Commitments And Contingencies	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	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. For all such matters, 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. For matters that affect Avista Utilities’ operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process. Federal Energy Regulatory Commission Inquiry In April 2004, the Federal Energy Regulatory Commission (FERC) approved the contested Agreement in Resolution of Section 206 Proceeding (Agreement in Resolution) between Avista Corp. doing business as Avista Utilities, Avista Energy and the FERC's Trial Staff which stated that there was: (1) no evidence that any executives or employees of Avista Utilities or Avista Energy knowingly engaged in or facilitated any improper trading strategy during 2000 and 2001; (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) no finding that Avista Utilities or Avista Energy withheld relevant information from the FERC's inquiry into the western energy markets for 2000 and 2001 (Trading Investigation). Pending before the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) are petitions of the Attorney General of the State of California (California AG) and the California Electricity Oversight Board challenging FERC's decisions approving the Agreement in Resolution. In May 2004, the FERC provided notice that Avista Energy was no longer subject to an investigation reviewing certain bids above $250 per MW in the short-term energy markets operated by the California Independent System Operator (CalISO) and the California Power Exchange (CalPX) from May 1, 2000 to October 2, 2000 (Bidding Investigation). That matter is also pending before the Ninth Circuit, after the California AG, Pacific Gas & Electric (PG&E), Southern California Edison Company (SCE) and the California Public Utilities Commission (CPUC) filed petitions for review in 2005. Based on the FERC's order approving the Agreement in Resolution in the Trading Investigation and order denying rehearing requests, the Company does not expect that this proceeding will have any material effect on its financial condition, results of operations or cash flows. Furthermore, based on information currently known to the Company regarding the Bidding Investigation and the fact that the FERC Staff did not find any evidence of manipulative behavior, the Company does not expect that this matter will have a material 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 CalISO and the CalPX during the period from October 2, 2000 to June 20, 2001 (Refund Period). Proposed refunds are based on the calculation of mitigated market clearing prices for each hour. The FERC ruled that if the refunds required by the formula would cause a seller to recover less than its actual costs for the Refund Period, sellers may document these costs and limit their refund liability commensurately. In September 2005, Avista Energy submitted its cost filing claim pursuant to the FERC's August 2005 order. The filing was initially accepted by the FERC, but in March 2011, the FERC ordered Avista Energy to remove any return on equity in a compliance filing with the CalISO, which Avista Energy did in April 2011. A challenge to Avista Energy's cost filing by the California AG, the CPUC, PG&E and SCE was denied in July 2011 as a collateral attack on the FERC's prior orders accepting Avista Energy's cost filing. In July 2011, the California AG, the CPUC, PG&E and SCE filed a petition for review of the FERC's orders regarding Avista Energy's cost filing with the Ninth Circuit. The 2001 bankruptcy of PG&E resulted in a default on its payment obligations to the CalPX. As a result, Avista Energy has not been paid for all of its energy sales during the Refund Period. Those funds are now in escrow accounts and will not be released until the FERC issues an order directing such release in the California refund proceeding. As of September 30, 2013, Avista Energy's accounts receivable outstanding related to defaulting parties in California were fully offset by reserves for uncollected amounts and funds collected from the defaulting parties. 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 an FPA section 309 remedy for tariff violations prior to that date. In an order issued in May 2011, the FERC clarified the issues set for hearing for the period May 1, 2000 - October 1, 2000 (Summer Period): (1) which market practices and behaviors constitute a violation of the then-current CalISO, CalPX, and individual seller's tariffs and FERC orders; (2) whether any of the sellers named as respondents in this proceeding engaged in those tariff violations; and (3) whether any such tariff violations affected the market clearing price. The FERC also gave the California Parties an opportunity to show that exchange transactions with the CalISO during the Refund Period were not just and reasonable. Avista Energy had one exchange transaction with the CalISO during the Refund Period. The California AG, the CPUC, PG&E and SCE filed for rehearing of the FERC's May 2011 order, arguing that it improperly denies them a market-wide remedy for the pre-refund period. That request for rehearing was denied in an order issued by the FERC on November 2, 2012. The California AG, the CPUC, PG&E and SCE filed a petition for review of the May 2011 and November 2012 orders with the Ninth Circuit on November 7, 2012. A FERC hearing commenced on April 11, 2012 and concluded on July 19, 2012. On August 27, 2012, the Presiding Administrative Law Judge (ALJ) issued a partial initial decision granting Avista Utilities' motion for summary disposition, based on the stipulation by the California Parties that there are no allegations of tariff violations made against Avista Utilities in this proceeding and therefore no tariff violations by Avista Utilities that affected the market clearing price in any hour during the Summer Period. On November 2, 2012, the FERC issued an order affirming the partial initial decision and dismissing Avista Utilities from the proceeding, thereby terminating all claims against Avista Utilities for the Summer Period. In the same order, the FERC also held that a market-wide remedy would not be appropriate with regard to any respondent during the Summer Period. The FERC stated that it is clear that the Ninth Circuit did not mandate a specific remedy on remand and, instead, left it to the FERC's discretion to determine which remedy would be appropriate. On December 3, 2012, the California Parties filed a request for clarification and rehearing of the November 2, 2012 order. On February 15, 2013, the ALJ issued an initial decision finding that certain Respondents committed various tariff and other violations that affected the market clearing price in the California organized markets during the Summer Period. The tariff violations identified for Avista Energy are type II and III bidding violations; false export violations; and selling ancillary services without market-based rate authority. The initial decision did not discuss evidence offered by Avista Energy, on an hour-by-hour basis, rebutting the alleged violations. With respect to Avista Energy's one exchange transaction with the CalISO during the Refund Period, the judge made no findings with respect to the justness and reasonableness of that transaction, but nonetheless determined that Avista Energy owed approximately $0.2 million in refunds with regard to the transaction. Avista Energy filed its brief on exceptions to the initial decision on April 12, 2013. The California AG, the CPUC, PG&E and SCE filed a brief opposing exceptions on June 7, 2013. Because the resolution of the California refund proceeding remains uncertain, legal counsel cannot express an opinion on the extent of the Company's liability, if any. However, based on information currently known, the Company does not expect that the refunds ultimately ordered for the Refund Period would result in a material loss. In the event that the Commission does not overturn the legal and factual errors in the February 15, 2013 initial decision, the Company does not expect that the refunds ultimately ordered for that period would result in a material loss either. This is primarily due to the fact that the FERC orders have stated that any refunds will be netted 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 of wholesale energy in the Pacific Northwest between December 25, 2000 and June 20, 2001 were just and reasonable. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of refunds. In August 2007, the Ninth Circuit found that the FERC, in denying the request for refunds, had failed to take into account new evidence of market manipulation in the California energy market and its potential ties to the Pacific Northwest energy market and that such failure was arbitrary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC's findings must be reevaluated in light of the evidence. In addition, the Ninth Circuit concluded that the FERC abused its discretion in denying potential relief for transactions involving energy that was purchased by California Energy Resources Scheduling (CERS) in the Pacific Northwest and ultimately consumed in California. The Ninth Circuit expressly declined to direct the FERC to grant refunds. The Ninth Circuit denied petitions for rehearing by various parties, and remanded the case to the FERC in April 2009. On October 3, 2011, the FERC issued an Order on Remand, finding that, in light of the Ninth Circuit's remand order, additional procedures are needed to address possible unlawful activity that may have influenced prices in the Pacific Northwest spot market during the period from December 25, 2000 through June 20, 2001. The Order on Remand establishes an evidentiary, trial-type hearing before an ALJ, and reopens the record to permit parties to present evidence of unlawful market activity. The Order on Remand also allows participants to supplement the record with additional evidence on CERS transactions in the Pacific Northwest spot market from January 18, 2001 to June 20, 2001. The Order on Remand states that parties seeking refunds must submit evidence demonstrating that specific unlawful market activity occurred, and must demonstrate that such activity directly affected negotiations with respect to the specific contract rate about which they complain. Simply alleging a general link between the dysfunctional spot market in California and the Pacific Northwest spot market will not be sufficient to establish a causal connection between a particular seller's alleged unlawful activities and the specific contract negotiations at issue. On July 11, 2012, Avista Energy and Avista Utilities filed settlements of all issues in this docket with regard to the claims made by the City of Tacoma. On September 21, 2012, and September 26, 2012, the FERC issued orders approving the settlements between the City of Tacoma and Avista Utilities and Avista Energy, respectively, thus terminating those claims. The two remaining direct claimants against Avista Utilities and Avista Energy in this proceeding are the City of Seattle, Washington (Seattle), and the California Attorney General (on behalf of CERS). On April 5, 2013, the FERC issued an Order on Rehearing of the October 3, 2011 Order on Remand. The Order on Rehearing reaffirmed the rulings in the Order on Remand about the scope of the hearing and permissible evidence, rejecting various challenges by the claimants. The Order on Rehearing expanded the temporal scope of the proceeding to permit parties to submit evidence on transactions during the period from January 1, 2000 through and including June 20, 2001. The hearing before an administrative law judge began on August 27, 2013, and concluded on October 24, 2013. The parties’ initial post-hearing briefs are due on December 16, 2013, and their reply briefs are due on January 28, 2014. The ALJ’s initial decision is anticipated on or before March 18, 2014. On April 11, 2013, the California Parties filed a petition for review of the October 3, 2011 Order on Remand and the April 5, 2013 Order on Rehearing, in the Ninth Circuit. Seattle filed a petition for review of the same orders on April 26, 2013. On May 22, 2013, the Ninth Circuit issued an order consolidating the California Parties' and Seattle's petitions for review with respect to the Order on Remand and the Order on Rehearing. Both Avista Utilities and Avista Energy were buyers and sellers of energy in the Pacific Northwest energy market during the period between January 1, 2000 and June 20, 2001, and are subject to potential claims in this proceeding. If refunds are ordered by the FERC with regard to any particular contract, Avista Utilities and Avista Energy could be liable to make payments. The Company cannot predict the outcome of this proceeding or the amount of any refunds that Avista Utilities or Avista Energy could be ordered to make. Therefore, the Company cannot predict the potential impact the outcome of this matter could ultimately have on the Company's results of operations, financial condition or cash flows. California Attorney General Complaint (the “Lockyer Complaint”) In May 2002, the FERC conditionally dismissed a complaint filed in March 2002 by the California AG that alleged violations of the FPA 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. In September 2004, the Ninth Circuit upheld the FERC's market-based rate authority, but held that the FERC erred in ruling that it lacked authority to order refunds for violations of its reporting requirement. The Court remanded the case for further proceedings. In March 2008, the FERC issued an order establishing a trial-type hearing to address “whether any individual public utility seller's violation of the FERC's market-based rate quarterly reporting requirement led to an unjust and unreasonable rate for that particular seller in California during the 2000-2001 period.” Purchasers in the California markets were given the opportunity to present evidence that “any seller that violated the quarterly reporting requirement failed to disclose an increased market share sufficient to give it the ability to exercise market power and thus cause its market-based rates to be unjust and unreasonable.” In March 2010, the Presiding ALJ granted the motions for summary disposition and found that a hearing was “unnecessary” because the California AG, CPUC, PG&E and SCE “failed to apply the appropriate test to determine market power during the relevant time period.” The judge determined that “[w]ithout a proper showing of market power, the California Parties failed to establish a prima facie case.” In May 2011, the FERC affirmed “in all respects” the ALJ's decision. In June 2011, the California AG, CPUC, PG&E and SCE filed for rehearing of that order. Those rehearing requests were denied by the FERC on June 13, 2012. On June 20, 2012, the California AG, CPUC, PG&E and SCE filed a petition for review of the FERC's order with the Ninth Circuit. Based on information currently known to the Company's management, the Company does not expect that this matter will have a material effect on its financial condition, results of operations or cash flows. Colstrip Generating Project - Complaint Alleging Water Pollution In March 2007, two families that own property near the holding ponds from Units 3 & 4 of the Colstrip Generating Project (Colstrip) filed a complaint against the owners of Colstrip and Hydrometrics, Inc. in Montana District Court. Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrip. The plaintiffs alleged that the holding ponds and remediation activities adversely impacted their property. They alleged contamination, decrease in water tables, reduced flow of streams on their property and other similar impacts to their property. They also sought punitive damages, attorneys' fees, an order by the court to remove certain ponds, and the forfeiture of profits earned from the generation of Colstrip. In September 2010, the owners of Colstrip filed a motion with the court to enforce a settlement agreement that would resolve all issues between the parties. In October 2011 the court issued an order which enforces the settlement agreement. The plaintiffs subsequently appealed the court's decision and, on December 31, 2012, the Montana Supreme Court issued its decision, holding that the District Court properly granted the motion to enforce the settlement agreement. A petition for rehearing before the Supreme Court was denied on February 5, 2013. A motion to dismiss the case was approved by the court. Under the settlement, Avista Corp.'s portion of payment (which was accrued in 2010) to the plaintiffs was not material to its financial condition, results of operations or cash flows. Sierra Club and Montana Environmental Information Center Litigation On March 6, 2013, the Sierra Club and Montana Environmental Information Center (MEIC) (collectively "Plaintiffs"), filed a Complaint (Complaint) in the United States District Court for the District of Montana, Billings Division, against the owners of the Colstrip Generating Project (Colstrip). Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrip. The other Colstrip co-owners are PPL Montana, Puget Sound Energy, Portland General Electric Company, NorthWestern Energy and PacifiCorp. The Complaint alleges certain violations of the Clean Air Act, including the New Source Review, Title V and opacity requirements. The Plaintiffs request that the Court grant injunctive and declaratory relief, impose civil penalties, require a beneficial environmental project in the areas affected by the alleged air pollution and require payment of Plaintiffs' costs of litigation and attorney fees. On May 3, 2013, the Colstrip owners and operator filed a partial motion to dismiss, seeking dismissal of 36 of the 39 claims. The Plaintiffs filed their opposition on May 31, 2013, and the owners and operator filed their reply on June 21, 2013. On July 17, 2013, the Court held a preliminary pretrial conference, and on July 18, 2013, the Court issued an Order establishing a procedural schedule and deadlines. On September 12, 2013, the Plaintiffs filed Plaintiffs’ First Motion for Partial Summary Judgment on the Applicable Method for Calculating Emission Increases from Modifications Made to the Colstrip Power Plant. The Colstrip Owners and Operator Response is due on November 15, 2013. On September 27, 2013, the Plaintiffs filed an Amended Complaint. The Amended Complaint withdrew from the original Complaint fifteen claims related to seven pre-January 1, 2001 Colstrip projects, and claims alleging violations of Title V and opacity requirements. The Amended Complaint alleges certain violations of the Clean Air Act and the New Source Review; and adds claims with respect to post-January 1, 2001 Colstrip projects. The Plaintiffs request that the Court grant injunctive and declaratory relief, order remediation of alleged environmental damage, impose civil penalties, require a beneficial environmental project in the areas affected by the alleged air pollution and require payment of Plaintiffs’ costs of litigation and attorney fees. On October 11, 2013, the Colstrip owners and operator filed a motion to dismiss, seeking dismissal of all of Plaintiffs' claims contained in the Amended Complaint. Due to the preliminary nature of the lawsuit, Avista Corporation cannot, at this time, predict the outcome of the matter. Spokane River Licensing The Company owns and operates six hydroelectric plants on the Spokane River. Five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street, and Post Falls) are regulated under one 50-year FERC license issued in June 2009 and are referred to as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. The license incorporated the 4(e) conditions that were included in the December 2008 Settlement Agreement with the United States Department of Interior and the Coeur d’Alene Tribe, as well as the mandatory conditions that were agreed to in the Idaho 401 Water Quality Certifications and in the amended Washington 401 Water Quality Certification. As part of the Settlement Agreement with the Washington Department of Ecology (Ecology), the Company has participated in the Total Maximum Daily Load (TMDL) process for the Spokane River and Lake Spokane, the reservoir created by Long Lake Dam. On May 20, 2010, the EPA approved the TMDL and on May 27, 2010, Ecology filed an amended 401 Water Quality Certification with the FERC for inclusion into the license. The amended 401 Water Quality Certification includes the Company's level of responsibility, as defined in the TMDL, for low dissolved oxygen levels in Lake Spokane. The Company submitted a draft Water Quality Attainment Plan for Dissolved Oxygen to Ecology in May 2012 and this was approved by Ecology in September 2012. This plan was subsequently approved by the FERC. The Company will begin to implement this plan, and management believes costs will not be material. On July 16, 2010, the City of Post Falls and the Hayden Area Regional Sewer Board filed an appeal with the United States District Court for the District of Idaho with respect to the EPA's approval of the TMDL. The Company, the City of Coeur d'Alene, Kaiser Aluminum and the Spokane River Keeper subsequently moved to intervene in the appeal. In September 2011, the EPA issued a stay to the litigation that will be in effect until either the permits are issued and all appeals and challenges are complete or the court lifts the stay. The stay is still in effect. During 2013, through a collaborative process with key stakeholders, a decision was reached to not move forward with a specific capital project to add oxygen to Lake Spokane. At the time of such decision, the Company had expended $1.3 million on the discontinued project. On September 26, 2013 and October 23, 2013, the UTC and IPUC, respectively issued Orders approving the Company's petition for an accounting order authorizing deferral of costs related to the discontinued project. The Washington portion of the project costs were $0.9 million and this amount has been recorded as a regulatory asset until the next general rate case. The Idaho portion of the costs of $0.4 million will be recorded as a regulatory asset during the fourth quarter of 2013 and will be included in the next general rate case. The Company will address the prudence and recovery of these costs in the next Washington and Idaho general rate cases, expected to be filed in 2014. The UTC and IPUC approved the recovery of licensing costs through the general rate case settlements in 2009. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to implementing the license for the Spokane River Project. Cabinet Gorge Total Dissolved Gas Abatement Plan Dissolved atmospheric gas levels in the Clark Fork River 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 as incorporated in Avista Corp.'s FERC license for the Clark Fork Project, Avista Corp. has worked in consultation with agencies, tribes and other stakeholders to address this issue. In the second quarter of 2011, the Company completed preliminary feasibility assessments for several alternative abatement measures. In 2012, Avista Corp., with the approval of the Clark Fork Management Committee (created under the Clark Fork Settlement Agreement), moved forward to test one of the alternatives by constructing a spill crest modification on a single spill gate. Based on testing in 2013, the modification appears to provide significant Total Dissolved Gas reduction. Further evaluation and design improvements are underway prior to applying this approach to other spill gates. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue. Fish Passage at Cabinet Gorge and Noxon Rapids In 1999, the USFWS listed bull trout as threatened under the Endangered Species Act. The Clark Fork Settlement Agreement describes programs intended to help restore bull trout populations in the project area. Using the concept of adaptive management and working closely with the USFWS, the Company evaluated the feasibility of fish passage at Cabinet Gorge and Noxon Rapids. The results of these studies led, in part, to the decision to move forward with development of permanent facilities, among other bull trout enhancement efforts. Fishway designs for Cabinet Gorge are still being finalized. Construction cost estimates and schedules will be developed after several remaining issues are resolved, related to Montana's approval of fish transport from Idaho and expected minimum discharge requirements. Fishway design for Noxon Rapids has also been initiated, and is still in early stages. In January 2010, the USFWS revised its 2005 designation of critical habitat for the bull trout to include the lower Clark Fork River as critical habitat. The Company believes its ongoing efforts through the Clark Fork Settlement Agreement continue to effectively address issues related to bull trout. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to fish passage at Cabinet Gorge and Noxon Rapids. 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 impact on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Information By Business Segments

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Information by Business Segments

INFORMATION BY BUSINESS SEGMENTS

The business segment presentation reflects the basis used by the Company's management to analyze performance and determine the allocation of resources. The Company's management evaluates performance based on income (loss) from operations before income taxes as well as net income (loss) attributable to Avista Corp. shareholders. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. Avista Utilities' business is managed based on the total regulated utility operation. Ecova is a provider of energy efficiency and other facility information and cost management programs and services for multi-site customers and utilities throughout North America. The Other category, which is not a reportable segment, includes Spokane Energy, other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital.

The following table presents information for each of the Company’s business segments (dollars in thousands):



	Avista Utilities		Ecova		Other			Total Non-Utility			Intersegment Eliminations (1)			Total
For the three months ended September 30, 2013:
Operating revenues	$	278,923	$	46,398	$	11,004		$	57,402		$	(450	)	$	335,875
Resource costs	131,136		—		—			—			—			131,136
Other operating expenses	69,596		37,047		10,662			47,709			(450		)	116,855
Depreciation and amortization	29,823		3,909		171			4,080			—			33,903
Income from operations	29,657		5,442		170			5,612			—			35,269
Interest expense (2)	18,837		398		525			923			(77		)	19,683
Income taxes	3,945		2,092		(578		)	1,514			—			5,459
Net income (loss) attributable to Avista Corporation shareholders	9,447		3,040		(1,074		)	1,966			—			11,413
Capital expenditures	75,368		357		24			381			—			75,749
For the three months ended September 30, 2012:
Operating revenues	$	292,535	$	38,617	$	9,930		$	48,547		$	(450	)	$	340,632
Resource costs	153,801		—		—			—			—			153,801
Other operating expenses	66,456		33,868		10,581			44,449			(450		)	110,455
Depreciation and amortization	28,255		3,260		131			3,391			—			31,646
Income from operations	25,901		1,489		(782		)	707			—			26,608
Interest expense (2)	18,001		530		824			1,354			(91		)	19,264
Income taxes	2,590		495		(1,477		)	(982		)	—			1,608
Net income (loss) attributable to Avista Corporation shareholders	7,660		640		(2,514		)	(1,874		)	—			5,786
Capital expenditures	57,964		1,023		619			1,642			—			59,606
For the nine months ended September 30, 2013:
Operating revenues	$	1,008,669	$	133,365	$	30,145		$	163,510		$	(1,350	)	$	1,170,829
Resource costs	487,277		—		—			—			—			487,277
Other operating expenses	200,824		110,753		30,322			141,075			(1,350		)	340,549
Depreciation and amortization	86,783		11,474		536			12,010			—			98,793
Income from operations	167,648		11,138		(713		)	10,425			—			178,073
Interest expense (2)	56,635		1,265		1,801			3,066			(230		)	59,471
Income taxes	43,278		4,178		(1,349		)	2,829			—			46,107
Net income (loss) attributable to Avista Corporation shareholders	76,265		5,759		(2,613		)	3,146			—			79,411
Capital expenditures	220,712		1,586		139			1,725			—			222,437
For the nine months ended September 30, 2012:
Operating revenues	$	992,210	$	115,707	$	29,907		$	145,614		$	(1,350	)	$	1,136,474
Resource costs	500,805		—		—			—			—			500,805
Other operating expenses	196,759		104,392		29,830			134,222			(1,350		)	329,631
Depreciation and amortization	83,327		9,455		511			9,966			—			93,293
Income from operations	147,596		1,860		(434		)	1,426			—			149,022
Interest expense (2)	54,148		1,301		2,691			3,992			(274		)	57,866
Income taxes	34,425		918		(2,237		)	(1,319		)	—			33,106
Net income (loss) attributable to Avista Corporation shareholders	65,157		962		(3,767		)	(2,805		)	—			62,352
Capital expenditures	178,440		3,248		660			3,908			—			182,348
Total Assets:
As of September 30, 2013:	$	3,961,718	$	353,128	$	87,156		$	440,284		$	—		$	4,402,002
As of December 31, 2012:	$	3,894,821	$	322,720	$	95,638		$	418,358		$	—		$	4,313,179


(1)	Intersegment eliminations reported as operating revenues and resource costs represent intercompany purchases and sales of electric capacity and energy. Intersegment eliminations reported as interest expense represent intercompany interest.


(2)	Including interest expense to affiliated trusts.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8380-108599

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8844-108599

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8984-108599

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9031-108599

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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-Section 50
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9054-108599

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8924-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8906-108599

+ Details

Subsequent Events

9 Months Ended

Sep. 30, 2013

Subsequent Events [Abstract]

Subsequent Events [Text Block]

SUBSEQUENT EVENTS

On November 4, 2013, the Company entered into an agreement and plan of merger (Merger Agreement) with Alaska Energy and Resources Company (AERC), a privately-held company based in Juneau, Alaska. When the transaction is complete, AERC will become a wholly-owned subsidiary of Avista Corp.

The primary subsidiary of AERC is Alaska Electric Light & Power Company (AEL&P), the oldest regulated electric utility in Alaska. In 2012, AEL&P had annual revenues of $42 million and a total rate base of $111 million. AEL&P has 60 full-time employees and is the sole provider of electric services to approximately 15,900 customers in the city and borough of Juneau.

In addition to the regulated utility, AERC owns the AJT Mining subsidiary, which is an inactive mining company holding certain mining properties.

The merger consideration at closing will be $170 million, less AERC's indebtedness and subject to other customary closing adjustments (Merger Consideration). The transaction will be funded primarily through the issuance of Avista common stock to the shareholders of AERC. The transaction is expected to close by July 1, 2014, following the receipt of necessary regulatory approvals and the satisfaction of other closing conditions. Avista Corp. shareholder approval is not required.

Pursuant to the Merger Agreement, among other things, each of the issued and outstanding shares of AERC common stock (other than Dissenting Shares) will be converted into the right to receive consideration as follows:


i.	the number of shares of Avista Corp. common stock equal to one share of AERC common stock multiplied by the Exchange Ratio; and


ii.	a portion of the Representative Reimbursement Amount.

For purposes of the foregoing:

The Exchange Ratio is the ratio obtained by dividing the Per Share Amount by (i) $21.48 if the Avista Corp. Closing Price is less than or equal to $21.48, (ii) the Avista Corp. Closing Price, if the Avista Corp. Closing Price is greater than $21.48 and less than $34.30 or (iii) $34.30 if the Avista Corp. Closing Price is greater than or equal to $34.30.

The Per Share Amount is the amount determined by dividing (a) the Merger Consideration (as adjusted) by (b) the aggregate number of shares of AERC common stock outstanding immediately prior to the closing of the transaction.

The Representative Reimbursement Amount is a $500,000 cash payment to be made by Avista Corp. at the Closing to the Shareholders’ Representative. The purpose of the Representative Reimbursement Amount is to reimburse the Shareholders’ Representative for expenses incurred by the Shareholders’ Representative in acting for the current shareholders of AERC in connection with the Merger. The total Merger Consideration will be reduced by the Representative Reimbursement Amount.

Dissenting Shares will not be converted into, or represent the right to receive, the Merger Consideration or any portion of the Representative Reimbursement Amount. Such shareholders will be entitled to receive payment of the fair value of Dissenting Shares held by them in accordance with the provisions of AS 10.06.580 of the Alaska Corporations Code. Any amounts paid to Dissenting Shares over the amounts otherwise payable in the form of Merger Consideration are indemnified expenses owed by AERC to Avista Corp.

The Merger Agreement has been approved by Avista Corp.'s and AERC's Boards of Directors, but the consummation of the transaction is subject to the satisfaction or waiver of specified closing conditions, including:


•	the registration under the Securities Act of 1933 of the shares of common stock that will be issued to AERC shareholders;


•	the approval of such shares for listing on the New York Stock Exchange;


•	the approval of the merger transaction by the requisite number of AERC shareholders;

•

the receipt of regulatory approvals and other consents required to consummate the merger transaction, including, among others, approvals from the FERC, the Regulatory Commission of Alaska, the UTC, the IPUC, the Public Utility Commission of Oregon (OPUC), the Public Service Commission of the State of Montana, the U.S. Federal Trade Commission (the FTC), the Antitrust Division of the U.S. Department of Justice (the DOJ) and any other applicable regulatory bodies on the terms and conditions specified in the definitive purchase agreement;


•	the absence of the occurrence of a material adverse effect (as defined in the Merger Agreement) relating to either AERC or Avista Corp. after the date of the signed agreement; and


•	other customary closing conditions.

The Merger Agreement also provides for customary termination rights for each of the Company and AERC, including the right for either party to terminate if the Merger has not been consummated by December 31, 2014; provided, however, that the failure of the Merger to have been consummated on or before December 31, 2014 was not caused by the failure of such party or any affiliate of such party to perform any of its obligations under the Merger Agreement. Upon termination of the Merger Agreement in accordance with its terms, there will be no further liability under the agreement except that nothing shall relieve any party thereto from liability for any breach of the agreement.

There may be certain commitments and contingencies that will be assumed when the merger transaction is consummated; however, Avista Corp. has not fully completed its evaluation of all the potential commitments and contingencies as of the date of this filing.

During the three and nine month periods ended September 30, 2013, Avista Corp. incurred $0.1 million (pre-tax) of transaction related fees which have been expensed and presented in the Condensed Consolidated Statements of Income in other operating expenses within other non-utility operating expenses. Avista Corp. expects to incur additional transaction related fees upon consummation of the transaction.

Summary Of Significant Accounting Policies (Policy)

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Accounting Changes and Error Corrections [Text Block]

Correction of an Immaterial Error

Nature Of Business

Nature of Business

Basis Of Reporting

Basis of Reporting

Taxes Other Than Income Taxes



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Utility taxes	$	10,901	$	10,741	$	41,045	$	41,353

Other Income - Net

Other (Income)/Expense-Net

Other (Income)/Expense-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,
	2013			2012			2013			2012
Interest income	$	(124	)	$	(166	)	$	(620	)	$	(804	)
Interest income on regulatory deferrals	(27		)	(19		)	(48		)	(43		)
Equity-related AFUDC	(1,595		)	(1,127		)	(4,341		)	(2,875		)
Net loss on investments	1,299			2,430			1,543			2,957
Other income	(537		)	(700		)	(2,099		)	(2,127		)
Total	$	(984	)	$	418		$	(5,565	)	$	(2,892	)

Materials And Supplies, Fuel Stock And Natural Gas Stored

Materials and Supplies, Fuel Stock and Natural Gas Stored



	September 30,		December 31,
	2013		2012
Materials and supplies	$	29,334	$	26,058
Fuel stock	3,750		4,121
Natural gas stored	23,759		17,276
Total	$	56,843	$	47,455

Investments And Funds Held For Clients And Client Fund Obligations

Investments and Funds Held for Clients and Client Fund Obligations



	Amortized Cost (1)		Unrealized Gain (Loss)			Fair Value
Cash and cash equivalents	$	14,155	$	—		$	14,155
Money market funds	3,238		—			3,238
Securities available for sale:
U.S. government agency	68,631		(2,466		)	66,165
Municipal	3,529		13			3,542
Corporate fixed income – financial	3,000		4			3,004
Corporate fixed income – industrial	1,753		13			1,766
Certificates of deposit	1,000		—			1,000
Total securities available for sale	77,913		(2,436		)	75,477
Total investments and funds held for clients	$	95,306	$	(2,436	)	$	92,870

Investments and funds held for clients as of December 31, 2012 are as follows (dollars in thousands):



	Amortized Cost (1)		Unrealized Gain (Loss)		Fair Value
Cash and cash equivalents	$	13,867	$	—	$	13,867
Money market funds	15,084		—		15,084
Securities available for sale:
U.S. government agency	48,340		156		48,496
Municipal	820		28		848
Corporate fixed income – financial	5,010		16		5,026
Corporate fixed income – industrial	3,887		49		3,936
Certificates of deposit	1,000		15		1,015
Total securities available for sale	59,057		264		59,321
Total investments and funds held for clients	$	88,008	$	264	$	88,272


(1)	Amortized cost represents the original purchase price of the investments, plus or minus any amortized purchase premiums or accreted purchase discounts.

The following is a summary of the disposition of available-for-sale securities for the three and nine months ended September 30 (dollars in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Proceeds from sales, maturities and calls	$	1,825	$	32,053	$	16,955	$	103,545
Gross realized gains	2		111		20		252
Gross realized losses	—		—		—		—

Contractual maturities of securities available for sale as of September 30, 2013 and December 31, 2012 are as follows (dollars in thousands):



	Due within 1 year		After 1 but within 5 years		After 5 but within 10 years		After 10 years		Total
September 30, 2013	$	5,655	$	18,479	$	48,437	$	2,906	$	75,477
December 31, 2012	3,047		11,786		41,485		3,003		59,321

Actual maturities may differ due to call or prepayment rights and the effective maturity was 3.1 years as of September 30, 2013 and 1.9 years as of December 31, 2012.

Goodwill

The changes in the carrying amount of goodwill are as follows (dollars in thousands):



	Ecova		Other		Accumulated Impairment Losses			Total
Balance as of December 31, 2012	$	70,713	$	12,979	$	(7,733	)	$	75,959
Adjustments	803		—		—			803
Balance as of September 30, 2013	$	71,516	$	12,979	$	(7,733	)	$	76,762

Intangible Assets

Amortization expense related to Intangible Assets was as follows for the three and nine months ended September 30 (dollars in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Intangible asset amortization	$	2,765	$	2,436	$	8,442	$	7,091

The following table details the estimated amortization expense related to Intangible Assets for each of the five years ending December 31 (dollars in thousands):



	Remaining
	2013		2014		2015		2016		2017
Estimated amortization expense	$	2,292	$	10,460	$	8,484	$	7,359	$	6,516

The gross carrying amount and accumulated amortization of Intangible Assets as of September 30, 2013 and December 31, 2012 are as follows (dollars in thousands):



	Estimated	September 30,			December 31,
	Useful Lives	2013			2012
Client backlog and relationships	2 - 12 years	$	33,559		$	32,059
Software development costs	3 - 7 years	38,148			33,990
Other	1 - 10 years	3,332			6,237
Total intangible assets		75,039			72,286
Client relationships accumulated amortization		(11,255		)	(7,793		)
Software development costs accumulated amortization		(20,383		)	(16,557		)
Other accumulated amortization		(2,248		)	(1,680		)
Total accumulated amortization		(33,886		)	(26,030		)
Total intangible assets - net		$	41,153		$	46,256

Of the total net intangible assets above, intangible assets associated with Ecova represent approximately $40.4 million and $45.4 million at September 30, 2013 and December 31, 2012, respectively.

Other Intangibles

Intangible Assets

Amortization expense related to Intangible Assets was as follows for the three and nine months ended September 30 (dollars in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Intangible asset amortization	$	2,765	$	2,436	$	8,442	$	7,091

The following table details the estimated amortization expense related to Intangible Assets for each of the five years ending December 31 (dollars in thousands):



	Remaining
	2013		2014		2015		2016		2017
Estimated amortization expense	$	2,292	$	10,460	$	8,484	$	7,359	$	6,516

The gross carrying amount and accumulated amortization of Intangible Assets as of September 30, 2013 and December 31, 2012 are as follows (dollars in thousands):



	Estimated	September 30,			December 31,
	Useful Lives	2013			2012
Client backlog and relationships	2 - 12 years	$	33,559		$	32,059
Software development costs	3 - 7 years	38,148			33,990
Other	1 - 10 years	3,332			6,237
Total intangible assets		75,039			72,286
Client relationships accumulated amortization		(11,255		)	(7,793		)
Software development costs accumulated amortization		(20,383		)	(16,557		)
Other accumulated amortization		(2,248		)	(1,680		)
Total accumulated amortization		(33,886		)	(26,030		)
Total intangible assets - net		$	41,153		$	46,256

Of the total net intangible assets above, intangible assets associated with Ecova represent approximately $40.4 million and $45.4 million at September 30, 2013 and December 31, 2012, respectively.

Derivative Assets And Liabilities

Derivative Assets and Liabilities

Fair Value Measurements

Regulatory Deferred Charges And Credits

Regulatory Deferred Charges and Credits

The Company prepares its condensed consolidated financial statements in accordance with regulatory accounting practices because:


•	rates for regulated services are established by or subject to approval by independent third-party regulators,


•	the regulated rates are designed to recover the cost of providing the regulated services, and


•	in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover costs.


•	required to write off its regulatory assets, and


•	precluded from the future deferral of costs not recovered through rates at the time such costs are incurred, even if the Company expected to recover such costs in the future.

Contingencies

Correction of an Immaterial Error and Reclassifications

Reclassifications

Accumulated Other Comprehensive Loss [Policy Text Block]

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, net of tax, consisted of the following as of September 30, 2013 and December 31, 2012 (dollars in thousands):



	September 30,			December 31,
	2013			2012
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $(3,401) and $(3,698), respectively	$	(6,316	)	$	(6,867	)
Unrealized gain (loss) on securities available for sale - net of taxes of $(904) and $97, respectively	(1,532		)	167
Total accumulated other comprehensive loss	$	(7,848	)	$	(6,700	)

The following table details the reclassifications out of accumulated other comprehensive loss by component for the three and nine months ended September 30, 2013 (dollars in thousands):



	Amounts Reclassified from Accumulated Other Comprehensive Loss
Details about Accumulated Other Comprehensive Loss Components	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013			Affected Line Item in Statement of Income
Realized gains on investment securities	$	2		$	20		Other income-net
	2			20			Total before tax
	(1		)	(8		)	Tax expense
	$	1		$	12		Net of tax
Amortization of defined benefit pension items
Amortization of net loss	$	(4,891	)	$	(14,673	)	(a)
Adjustment due to effects of regulation	4,608			13,825			(a)
	(283		)	(848		)	Total before tax
	99			297			Tax benefit
	$	(184	)	$	(551	)	Net of tax


(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 6 for additional details).

Restructuring and Related Activities Disclosure [Text Block]

Voluntary Severance Incentive Program

Summary Of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive loss, net of tax, consisted of the following as of September 30, 2013 and December 31, 2012 (dollars in thousands):



	September 30,			December 31,
	2013			2012
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $(3,401) and $(3,698), respectively	$	(6,316	)	$	(6,867	)
Unrealized gain (loss) on securities available for sale - net of taxes of $(904) and $97, respectively	(1,532		)	167
Total accumulated other comprehensive loss	$	(7,848	)	$	(6,700	)

Reclassifications Out of Accumulated Other Comprehensive Loss by Component

The following table details the reclassifications out of accumulated other comprehensive loss by component for the three and nine months ended September 30, 2013 (dollars in thousands):



	Amounts Reclassified from Accumulated Other Comprehensive Loss
Details about Accumulated Other Comprehensive Loss Components	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013			Affected Line Item in Statement of Income
Realized gains on investment securities	$	2		$	20		Other income-net
	2			20			Total before tax
	(1		)	(8		)	Tax expense
	$	1		$	12		Net of tax
Amortization of defined benefit pension items
Amortization of net loss	$	(4,891	)	$	(14,673	)	(a)
Adjustment due to effects of regulation	4,608			13,825			(a)
	(283		)	(848		)	Total before tax
	99			297			Tax benefit
	$	(184	)	$	(551	)	Net of tax


(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 6 for additional details).

Utility Taxes

Utility related taxes collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled the following amounts for the three and nine months ended September 30 (dollars in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Utility taxes	$	10,901	$	10,741	$	41,045	$	41,353

Other Income - Net

Other (Income)/Expense-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,
	2013			2012			2013			2012
Interest income	$	(124	)	$	(166	)	$	(620	)	$	(804	)
Interest income on regulatory deferrals	(27		)	(19		)	(48		)	(43		)
Equity-related AFUDC	(1,595		)	(1,127		)	(4,341		)	(2,875		)
Net loss on investments	1,299			2,430			1,543			2,957
Other income	(537		)	(700		)	(2,099		)	(2,127		)
Total	$	(984	)	$	418		$	(5,565	)	$	(2,892	)

Materials And Supplies Fuel Stock And Natural Gas Stored



	September 30,		December 31,
	2013		2012
Materials and supplies	$	29,334	$	26,058
Fuel stock	3,750		4,121
Natural gas stored	23,759		17,276
Total	$	56,843	$	47,455

Investments And Funds Held For Clients

Investments and funds held for clients as of September 30, 2013 are as follows (dollars in thousands):



	Amortized Cost (1)		Unrealized Gain (Loss)			Fair Value
Cash and cash equivalents	$	14,155	$	—		$	14,155
Money market funds	3,238		—			3,238
Securities available for sale:
U.S. government agency	68,631		(2,466		)	66,165
Municipal	3,529		13			3,542
Corporate fixed income – financial	3,000		4			3,004
Corporate fixed income – industrial	1,753		13			1,766
Certificates of deposit	1,000		—			1,000
Total securities available for sale	77,913		(2,436		)	75,477
Total investments and funds held for clients	$	95,306	$	(2,436	)	$	92,870

Investments and funds held for clients as of December 31, 2012 are as follows (dollars in thousands):



	Amortized Cost (1)		Unrealized Gain (Loss)		Fair Value
Cash and cash equivalents	$	13,867	$	—	$	13,867
Money market funds	15,084		—		15,084
Securities available for sale:
U.S. government agency	48,340		156		48,496
Municipal	820		28		848
Corporate fixed income – financial	5,010		16		5,026
Corporate fixed income – industrial	3,887		49		3,936
Certificates of deposit	1,000		15		1,015
Total securities available for sale	59,057		264		59,321
Total investments and funds held for clients	$	88,008	$	264	$	88,272


(1)	Amortized cost represents the original purchase price of the investments, plus or minus any amortized purchase premiums or accreted purchase discounts.

Contractual Maturities Of Securities Available For Sale

Contractual maturities of securities available for sale as of September 30, 2013 and December 31, 2012 are as follows (dollars in thousands):



	Due within 1 year		After 1 but within 5 years		After 5 but within 10 years		After 10 years		Total
September 30, 2013	$	5,655	$	18,479	$	48,437	$	2,906	$	75,477
December 31, 2012	3,047		11,786		41,485		3,003		59,321

Goodwill

The changes in the carrying amount of goodwill are as follows (dollars in thousands):



	Ecova		Other		Accumulated Impairment Losses			Total
Balance as of December 31, 2012	$	70,713	$	12,979	$	(7,733	)	$	75,959
Adjustments	803		—		—			803
Balance as of September 30, 2013	$	71,516	$	12,979	$	(7,733	)	$	76,762

Other Intangible Amortization

Amortization expense related to Intangible Assets was as follows for the three and nine months ended September 30 (dollars in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Intangible asset amortization	$	2,765	$	2,436	$	8,442	$	7,091

Future Estimated Amortization Expense

The following table details the estimated amortization expense related to Intangible Assets for each of the five years ending December 31 (dollars in thousands):



	Remaining
	2013		2014		2015		2016		2017
Estimated amortization expense	$	2,292	$	10,460	$	8,484	$	7,359	$	6,516

Accumulated Amortization Of Other Intangibles

The gross carrying amount and accumulated amortization of Intangible Assets as of September 30, 2013 and December 31, 2012 are as follows (dollars in thousands):



	Estimated	September 30,			December 31,
	Useful Lives	2013			2012
Client backlog and relationships	2 - 12 years	$	33,559		$	32,059
Software development costs	3 - 7 years	38,148			33,990
Other	1 - 10 years	3,332			6,237
Total intangible assets		75,039			72,286
Client relationships accumulated amortization		(11,255		)	(7,793		)
Software development costs accumulated amortization		(20,383		)	(16,557		)
Other accumulated amortization		(2,248		)	(1,680		)
Total accumulated amortization		(33,886		)	(26,030		)
Total intangible assets - net		$	41,153		$	46,256

Disposition of Available-for-Sale Securities

The following is a summary of the disposition of available-for-sale securities for the three and nine months ended September 30 (dollars in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Proceeds from sales, maturities and calls	$	1,825	$	32,053	$	16,955	$	103,545
Gross realized gains	2		111		20		252
Gross realized losses	—		—		—		—

Redeemable Noncontrolling Interests And Subsidiary Acquisitions (Tables)

9 Months Ended

Sep. 30, 2013

Business Combinations [Abstract]

Redeemable Noncontrolling Interests



	September 30,		December 31,
	2013		2012
Stock options and other outstanding redeemable stock	$	8,330	$	4,938

Derivatives And Risk Management (Tables)

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedges, Assets [Abstract]

Energy Commodity Derivatives



	Purchases				Sales
	Electric Derivatives		Gas Derivatives		Electric Derivatives		Gas Derivatives
Year	Physical (1) MWH	Financial (1) MWH	Physical (1) mmBTUs	Financial (1) mmBTUs	Physical MWH	Financial MWH	Physical mmBTUs	Financial mmBTUs
2013	385	997	11,576	36,932	230	1,123	906	26,934
2014	702	1,942	22,613	115,004	345	2,839	1,786	84,108
2015	379	1,013	4,523	72,320	254	2,542	—	46,840
2016	367	—	2,505	38,210	287	1,634	—	13,380
2017	366	—	675	—	286	—	—	—
Thereafter	583	—	—	—	443	—	—	—


(1)	Physical transactions represent commodity transactions where Avista Utilities will take delivery of either electricity or natural gas and financial transactions represent derivative instruments with no physical delivery, such as futures, swaps or options.

Foreign Currency Exchange Contracts



	September 30,		December 31,
	2013		2012
Number of contracts	14		20
Notional amount (in United States dollars)	$	1,852	$	12,621
Notional amount (in Canadian dollars)	1,929		12,502

Interest Rate Swap Agreements



Balance Sheet Date	Number of Contracts	Notional Amount		Mandatory Cash Settlement Date
September 30, 2013	2	$	50,000	October 2014
	2	45,000		October 2015
	1	20,000		October 2016
	2	50,000		June 2018
December 31, 2012	2	85,000		June 2013
	2	50,000		October 2014
	1	25,000		October 2015

Derivative Instruments Summary



		Fair Value
Derivative	Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netting		Net Asset (Liability) in Balance Sheet			Gross Assets Not Offset		Gross Liabilities Not Offset		Net Asset (Liability)
Foreign currency contracts	Other current assets	$	19	$	(1	)	$	—	$	18		$	—	$	—	$	18
Interest rate contracts	Other non-current liabilities and deferred credits	—		(471		)	—		(471		)	—		—		(471		)
Interest rate contracts	Other property and investments - net	25,178		—			—		25,178			—		—		25,178
Commodity contracts (1)	Current utility energy commodity derivative assets	4,078		(648		)	—		3,430			—		—		3,430
Commodity contracts (1)	Non-current utility energy commodity derivative assets	7,191		(6,898		)	—		293			—		—		293
Commodity contracts (1)	Current utility energy commodity derivative liabilities	34,858		(58,687		)	5,121		(18,708		)	—		—		(18,708		)
Commodity contracts (1)	Other non-current liabilities and deferred credits	23,274		(48,296		)	5,292		(19,730		)	—		—		(19,730		)
Total derivative instruments recorded on the balance sheet		$	94,598	$	(115,001	)	$	10,413	$	(9,990	)	$	—	$	—	$	(9,990	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2012 (in thousands):



		Fair Value
Derivative	Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netting		Net Asset (Liability) in Balance Sheet			Gross Assets Not Offset			Gross Liabilities Not Offset			Net Asset (Liability)
Foreign currency contracts	Other current liabilities	$	7	$	(34	)	$	—	$	(27	)	$	—		$	—		$	(27	)
Interest rate contracts	Other current liabilities	—		(1,406		)	—		(1,406		)	—			—			(1,406		)
Interest rate contracts	Other property and investments - net	7,265		—			—		7,265			—			—			7,265
Commodity contracts (1)	Current utility energy commodity derivative assets	10,772		(6,633		)	—		4,139			(9,678		)	6,572			1,033
Commodity contracts (1)	Non-current utility energy commodity derivative assets	18,779		(17,686		)	—		1,093			—			—			1,093
Commodity contracts (1)	Current utility energy commodity derivative liabilities	50,227		(89,449		)	9,707		(29,515		)	9,678			(6,572		)	(26,409		)
Commodity contracts (1)	Other non-current liabilities and deferred credits	2,247		(28,558		)	—		(26,311		)	—			—			(26,311		)
Total derivative instruments recorded on the balance sheet		$	89,297	$	(143,766	)	$	9,707	$	(44,762	)	$	—		$	—		$	(44,762	)

(1)

Pension Plans And Other Postretirement Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2013

Components of Net Periodic Benefit Cost



	Pension Benefits						Other Post-retirement Benefits
	2013			2012			2013			2012
Three months ended September 30:
Service cost	$	4,743		$	3,891		$	971		$	689
Interest cost	5,978			6,084			1,373			1,256
Expected return on plan assets	(6,900		)	(5,950		)	(402		)	(375		)
Transition obligation recognition	—			—			—			125
Amortization of prior service cost	75			75			(37		)	(37		)
Net loss recognition	3,220			3,019			1,395			1,250
Net periodic benefit cost	$	7,116		$	7,119		$	3,300		$	2,908
Nine months ended September 30:
Service cost	$	14,229		$	11,573		$	3,035		$	2,067
Interest cost	17,934			18,277			4,153			3,793
Expected return on plan assets	(20,700		)	(17,900		)	(1,202		)	(1,125		)
Transition obligation recognition	—			—			—			375
Amortization of prior service cost	225			225			(111		)	(111		)
Net loss recognition	9,989			8,797			4,342			3,814
Net periodic benefit cost	$	21,677		$	20,972		$	10,217		$	8,813

Committed Lines of Credit (Tables)

9 Months Ended

Sep. 30, 2013

Schedule Of Borrowings Outstanding And Letters Of Credit



	September 30,			December 31,
	2013			2012
Borrowings outstanding at end of period	$	66,000		$	52,000
Letters of credit outstanding at end of period	$	27,994		$	35,885
Average interest rate on borrowings at end of period	1.10		%	1.12		%

Ecova [Member]

Schedule Of Borrowings Outstanding And Letters Of Credit



	September 30,			December 31,
	2013			2012
Borrowings outstanding at end of period	$	50,000		$	54,000
Average interest rate on borrowings at end of period	2.19		%	2.21		%

Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2013

Long-term Debt, Unclassified [Abstract]

Long-term Debt Outstanding



Maturity		Interest	September 30,			December 31,
Year	Description	Rate	2013			2012
2013	First Mortgage Bonds	1.68%	$	50,000		$	50,000
2016	First Mortgage Bonds	0.84%	90,000			—
2018	First Mortgage Bonds	5.95%	250,000			250,000
2018	Secured Medium-Term Notes	7.39%-7.45%	22,500			22,500
2019	First Mortgage Bonds	5.45%	90,000			90,000
2020	First Mortgage Bonds	3.89%	52,000			52,000
2022	First Mortgage Bonds	5.13%	250,000			250,000
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	Secured Pollution Control Bonds (1)	(1)	66,700			66,700
2034	Secured Pollution Control Bonds (2)	(2)	17,000			17,000
2035	First Mortgage Bonds	6.25%	150,000			150,000
2037	First Mortgage Bonds	5.70%	150,000			150,000
2040	First Mortgage Bonds	5.55%	35,000			35,000
2041	First Mortgage Bonds	4.45%	85,000			85,000
2047	First Mortgage Bonds	4.23%	80,000			80,000
	Total secured long-term debt		1,426,700			1,336,700
	Other long-term debt and capital leases		4,680			5,092
	Settled interest rate swaps (3)		(23,760		)	(27,900		)
	Unamortized debt discount		(1,330		)	(1,453		)
	Total		1,406,290			1,312,439
	Secured Pollution Control Bonds held by Avista Corporation (1) (2)		(83,700		)	(83,700		)
	Current portion of long-term debt		(50,330		)	(50,372		)
	Total long-term debt		$	1,272,260		$	1,178,367

(1)

(2)


(3)	Upon settlement of interest rate swaps, these are recorded as a regulatory asset or liability and included as part of long-term debt above. They are amortized as a component of interest expense over the life of the associated debt and included as a part of the Company's cost of debt calculation for ratemaking purposes.

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6584090&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

+ Details

Fair Value (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Inputs, Liabilities, Quantitative Information [Line Items]

Fair Value Inputs, Liabilities, Quantitative Information [Table Text Block]



	Fair Value (Net) at
	September 30, 2013			Valuation Technique	Unobservable Input	Range
Power exchange agreement	$	(16,044	)	Surrogate facility pricing	O&M charges	$30.18-$53.90/MWh (1)
					Escalation factor	3% - 2014 to 2019
					Transaction volumes	365,619 - 394,255 MWhs
Power option agreement	(761		)	Black-Scholes- Merton	Strike price	$55.53/MWh - 2015
					Strike price	$69.60/MWh - 2019
					Delivery volumes	157,517 - 287,147 MWhs
					Volatility rates	0.20 (2)
Natural gas exchange agreement	(1,193		)	Internally derived weighted average cost of gas	Forward purchase prices	(3)
					Forward purchase prices	(3)
					Forward sales prices	$3.64 - $4.19/mmBTU
					Purchase volumes	(3)
					Sales volumes	139,980 - 310,000 mmBTUs

Carrying Value and Estimated Fair Value of Financial Instruments



	September 30, 2013				December 31, 2012
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	951,000	$	1,083,214	$	951,000	$	1,164,639
Long-term debt (Level 3)	392,000		382,426		302,000		320,892
Nonrecourse long-term debt (Level 3)	21,688		22,875		32,803		35,297
Long-term debt to affiliated trusts (Level 3)	51,547		36,861		51,547		43,686

Fair Value of Assets And Liabilities Measured on Recurring Basis



	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
September 30, 2013
Assets:
Energy commodity derivatives	$	—	$	69,334	$	—	$	(65,611	)	$	3,723
Level 3 energy commodity derivatives:
Power exchange agreement	—		—		67		(67		)	—
Foreign currency derivatives	—		19		—		—			19
Interest rate swaps	—		25,178		—		—			25,178
Investments and funds held for clients:
Money market funds	3,238		—		—		—			3,238
Securities available for sale:
U.S. government agency	—		66,165		—		—			66,165
Municipal	—		3,542		—		—			3,542
Corporate fixed income – financial	—		3,004		—		—			3,004
Corporate fixed income – industrial	—		1,766		—		—			1,766
Certificate of deposits	—		1,000		—		—			1,000
Funds held in trust account of Spokane Energy	1,600		—		—		—			1,600
Deferred compensation assets:
Fixed income securities (2)	1,829		—		—		—			1,829
Equity securities (2)	6,213		—		—		—			6,213
Total	$	12,880	$	170,008	$	67	$	(65,678	)	$	117,277
Liabilities:
Energy commodity derivatives	$	—	$	96,464	$	—	$	(76,024	)	$	20,440
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		1,193		—			1,193
Power exchange agreement	—		—		16,111		(67		)	16,044
Power option agreement	—		—		761		—			761
Foreign currency derivatives	—		1		—		—			1
Interest rate swaps	—		471		—		—			471
Total	$	—	$	96,936	$	18,065	$	(76,091	)	$	38,910



	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
December 31, 2012
Assets:
Energy commodity derivatives	$	—	$	81,640	$	—	$	(76,408	)	$	5,232
Level 3 energy commodity derivatives:
Power exchange agreement	—		—		385		(385		)	—
Foreign currency derivatives	—		7		—		(7		)	—
Interest rate swaps	—		7,265		—		—			7,265
Investments and funds held for clients:
Money market funds	15,084		—		—		—			15,084
Securities available for sale:
U.S. government agency	—		48,496		—		—			48,496
Municipal	—		848		—		—			848
Corporate fixed income – financial	—		5,026		—		—			5,026
Corporate fixed income – industrial	—		3,936		—		—			3,936
Certificate of deposits	—		1,015		—		—			1,015
Funds held in trust account of Spokane Energy	1,600		—		—		—			1,600
Deferred compensation assets:
Fixed income securities (2)	2,010		—		—		—			2,010
Equity securities (2)	5,955		—		—		—			5,955
Total	$	24,649	$	148,233	$	385	$	(76,800	)	$	96,467
Liabilities:
Energy commodity derivatives	$	—	$	119,390	$	—	$	(86,115	)	$	33,275
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		2,379		—			2,379
Power exchange agreement	—		—		19,077		(385		)	18,692
Power option agreement	—		—		1,480		—			1,480
Foreign currency derivatives	—		34		—		(7		)	27
Interest rate swaps	—		1,406		—		—			1,406
Total	$	—	$	120,830	$	22,936	$	(86,507	)	$	57,259


(1)	The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.


(2)	These assets are trading securities and are included in other property and investments-net on the Condensed Consolidated Balance Sheets.

Reconciliation for All Assets Measured At Fair Value on a Recurring Basis Using Significant Unobservable Inputs (Level 3)



	Natural Gas Exchange Agreement			Power Exchange Agreement			Power Option Agreement			Total
Three months ended September 30, 2013:
Balance as of July 1, 2013	$	(1,022	)	$	(22,179	)	$	(596	)	$	(23,797	)
Total gains or losses (realized/unrealized):
Included in net income	—			—			—			—
Included in other comprehensive income	—			—			—			—
Included in regulatory assets/liabilities (1)	(170		)	6,135			(165		)	5,800
Purchases	—			—			—			—
Issuance	—			—			—			—
Settlements	(1		)	—			—			(1		)
Transfers to/from other categories	—			—			—			—
Ending balance as of September 30, 2013	$	(1,193	)	$	(16,044	)	$	(761	)	$	(17,998	)



	Natural Gas Exchange Agreement			Power Exchange Agreement			Power Option Agreement			Total
Three months ended September 30, 2012:
Balance as of July 1, 2012	$	(2,727	)	$	(10,438	)	$	(1,756	)	$	(14,921	)
Total gains or losses (realized/unrealized):
Included in net income	—			—			—			—
Included in other comprehensive income	—			—			—			—
Included in regulatory assets/liabilities (1)	(377		)	(7,438		)	171			(7,644		)
Purchases	—			—			—			—
Issuance	—			—			—			—
Settlements	(1		)	—			—			(1		)
Transfers to/from other categories	—			—			—			—
Ending balance as of September 30, 2012	$	(3,105	)	$	(17,876	)	$	(1,585	)	$	(22,566	)
Nine months ended September 30, 2013:
Balance as of January 1, 2013	$	(2,379	)	$	(18,692	)	$	(1,480	)	$	(22,551	)
Total gains or losses (realized/unrealized):
Included in net income	—			—			—			—
Included in other comprehensive income	—			—			—			—
Included in regulatory assets/liabilities (1)	1,637			(113		)	719			2,243
Purchases	—			—			—			—
Issuance	—			—			—			—
Settlements	(451		)	2,761			—			2,310
Transfers to/from other categories	—			—			—			—
Ending balance as of September 30, 2013	$	(1,193	)	$	(16,044	)	$	(761	)	$	(17,998	)
Nine months ended September 30, 2012:
Balance as of January 1, 2012	$	(1,688	)	$	(9,910	)	$	(1,260	)	$	(12,858	)
Total gains or losses (realized/unrealized):
Included in net income	—			—			—			—
Included in other comprehensive income	—			—			—			—
Included in regulatory assets/liabilities (1)	(364		)	(12,216		)	(325		)	(12,905		)
Purchases	—			—			—			—
Issuance	—			—			—			—
Settlements	(1,053		)	4,250			—			3,197
Transfers from other categories	—			—			—			—
Ending balance as of September 30, 2012	$	(3,105	)	$	(17,876	)	$	(1,585	)	$	(22,566	)

(1)

Earnings Per Common Share Attributable To Avista Corporation (Tables)

9 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Computations Of Earnings Per Share



	Three months ended						Nine months ended
	September 30,						September 30,
	2013			2012			2013			2012
Numerator:
Net income attributable to Avista Corporation shareholders	$	11,413		$	5,786		$	79,411		$	62,352
Subsidiary earnings adjustment for dilutive securities	(81		)	(16		)	(163		)	(25		)
Adjusted net income attributable to Avista Corporation shareholders for computation of diluted earnings per common share	$	11,332		$	5,770		$	79,248		$	62,327
Denominator:
Weighted-average number of common shares outstanding-basic	59,994			59,047			59,933			58,778
Effect of dilutive securities:
Performance and restricted stock awards	38			71			31			234
Stock options	—			5			—			14
Weighted-average number of common shares outstanding-diluted	60,032			59,123			59,964			59,026
Earnings per common share attributable to Avista Corporation shareholders:
Basic	$	0.19		$	0.10		$	1.32		$	1.06
Diluted	$	0.19		$	0.10		$	1.32		$	1.06

Information By Business Segments (Tables)

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Information by Business Segments

The following table presents information for each of the Company’s business segments (dollars in thousands):



	Avista Utilities		Ecova		Other			Total Non-Utility			Intersegment Eliminations (1)			Total
For the three months ended September 30, 2013:
Operating revenues	$	278,923	$	46,398	$	11,004		$	57,402		$	(450	)	$	335,875
Resource costs	131,136		—		—			—			—			131,136
Other operating expenses	69,596		37,047		10,662			47,709			(450		)	116,855
Depreciation and amortization	29,823		3,909		171			4,080			—			33,903
Income from operations	29,657		5,442		170			5,612			—			35,269
Interest expense (2)	18,837		398		525			923			(77		)	19,683
Income taxes	3,945		2,092		(578		)	1,514			—			5,459
Net income (loss) attributable to Avista Corporation shareholders	9,447		3,040		(1,074		)	1,966			—			11,413
Capital expenditures	75,368		357		24			381			—			75,749
For the three months ended September 30, 2012:
Operating revenues	$	292,535	$	38,617	$	9,930		$	48,547		$	(450	)	$	340,632
Resource costs	153,801		—		—			—			—			153,801
Other operating expenses	66,456		33,868		10,581			44,449			(450		)	110,455
Depreciation and amortization	28,255		3,260		131			3,391			—			31,646
Income from operations	25,901		1,489		(782		)	707			—			26,608
Interest expense (2)	18,001		530		824			1,354			(91		)	19,264
Income taxes	2,590		495		(1,477		)	(982		)	—			1,608
Net income (loss) attributable to Avista Corporation shareholders	7,660		640		(2,514		)	(1,874		)	—			5,786
Capital expenditures	57,964		1,023		619			1,642			—			59,606
For the nine months ended September 30, 2013:
Operating revenues	$	1,008,669	$	133,365	$	30,145		$	163,510		$	(1,350	)	$	1,170,829
Resource costs	487,277		—		—			—			—			487,277
Other operating expenses	200,824		110,753		30,322			141,075			(1,350		)	340,549
Depreciation and amortization	86,783		11,474		536			12,010			—			98,793
Income from operations	167,648		11,138		(713		)	10,425			—			178,073
Interest expense (2)	56,635		1,265		1,801			3,066			(230		)	59,471
Income taxes	43,278		4,178		(1,349		)	2,829			—			46,107
Net income (loss) attributable to Avista Corporation shareholders	76,265		5,759		(2,613		)	3,146			—			79,411
Capital expenditures	220,712		1,586		139			1,725			—			222,437
For the nine months ended September 30, 2012:
Operating revenues	$	992,210	$	115,707	$	29,907		$	145,614		$	(1,350	)	$	1,136,474
Resource costs	500,805		—		—			—			—			500,805
Other operating expenses	196,759		104,392		29,830			134,222			(1,350		)	329,631
Depreciation and amortization	83,327		9,455		511			9,966			—			93,293
Income from operations	147,596		1,860		(434		)	1,426			—			149,022
Interest expense (2)	54,148		1,301		2,691			3,992			(274		)	57,866
Income taxes	34,425		918		(2,237		)	(1,319		)	—			33,106
Net income (loss) attributable to Avista Corporation shareholders	65,157		962		(3,767		)	(2,805		)	—			62,352
Capital expenditures	178,440		3,248		660			3,908			—			182,348
Total Assets:
As of September 30, 2013:	$	3,961,718	$	353,128	$	87,156		$	440,284		$	—		$	4,402,002
As of December 31, 2012:	$	3,894,821	$	322,720	$	95,638		$	418,358		$	—		$	4,313,179


(1)	Intersegment eliminations reported as operating revenues and resource costs represent intercompany purchases and sales of electric capacity and energy. Intersegment eliminations reported as interest expense represent intercompany interest.


(2)	Including interest expense to affiliated trusts.

Summary Of Significant Accounting Policies (Narrative) (Details) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2013 USD ($)	Sep. 30, 2012 USD ($)	Sep. 30, 2013 USD ($)	Sep. 30, 2012 USD ($)	Dec. 31, 2012 USD ($)
Summary Of Significant Accounting Policies [Line Items]
Quantifying Misstatement in Current Year Financial Statements, Amount		$ 3,400		$ 8,000
Investment portfolio percentage rated AA or higher			95.00%		97.00%
Sale and maturity of securities available for sale	$ 1,825	32,053	$ 16,955	103,545
Ecova [Member]
Summary Of Significant Accounting Policies [Line Items]
Owners percentage interest	78.90%		78.90%
Employee Severance [Member]
Summary Of Significant Accounting Policies [Line Items]
Severance costs					$ 7,300
Restructuring number of positions eliminated					55
Other Intangible Assets [Member] \| Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Finite-Lived Intangible Asset, Useful Life			1 year
Other Intangible Assets [Member] \| Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Finite-Lived Intangible Asset, Useful Life			10 years
Software and Software Development Costs [Member] \| Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Finite-Lived Intangible Asset, Useful Life			3 years
Software and Software Development Costs [Member] \| Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Finite-Lived Intangible Asset, Useful Life			7 years
Customer Relationships [Member] \| Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Finite-Lived Intangible Asset, Useful Life			2 years
Customer Relationships [Member] \| Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Finite-Lived Intangible Asset, Useful Life			12 years
Other operating expenses [Member] \| Avista Utilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Quantifying Misstatement in Current Year Financial Statements, Amount		2,000		5,400
Other operating expenses [Member] \| Other Business Segment [Member]
Summary Of Significant Accounting Policies [Line Items]
Quantifying Misstatement in Current Year Financial Statements, Amount		1,400		2,500
Utility operating expenses, taxes [Member] \| Avista Utilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Quantifying Misstatement in Current Year Financial Statements, Amount		$ 0		$ 100

Summary Of Significant Accounting Policies (Utility Taxes) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Accounting Policies [Abstract]
Utility taxes	$ 10,901	$ 10,741	$ 41,045	$ 41,353

Summary Of Significant Accounting Policies (Other Income - Net) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Accounting Policies [Abstract]
Interest income	$ (124)	$ (166)	$ (620)	$ (804)
Interest on regulatory deferrals	(27)	(19)	(48)	(43)
Equity-related AFUDC	(1,595)	(1,127)	(4,341)	(2,875)
Net loss on investments	1,299	2,430	1,543	2,957
Other income	(537)	(700)	(2,099)	(2,127)
Total	$ (984)	$ 418	$ (5,565)	$ (2,892)

- Definition

This item represents the net total realized and unrealized gain (loss) included in earnings for the period as a result of selling or holding marketable securities categorized as trading, available-for-sale, or held-to-maturity, including the unrealized holding gain (loss) of held-to-maturity securities transferred to the trading security category and the cumulative unrealized gain (loss) which was included in other comprehensive income (a separate component of shareholders' equity) for available-for-sale securities transferred to trading securities during the period. Additionally, this item would include any gains (losses) realized during the period from the sale of investments accounted for under the cost method of accounting and losses recognized for other than temporary impairments (OTTI) of the subject investments.

+ References + Details

Summary Of Significant Accounting Policies (Materials And Supplies Fuel Stock And Natural Gas Stored) (Details) - USD ($) $ in Thousands	Sep. 30, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Materials and supplies	$ 29,334	$ 26,058
Fuel stock	3,750	4,121
Natural gas stored	23,759	17,276
Total	$ 56,843	$ 47,455

Summary Of Significant Accounting Policies (Investments And Funds Held For Customers) (Details) - USD ($)
$ in Thousands

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Schedule of Available-for-sale Securities [Line Items]

Available for Sale Securities Debt Effective Maturity

3 years 1 month 6 days

Proceeds from Sale of Available-for-sale Securities

$ 1,825

$ 32,053

$ 16,955

$ 103,545

Cash and Cash Equivalents, Amortized Cost

^[1]

14,155

$ 13,867

Cash And Cash Equivalents Unrealized Gain Loss

Money market funds

14,155

13,867

Money market funds, Amortized Cost

^[1]

15,084

Money Market Funds, Unrealized Gain Loss

Total securities available for sale, Amortized Cost

^[1]

77,913

59,057

Total securities available for sale, Unrealized Gain (Loss)

(2,436)

264

Total securities available for sale, Fair Value

75,477

59,321

Total investments and funds held for clients, Amortized Cost

^[1]

95,306

88,008

Total investments and funds held for clients, Unrealized Gain (Loss)

(2,436)

264

Total investments and funds held for clients, fair value

92,870

88,272

U.S. Government Agency [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Amortized Cost

^[1]

68,631

48,340

Total securities available for sale, Unrealized Gain (Loss)

(2,466)

156

Municipal [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Amortized Cost

^[1]

3,529

820

Total securities available for sale, Unrealized Gain (Loss)

Corporate fixed income - financial [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Amortized Cost

^[1]

3,000

5,010

Total securities available for sale, Unrealized Gain (Loss)

Corporate fixed income - industrial [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Amortized Cost

^[1]

1,753

3,887

Total securities available for sale, Unrealized Gain (Loss)

Certificates of deposits [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Amortized Cost

^[1]

1,000

Total securities available for sale, Unrealized Gain (Loss)

Fair Value, Measurements, Recurring [Member]

Schedule of Available-for-sale Securities [Line Items]

Money Market Funds, Fair Value

3,238

15,084

Fair Value, Measurements, Recurring [Member] | U.S. Government Agency [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Fair Value

66,165

48,496

Fair Value, Measurements, Recurring [Member] | Municipal [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Fair Value

3,542

848

Fair Value, Measurements, Recurring [Member] | Corporate fixed income - financial [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Fair Value

3,004

5,026

Fair Value, Measurements, Recurring [Member] | Corporate fixed income - industrial [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Fair Value

1,766

3,936

Fair Value, Measurements, Recurring [Member] | Certificates of deposits [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Fair Value

1,000

1,015

Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring [Member]

Schedule of Available-for-sale Securities [Line Items]

Money Market Funds, Fair Value

3,238

15,084

Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Government Agency [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Fair Value

66,165

48,496

Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Municipal [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Fair Value

3,542

848

Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Corporate fixed income - financial [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Fair Value

3,004

5,026

Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Corporate fixed income - industrial [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Fair Value

1,766

3,936

Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Certificates of deposits [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Fair Value

$ 1,000

$ 1,015

[1]	(1) Amortized cost represents the original purchase price of the investments, plus or minus any amortized purchase premiums or accreted purchase discounts.

Summary Of Significant Accounting Policies (Contractual Maturities Of Securities Available For Sale) (Details) - USD ($) $ in Thousands	Sep. 30, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Due within 1 year	$ 5,655	$ 3,047
After 1 but within 5 years	18,479	11,786
After 5 but within 10 years	48,437	41,485
After 10 years	2,906	3,003
Total securities available for sale, Fair Value	$ 75,477	$ 59,321

Summary Of Significant Accounting Policies (Goodwill) (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2013 USD ($)
Balance at beginning	$ 75,959
Adjustments	803
Balance at ending	76,762
Ecova [Member]
Balance at beginning	70,713
Adjustments	803
Balance at ending	71,516
Other [Member]
Balance at beginning	12,979
Adjustments	0
Balance at ending	12,979
Accumulated Impairment Losses [Member]
Balance at beginning	(7,733)
Adjustments	0
Balance at ending	$ (7,733)

Summary Of Significant Accounting Policies (Other Intangible Amortization) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Accounting Policies [Abstract]
Intangible asset amortization	$ 2,765	$ 2,436	$ 8,442	$ 7,091

Summary Of Significant Accounting Policies (Future Estimated Amortization Expense) (Details) $ in Thousands	Sep. 30, 2013 USD ($)
Accounting Policies [Abstract]
2013	$ 2,292
2014	10,460
2015	8,484
2016	7,359
2017	$ 6,516

Summary Of Significant Accounting Policies (Accumulated Amortization Of Other Intangibles) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Finite-Lived Intangible Assets [Line Items]
Client relationships	$ 33,559	$ 32,059
Software development costs	38,148	33,990
Other	3,332	6,237
Total intangible assets	75,039	72,286
Total accumulated amortization	(33,886)	(26,030)
Total intangible assets - net	41,153	46,256
Ecova [Member]
Finite-Lived Intangible Assets [Line Items]
Total intangible assets - net	40,400	45,400
Other Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Total accumulated amortization	(2,248)	(1,680)
Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Total accumulated amortization	(11,255)	(7,793)
Software and Software Development Costs [Member]
Finite-Lived Intangible Assets [Line Items]
Total accumulated amortization	$ (20,383)	$ (16,557)
Minimum [Member] \| Other Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life	1 year
Minimum [Member] \| Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life	2 years
Minimum [Member] \| Software and Software Development Costs [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life	3 years

Summary Of Significant Accounting Policies (Accumulated Other Comprehensive Loss) (Details) - USD ($)
$ in Thousands

3 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Reclassification Out of Accumulated Other Comprehensive Income [Line Items]

Other income-net

$ 537

$ 700

$ 2,099

$ 2,127

Tax expense

(5,459)

(1,608)

(46,107)

(33,106)

Net of tax

11,931

$ 5,962

80,762

$ 62,707

Reclassification Out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]

Reclassification Out of Accumulated Other Comprehensive Income [Line Items]

Other income-net

Total before tax

Tax expense

(1)

(8)

Net of tax

Reclassification Out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]

Reclassification Out of Accumulated Other Comprehensive Income [Line Items]

Total before tax

(283)

(848)

Tax expense

297

Net of tax

(184)

(551)

Amortization of net loss

^[1]

(4,891)

(14,673)

Adjustment due to effects of regulation

^[1]

$ 4,608

$ 13,825

[1]	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 6 for additional details).

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Voluntary Severance Incentive Program) (Details) - Employee Severance [Member] $ in Millions	12 Months Ended
	Dec. 31, 2012 USD ($)
Severance Costs	$ 7.3
Restructuring and Related Cost, Number of Positions Eliminated	55

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Thousands	Sep. 30, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities, Tax	$ (904)	$ 97
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans Net Unamortized (Gain) Loss, Tax	(3,401)	(3,698)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	6,316	6,867
Accumulated Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	(1,532)	167
Accumulated other comprehensive loss	$ (7,848)	$ (6,700)

- Definition

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

+ References + Details

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Disposition of Available-for-Sale Securities) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Disposition of Available for Sale Securities [Abstract]
Proceeds from Sale of Available-for-sale Securities	$ 1,825	$ 32,053	$ 16,955	$ 103,545
Available-for-sale Securities, Gross Realized Gains	2	111	20	252
Available-for-sale Securities, Gross Realized Losses	$ 0	$ 0	$ 0	$ 0

Variable Interest Entities (Details) $ in Thousands	3 Months Ended		9 Months Ended
Variable Interest Entities (Details) $ in Thousands	Sep. 30, 2013 USD ($)	Sep. 30, 2012 USD ($)	Sep. 30, 2013 USD ($) MW	Sep. 30, 2012 USD ($)
Operating revenues \| $	$ 335,875	$ 340,632	$ 1,170,829	$ 1,136,474
Lancaster Power Purchase Agreement [Member]
Evaluated power capacity, megawatts \| MW			270
Future contractual obligation \| $	303,000		$ 303,000
Palouse Wind Power Purchase Agreement [Member]
Evaluated power capacity, megawatts \| MW			105
Expected power production, in megawatts \| MW			40
Future contractual obligation \| $	$ 562,000		$ 562,000
Minimum [Member] \| Lancaster Power Purchase Agreement [Member]
Minimum estimated life of plant, in years			15 years
Maximum [Member] \| Lancaster Power Purchase Agreement [Member]
Minimum estimated life of plant, in years			25 years

Redeemable Noncontrolling Interests And Subsidiary Acquisitions (Redeemable Noncontrolling Interests) (Details) - USD ($) $ in Thousands	Sep. 30, 2013	Dec. 31, 2012
Noncontrolling Interest [Line Items]
Stock options and other outstanding redeemable stock	$ 8,330	$ 4,938
Total redeemable noncontrolling interests	8,330	$ 4,938
Ecova [Member]
Noncontrolling Interest [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Contingent Liability	$ 200

Redeemable Noncontrolling Interests And Subsidiary Acquisitions Redeemable Noncontrolling Interests And Subsidiary Acquisitions (LPB Acquisition) (Details) - USD ($) $ in Thousands		1 Months Ended	9 Months Ended
	Jan. 31, 2012	Jan. 31, 2012	Sep. 30, 2013	Sep. 30, 2012
Business Acquisition [Line Items]
Proceeds from Issuance of Common Stock			$ 4,479	$ 28,699
LPB Energy Management [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	$ 50,600
Borrowed Funds	$ 25,000	$ 25,000
Proceeds from Issuance of Common Stock		$ 20,000
Ecova [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Contingent Liability			200
Business Acquisition, Additional Payment Due in Year Two [Member]
Business Acquisition [Line Items]
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High			$ 1,500

Derivatives And Risk Management (Narrative) (Details) - USD ($) $ in Thousands	Sep. 30, 2013	Dec. 31, 2012
Derivative [Line Items]
Secured Debt	$ 1,426,700	$ 1,336,700
Cash deposited as collateral	23,800
Derivative, Fair Value, Amount Offset Against Collateral, Net	10,413	9,707
Liability position at aggregate fair value	23,300
Collateral agreements	18,500
Energy Derivative Contracts [Member]
Derivative [Line Items]
Letters of credit outstanding	20,100
First Mortgage [Member] \| 2041 [Member]
Derivative [Line Items]
Secured Debt	$ 85,000	$ 85,000

Derivatives And Risk Management (Energy Commodity Derivatives) (Details)
frequency in Thousands, Volt in Thousands

9 Months Ended

Sep. 30, 2013

frequency

Volt

Sales [Member] | Physical [Member] | Electric Derivative [Member]

Energy Commodity Derivative Volumes [Line Items]

230

345

254

287

286

443

Sales [Member] | Physical [Member] | Gas Derivative [Member]

Energy Commodity Derivative Volumes [Line Items]

906

1,786

Sales [Member] | Financial [Member] | Electric Derivative [Member]

Energy Commodity Derivative Volumes [Line Items]

1,123

2,839

2,542

1,634

Sales [Member] | Financial [Member] | Gas Derivative [Member]

Energy Commodity Derivative Volumes [Line Items]

26,934

84,108

46,840

13,380

Purchase [Member] | Physical [Member] | Electric Derivative [Member]

Energy Commodity Derivative Volumes [Line Items]

2013

385

^[1]

2014

702

^[1]

2015

379

^[1]

2016

367

^[1]

2017

366

^[1]

Thereafter

583

^[1]

Purchase [Member] | Physical [Member] | Gas Derivative [Member]

Energy Commodity Derivative Volumes [Line Items]

11,576

22,613

4,523

2,505

675

Purchase [Member] | Financial [Member] | Electric Derivative [Member]

Energy Commodity Derivative Volumes [Line Items]

2013

997

^[1]

2014

1,942

^[1]

2015

1,013

^[1]

2016

^[1]

2017

^[1]

Thereafter

^[1]

Purchase [Member] | Financial [Member] | Gas Derivative [Member]

Energy Commodity Derivative Volumes [Line Items]

36,932

115,004

72,320

38,210

[1]	Physical transactions represent commodity transactions where Avista Utilities will take delivery of either electricity or natural gas and financial transactions represent derivative instruments with no physical delivery, such as futures, swaps or options.

Derivatives And Risk Management (Interest Rate Swap Agreements) (Details) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2013 USD ($) Caontracts	Sep. 30, 2012 USD ($)	Dec. 31, 2012 USD ($) Caontracts
Derivatives, Fair Value [Line Items]
Cash received (paid) for settlement of interest rate swap agreements	$ (2,901)	$ 18,547
June 2013 [Member] \| Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts \| Caontracts			2
Derivative, Notional Amount			$ 85,000
Derivative, Maturity Date			Jun. 01, 2013
October 2014 [Member] \| Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts \| Caontracts	2		2
Derivative, Notional Amount	$ 50,000		$ 50,000
Derivative, Maturity Date	Oct. 01, 2014		Oct. 01, 2014
October 2015 [Member] \| Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts \| Caontracts	2		1
Derivative, Notional Amount	$ 45,000		$ 25,000
Derivative, Maturity Date	Oct. 01, 2015		Oct. 01, 2015
October 2016 [Member] \| Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts \| Caontracts	1
Derivative, Notional Amount	$ 20,000
Derivative, Maturity Date	Oct. 01, 2016
June 2018 [Member] \| Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts \| Caontracts	2,000
Derivative, Notional Amount	$ 50,000
Derivative, Maturity Date	Jun. 01, 2018

Derivatives And Risk Management (Derivative Instruments Summary) (Details) - USD ($)

Sep. 30, 2013

Dec. 31, 2012

Derivatives, Fair Value [Line Items]

Gross Asset

$ 94,598,000

$ 89,297,000

Gross Liability

(115,001,000)

(143,766,000)

Collateral Netting

10,413,000

9,707,000

Net Asset (Liability) in Balance Sheet

(9,990,000)

(44,762,000)

Gross Assets Not Offset

Gross Liabilities Not Offset

Net Asset (Liability)

(9,990,000)

(44,762,000)

Other Current Liabilities [Member] | Foreign Exchange Contract [Member]

Derivatives, Fair Value [Line Items]

Gross Asset

7,000

Gross Liability

(34,000)

Collateral Netting

Net Asset (Liability) in Balance Sheet

(27,000)

Gross Assets Not Offset

Gross Liabilities Not Offset

Net Asset (Liability)

(27,000)

Other Current Liabilities [Member] | Interest Rate Contracts [Member]

Derivatives, Fair Value [Line Items]

Gross Asset

Gross Liability

(1,406,000)

Collateral Netting

Net Asset (Liability) in Balance Sheet

(1,406,000)

Gross Assets Not Offset

Gross Liabilities Not Offset

Net Asset (Liability)

(1,406,000)

Other Current Liabilities [Member] | Foreign Exchange Contract [Member]

Derivatives, Fair Value [Line Items]

Gross Asset

19,000

Gross Liability

(1,000)

Collateral Netting

Net Asset (Liability) in Balance Sheet

18,000

Gross Assets Not Offset

Gross Liabilities Not Offset

Net Asset (Liability)

18,000

Other Property and Investments-Net [Member] | Interest Rate Contracts [Member]

Derivatives, Fair Value [Line Items]

Gross Asset

25,178,000

7,265,000

Gross Liability

Collateral Netting

Net Asset (Liability) in Balance Sheet

25,178,000

7,265,000

Gross Assets Not Offset

Gross Liabilities Not Offset

Net Asset (Liability)

25,178,000

7,265,000

Current Utility Energy Commodity Derivative Assets [Member] | Commodity Contracts [Member]

Derivatives, Fair Value [Line Items]

Gross Asset

^[1]

4,078,000

10,772,000

Gross Liability

^[1]

(648,000)

(6,633,000)

Collateral Netting

^[1]

Net Asset (Liability) in Balance Sheet

^[1]

3,430,000

4,139,000

Gross Assets Not Offset

^[1]

(9,678,000)

Gross Liabilities Not Offset

^[1]

6,572,000

Net Asset (Liability)

^[1]

3,430,000

1,033,000

Non-Current Utility Energy Commodity Derivative Assets [Member] | Commodity Contracts [Member]

Derivatives, Fair Value [Line Items]

Gross Asset

^[1]

7,191,000

18,779,000

Gross Liability

^[1]

(6,898,000)

(17,686,000)

Collateral Netting

^[1]

Net Asset (Liability) in Balance Sheet

^[1]

293,000

1,093,000

Gross Assets Not Offset

^[1]

Gross Liabilities Not Offset

^[1]

Net Asset (Liability)

^[1]

293,000

1,093,000

Current Utility Energy Commodity Derivative Liabilities [Member] | Commodity Contracts [Member]

Derivatives, Fair Value [Line Items]

Gross Asset

^[1]

34,858,000

50,227,000

Gross Liability

^[1]

(58,687,000)

(89,449,000)

Collateral Netting

^[1]

5,121,000

9,707,000

Net Asset (Liability) in Balance Sheet

^[1]

(18,708,000)

(29,515,000)

Gross Assets Not Offset

^[1]

9,678,000

Gross Liabilities Not Offset

^[1]

(6,572,000)

Net Asset (Liability)

^[1]

(18,708,000)

(26,409,000)

Other Noncurrent Liabilities [Member] | Interest Rate Contracts [Member]

Derivatives, Fair Value [Line Items]

Gross Asset

Gross Liability

(471,000)

Collateral Netting

Net Asset (Liability) in Balance Sheet

(471,000)

Gross Assets Not Offset

Gross Liabilities Not Offset

Net Asset (Liability)

(471,000)

Other Noncurrent Liabilities [Member] | Commodity Contracts [Member]

Derivatives, Fair Value [Line Items]

Gross Asset

^[1]

23,274,000

2,247,000

Gross Liability

^[1]

(48,296,000)

(28,558,000)

Collateral Netting

^[1]

5,292,000

Net Asset (Liability) in Balance Sheet

^[1]

(19,730,000)

(26,311,000)

Gross Assets Not Offset

^[1]

Gross Liabilities Not Offset

^[1]

Net Asset (Liability)

^[1]

$ (19,730,000)

$ (26,311,000)

[1]

Derivatives And Risk Management Derivatives and Risk Management (Foreign Currency Exchange Contracts) (Details) $ in Thousands, $ in Thousands	9 Months Ended
	Sep. 30, 2013 CAD ($)	Sep. 30, 2013 USD ($)	Dec. 31, 2012 CAD ($)	Dec. 31, 2012 USD ($)
Schedule of Foreign Currency Derivative Contracts Outstanding [Line Items]
Number Of Days Canadian Currency Prices Are Settled With U.S. Dollars	60 days
Number of Foreign Currency Derivatives Held	14	14	20	20
Foreign Exchange Contract [Member] \| United States of America, Dollars
Schedule of Foreign Currency Derivative Contracts Outstanding [Line Items]
Derivative, Notional Amount		$ 1,852		$ 12,621
Foreign Exchange Contract [Member] \| Canada, Dollars
Schedule of Foreign Currency Derivative Contracts Outstanding [Line Items]
Derivative, Notional Amount	$ 1,929		$ 12,502

Pension Plans And Other Postretirement Benefit Plans (Narrative) (Details) - USD ($) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Contributions to defined benefit pension plan	$ (44,000)	$ (44,000)	$ (44,000)

Pension Plans And Other Postretirement Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 4,743	$ 3,891	$ 14,229	$ 11,573
Interest cost	5,978	6,084	17,934	18,277
Expected return on plan assets	(6,900)	(5,950)	(20,700)	(17,900)
Transition obligation recognition	0	0	0	0
Amortization of prior service cost	75	75	225	225
Net loss recognition	3,220	3,019	9,989	8,797
Net periodic benefit cost	7,116	7,119	21,677	20,972
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	971	689	3,035	2,067
Interest cost	1,373	1,256	4,153	3,793
Expected return on plan assets	(402)	(375)	(1,202)	(1,125)
Transition obligation recognition	0	125	0	375
Amortization of prior service cost	(37)	(37)	(111)	(111)
Net loss recognition	1,395	1,250	4,342	3,814
Net periodic benefit cost	$ 3,300	$ 2,908	$ 10,217	$ 8,813

Committed Lines of Credit (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Jul. 31, 2012	Feb. 28, 2011
Avista Corporation [Member]
Short-term Debt [Line Items]
Maximum percentage ratio of consolidated total debt to consolidated total capitalization needed to comply with covenants	0.65
Balance outstanding at end of period	$ 66,000	$ 52,000
Letters of credit outstanding at end of period	$ 27,994	$ 35,885
Average interest rate at end of period	1.10%	1.12%
Ecova [Member]
Short-term Debt [Line Items]
Balance outstanding at end of period	$ 50,000	$ 54,000
Average interest rate at end of period	2.19%	2.21%
Line of Credit [Member] \| Avista Corporation [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 400,000
Line of Credit [Member] \| Ecova [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 125,000
Funded Debt to Ebitda Ratio [Member] \| Ecova [Member]
Short-term Debt [Line Items]
Maximum percentage ratio of consolidated total debt to consolidated total capitalization needed to comply with covenants	2.50
Fixed Charges Coverage Ratio [Member] \| Ecova [Member]
Short-term Debt [Line Items]
Maximum percentage ratio of consolidated total debt to consolidated total capitalization needed to comply with covenants	1.50

Long-Term Debt (Narrative) (Details) - USD ($)
$ in Thousands

Dec. 31, 1998

Sep. 30, 2013

Dec. 31, 2012

Debt Instrument [Line Items]

Long-term Pollution Control Bond, Noncurrent

^[1],[2]

$ (83,700)

Debt instrument, interest rate, stated percentage

8.45%

Amount borrowed to acquire a long-term fixed rate electric capacity contract

$ 145,000

Funds held in trust account which are used to secure long-term debt

1,600

2032 [Member] | Secured Debt [Member]

Debt Instrument [Line Items]

Long-term Pollution Control Bond, Noncurrent

^[2]

66,700

2034 [Member] | Secured Debt [Member]

Debt Instrument [Line Items]

Long-term Pollution Control Bond, Noncurrent

^[1]

$ 17,000

2047 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Debt instrument, interest rate, stated percentage

4.23%

[1]

[2]

Long-Term Debt (Schedule Of Long-Term Debt Instruments) (Details) - USD ($)
$ in Thousands

9 Months Ended

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 1998

Debt Instrument [Line Items]

Debt instrument, interest rate, stated percentage

8.45%

Secured long-term debt

$ 1,426,700

$ 1,336,700

Other long-term debt and capital leases

1,272,260

1,178,367

Settled interest rate swaps

^[1]

(23,760)

(27,900)

Unamortized debt discount

(1,330)

(1,453)

Total

1,406,290

1,312,439

Pollution Control Bonds

^[2],[3]

(83,700)

Other Long-term Debt and Capital Lease Obligations

4,680

5,092

Long-term Debt and Capital Lease Obligations, Current

$ (50,330)

(50,372)

2013 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2013

Debt instrument, interest rate, stated percentage

1.68%

Secured long-term debt

$ 50,000

50,000

2018, 5.95% [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2018

Debt instrument, interest rate, stated percentage

5.95%

Secured long-term debt

$ 250,000

250,000

2018, 7.39% - 7.45% [Member] | Secured Debt [Member]

Debt Instrument [Line Items]

Maturity Year

2018

Interest Rate, minimum

7.39%

Interest Rate, maximum

7.45%

Medium-Term Notes, Noncurrent

$ 22,500

22,500

2019 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2019

Debt instrument, interest rate, stated percentage

5.45%

Secured long-term debt

$ 90,000

90,000

2020 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2020

Debt instrument, interest rate, stated percentage

3.89%

Secured long-term debt

$ 52,000

52,000

2022 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2022

Debt instrument, interest rate, stated percentage

5.13%

Secured long-term debt

$ 250,000

250,000

2023, 7.18% - 7.54% [Member] | Secured Debt [Member]

Debt Instrument [Line Items]

Maturity Year

2023

Interest Rate, minimum

7.18%

Interest Rate, maximum

7.54%

Medium-Term Notes, Noncurrent

$ 13,500

13,500

2028 [Member] | Secured Debt [Member]

Debt Instrument [Line Items]

Maturity Year

2028

Debt instrument, interest rate, stated percentage

6.37%

Medium-Term Notes, Noncurrent

$ 25,000

25,000

2032 [Member] | Secured Debt [Member]

Debt Instrument [Line Items]

Maturity Year

^[3]

2032

Pollution Control Bonds

^[3]

$ 66,700

66,700

2034 [Member] | Secured Debt [Member]

Debt Instrument [Line Items]

Maturity Year

^[2]

2034

Pollution Control Bonds

^[2]

$ 17,000

17,000

2035 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2035

Debt instrument, interest rate, stated percentage

6.25%

Secured long-term debt

$ 150,000

150,000

2037 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2037

Debt instrument, interest rate, stated percentage

5.70%

Secured long-term debt

$ 150,000

150,000

2040 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2040

Debt instrument, interest rate, stated percentage

5.55%

Secured long-term debt

$ 35,000

35,000

2041 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2041

Debt instrument, interest rate, stated percentage

4.45%

Secured long-term debt

$ 85,000

85,000

2047 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2047

Debt instrument, interest rate, stated percentage

4.23%

Secured long-term debt

$ 80,000

80,000

Two Thousand Sixteen [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2016

Debt instrument, interest rate, stated percentage

0.84%

Secured long-term debt

$ 90,000

^[1]

$ 0

[1]	Upon settlement of interest rate swaps, these are recorded as a regulatory asset or liability and included as part of long-term debt above. They are amortized as a component of interest expense over the life of the associated debt and included as a part of the Company's cost of debt calculation for ratemaking purposes.
[2]	In December 2010, $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds, (Avista Corporation Colstrip Project) due 2034, which had been held by Avista Corp. since 2009, were refunded by a new bond issue (Series 2010B). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, the bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s Condensed Consolidated Balance Sheet.
[3]	In December 2010, $66.7 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due 2032, which had been held by Avista Corp. since 2008, were refunded by a new bond issue (Series 2010A). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, these bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s Condensed Consolidated Balance Sheet.

Fair Value (Carrying Value And Estimated Fair Value Of Financial Instruments) (Details) - USD ($) $ in Thousands	Sep. 30, 2013	Dec. 31, 2012
Reported Value Measurement [Member] \| Level 2 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	$ 951,000	$ 951,000
Reported Value Measurement [Member] \| Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	392,000	302,000
Reported Value Measurement [Member] \| Level 3 [Member] \| Affiliated Entity [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	51,547	51,547
Reported Value Measurement [Member] \| Level 3 [Member] \| Nonrecourse Long-Term Debt [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	21,688	32,803
Estimate of Fair Value Measurement [Member] \| Level 2 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	1,083,214	1,164,639
Estimate of Fair Value Measurement [Member] \| Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	382,426	320,892
Estimate of Fair Value Measurement [Member] \| Level 3 [Member] \| Affiliated Entity [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	36,861	43,686
Estimate of Fair Value Measurement [Member] \| Level 3 [Member] \| Nonrecourse Long-Term Debt [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	$ 22,875	$ 35,297

Fair Value (Fair Value Of Assets And Liabilities Measured On Recurring Basis) (Details) - USD ($)
$ in Thousands

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2012

Dec. 31, 2011

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Gross Asset

$ 94,598

$ 89,297

Securities available for sale:

75,477

59,321

Liability

115,001

143,766

Cash and cash equivalents

91,979

75,464

$ 82,952

$ 74,662

Fixed Income Securities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Cash and cash equivalents

800

Fair Value, Measurements, Recurring [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Foreign currency derivatives

Interest rate swaps

25,178

7,265

Money Market Funds, Fair Value

3,238

15,084

Funds held in trust account of Spokane Energy

1,600

Total

117,277

96,467

Foreign currency derivative liabilities at fair value

Interest rate swaps

471

1,406

Total

38,910

57,259

Fair Value, Measurements, Recurring [Member] | Energy commodity derivatives [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Gross Asset

3,723

5,232

Liability

20,440

33,275

Fair Value, Measurements, Recurring [Member] | Power Option Agreement [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Liability

761

1,480

Fair Value, Measurements, Recurring [Member] | Natural Gas Exchange Agreements [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Liability

1,193

2,379

Fair Value, Measurements, Recurring [Member] | Power Exchange Agreements [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Gross Asset

Liability

16,044

18,692

Fair Value, Measurements, Recurring [Member] | U.S. Government Agency [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale:

66,165

48,496

Fair Value, Measurements, Recurring [Member] | Municipal [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale:

3,542

848

Fair Value, Measurements, Recurring [Member] | Corporate fixed income - financial [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale:

3,004

5,026

Fair Value, Measurements, Recurring [Member] | Corporate fixed income - industrial [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale:

1,766

3,936

Fair Value, Measurements, Recurring [Member] | Certificates of deposits [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale:

1,000

1,015

Fair Value, Measurements, Recurring [Member] | Fixed Income Securities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Deferred compensation assets:

^[1]

1,829

2,010

Fair Value, Measurements, Recurring [Member] | Equity Securities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Deferred compensation assets:

^[1]

6,213

5,955

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Money Market Funds, Fair Value

3,238

15,084

Funds held in trust account of Spokane Energy

1,600

Total

12,880

24,649

Total

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Deferred compensation assets:

^[1]

1,829

2,010

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Deferred compensation assets:

^[1]

6,213

5,955

Fair Value, Measurements, Recurring [Member] | Level 2 [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Foreign currency derivatives

Interest rate swaps

25,178

7,265

Total

170,008

148,233

Foreign currency derivative liabilities at fair value

Interest rate swaps

471

1,406

Total

96,936

120,830

Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Energy commodity derivatives [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Gross Asset

69,334

81,640

Liability

96,464

119,390

Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | U.S. Government Agency [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale:

66,165

48,496

Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Municipal [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale:

3,542

848

Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Corporate fixed income - financial [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale:

3,004

5,026

Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Corporate fixed income - industrial [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale:

1,766

3,936

Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Certificates of deposits [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale:

1,000

1,015

Fair Value, Measurements, Recurring [Member] | Level 3 [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Total

385

Total

18,065

22,936

Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Power Option Agreement [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Liability

761

1,480

Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Natural Gas Exchange Agreements [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Liability

1,193

2,379

Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Power Exchange Agreements [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Gross Asset

385

Liability

16,111

19,077

Fair Value, Measurements, Recurring [Member] | Netting [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Foreign currency derivatives

^[2]

(7)

Total

^[2]

(65,678)

(76,800)

Foreign currency derivative liabilities at fair value

(7)

Total

^[2]

(76,091)

(86,507)

Fair Value, Measurements, Recurring [Member] | Netting [Member] | Energy commodity derivatives [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Gross Asset

^[2]

(65,611)

(76,408)

Liability

^[2]

(76,024)

(86,115)

Fair Value, Measurements, Recurring [Member] | Netting [Member] | Natural Gas Exchange Agreements [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Liability

^[2]

Fair Value, Measurements, Recurring [Member] | Netting [Member] | Power Exchange Agreements [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Gross Asset

(67)

(385)

^[2]

Liability

$ (67)

$ (385)

^[2]

[1]	These assets are trading securities and are included in other property and investments-net on the Condensed Consolidated Balance Sheets.
[2]	The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.

Fair Value (Quantitative Information) (Details)
$ in Thousands

9 Months Ended

Sep. 30, 2013

USD ($)

MMBTU

MWh

$ / MmBtu

$ / MWH

Dec. 31, 2012

USD ($)

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Gross Liability | $

$ (115,001)

$ (143,766)

Power Exchange Agreements [Member] | 2014 to 2019 [Member] | Surrogate Facility Pricing [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Escalation Factor

3.00%

Power Option Agreement [Member] | Black Scholes Merton [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Fair Value Assumptions, Expected Volatility Rate

^[1]

20.00%

Power Option Agreement [Member] | 2015 [Member] | Black Scholes Merton [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Derivative, Price Risk Option Strike Price | $ / MWH

55.53

Power Option Agreement [Member] | 2016 [Member] | Black Scholes Merton [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Fair Value Assumptions, Expected Volatility Rate

21.00%

Power Option Agreement [Member] | 2013 [Member] | Black Scholes Merton [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Fair Value Assumptions, Expected Volatility Rate

32.00%

Power Option Agreement [Member] | 2019 [Member] | Black Scholes Merton [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Derivative, Price Risk Option Strike Price | $ / MWH

69.60

Minimum [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Operation and Maintenance Charges

^[2]

30.18

Transaction/Delivery Volumes | MWh

365,619

Minimum [Member] | Power Option Agreement [Member] | Black Scholes Merton [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Transaction/Delivery Volumes | MWh

157,517

Minimum [Member] | Natural Gas Exchange Agreements [Member] | Internally Derived Weighted Average Cost Of Gas [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Derivative, Forward Price | $ / MmBtu

3.64

Transaction/Delivery Volumes | MMBTU

139,980

Maximum [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Operation and Maintenance Charges

^[2]

53.90

Transaction/Delivery Volumes | MWh

394,255

Maximum [Member] | Power Option Agreement [Member] | Black Scholes Merton [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Transaction/Delivery Volumes | MWh

287,147

Maximum [Member] | Natural Gas Exchange Agreements [Member] | Internally Derived Weighted Average Cost Of Gas [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Derivative, Forward Price | $ / MmBtu

4.19

Transaction/Delivery Volumes | MMBTU

310,000

Average [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Operation and Maintenance Charges

^[2]

40.93

Fair Value, Measurements, Recurring [Member] | Power Exchange Agreements [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Gross Liability | $

$ (16,044)

(18,692)

Fair Value, Measurements, Recurring [Member] | Power Option Agreement [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Gross Liability | $

(761)

(1,480)

Fair Value, Measurements, Recurring [Member] | Natural Gas Exchange Agreements [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Gross Liability | $

$ (1,193)

$ (2,379)

[1]	The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.32 for 2013 to 0.21 in October 2016.
[2]	The average O&M charges for 2013 were $40.93 per MWh.

Fair Value (Reconciliation For All Assets And Liabilities Measured At Fair Value On A Recurring Basis Using Significant Unobservable Inputs (Level 3)) (Details) - Fair Value, Inputs, Level 3 [Member] - USD ($)
$ in Thousands

3 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Beginning Balance

$ (23,797)

$ (14,921)

$ (22,551)

$ (12,858)

Included in net income

Included in other comprehensive income

Included in regulatory assets/liabilities

^[1]

5,800

(7,644)

2,243

(12,905)

Purchases

Issuances

Settlements

(1)

2,310

3,197

Transfers from other categories

Ending Balance

(17,998)

(22,566)

(17,998)

(22,566)

Natural Gas Exchange Agreements [Member]

Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Beginning Balance

(1,022)

(2,727)

(2,379)

(1,688)

Included in net income

Included in other comprehensive income

Included in regulatory assets/liabilities

^[1]

(170)

(377)

1,637

(364)

Purchases

Issuances

Settlements

(1)

(451)

(1,053)

Transfers from other categories

Ending Balance

(1,193)

(3,105)

(1,193)

(3,105)

Power Exchange Agreements [Member]

Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Beginning Balance

(22,179)

(10,438)

(18,692)

(9,910)

Included in net income

Included in other comprehensive income

Included in regulatory assets/liabilities

^[1]

6,135

(7,438)

(113)

(12,216)

Purchases

Issuances

Settlements

2,761

4,250

Transfers from other categories

Ending Balance

(16,044)

(17,876)

(16,044)

(17,876)

Power Option Agreement [Member]

Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Beginning Balance

(596)

(1,756)

(1,480)

(1,260)

Included in net income

Included in other comprehensive income

Included in regulatory assets/liabilities

^[1]

(165)

171

719

(325)

Purchases

Issuances

Settlements

Transfers from other categories

Ending Balance

$ (761)

$ (1,585)

$ (761)

$ (1,585)

[1]

(1)The UTC and the IPUC issued accounting orders authorizing Avista Utilities to offset commodity 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 delivery. The orders provide for Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Condensed Consolidated Statements of Income. Realized gains or losses are recognized in the period of delivery, 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 in Washington, the PCA mechanism in Idaho, and periodic general rates cases.

Earnings Per Share Attributable To Avista Corporation (Computation Of Earnings Per Share) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Numerator:
Net income attributable to Avista Corporation shareholders	$ 11,413	$ 5,786	$ 79,411	$ 62,352
Subsidiary earnings adjustment for dilutive securities	(81)	(16)	(163)	(25)
Adjusted net income attributable to Avista Corporation shareholders for computation of diluted earnings per common share	$ 11,332	$ 5,770	$ 79,248	$ 62,327
Denominator:
Weighted-average number of common shares outstanding-basic	59,994	59,047	59,933	58,778
Performance and restricted stock awards	38	71	31	234
Stock options	0	5	0	14
Weighted-average number of common shares outstanding-diluted	60,032	59,123	59,964	59,026
Earnings per common share attributable to Avista Corporation:
Basic	$ 0.19	$ 0.10	$ 1.32	$ 1.06
Diluted (usd per share)	$ 0.19	$ 0.10	$ 1.32	$ 1.06

Commitments And Contingencies (Details)	1 Months Ended		9 Months Ended
Commitments And Contingencies (Details)	Mar. 31, 2007 family	May 31, 2004 USD ($)	Sep. 30, 2013 USD ($) hydroelectric_plant	Mar. 30, 2007
Amount of Regulatory Costs Not yet Approved			$ 1,300,000
Investigation review bid maximum (per MW)		$ 250
Customer refund liability			$ 200,000
Number of families that own property near the holding ponds who filed a complaint \| family	2
Owners percentage interest				15.00%
Number of hydroelectric plants \| hydroelectric_plant			6
Number of years, license issued			50 years
WASHINGTON
Amount of Regulatory Costs Not yet Approved			$ 900,000
IDAHO
Amount of Regulatory Costs Not yet Approved			$ 400,000

Information By Business Segments (Details) - USD ($)
$ in Thousands

3 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Segment Reporting Information [Line Items]

Operating revenues

$ 335,875

$ 340,632

$ 1,170,829

$ 1,136,474

Resource costs

131,136

153,801

487,277

500,805

Other operating expenses

116,855

110,455

340,549

329,631

Depreciation and amortization

33,903

31,646

98,793

93,293

Income from operations

35,269

26,608

178,073

149,022

Interest expense

^[1]

19,683

19,264

59,471

57,866

Income taxes

5,459

1,608

46,107

33,106

Net income (loss) attributable to Avista Corporation

11,413

5,786

79,411

62,352

Payments to Acquire Other Property, Plant, and Equipment

75,749

59,606

222,437

182,348

Total assets

4,402,002

$ 4,313,179

Avista Utilities [Member]

Segment Reporting Information [Line Items]

Operating revenues

278,923

292,535

1,008,669

992,210

Resource costs

131,136

153,801

487,277

500,805

Other operating expenses

69,596

66,456

200,824

196,759

Depreciation and amortization

29,823

28,255

86,783

83,327

Income from operations

29,657

25,901

167,648

147,596

Interest expense

^[1]

18,837

18,001

56,635

54,148

Income taxes

3,945

2,590

43,278

34,425

Net income (loss) attributable to Avista Corporation

9,447

7,660

76,265

65,157

Payments to Acquire Other Property, Plant, and Equipment

75,368

57,964

220,712

178,440

Total assets

3,961,718

3,894,821

Ecova [Member]

Segment Reporting Information [Line Items]

Operating revenues

46,398

38,617

133,365

115,707

Resource costs

Other operating expenses

37,047

33,868

110,753

104,392

Depreciation and amortization

3,909

3,260

11,474

9,455

Income from operations

5,442

1,489

11,138

1,860

Interest expense

^[1]

398

530

1,265

1,301

Income taxes

2,092

495

4,178

918

Net income (loss) attributable to Avista Corporation

3,040

640

5,759

962

Payments to Acquire Other Property, Plant, and Equipment

357

1,023

1,586

3,248

Total assets

353,128

322,720

Other Business Segment [Member]

Segment Reporting Information [Line Items]

Operating revenues

11,004

9,930

30,145

29,907

Resource costs

Other operating expenses

10,662

10,581

30,322

29,830

Depreciation and amortization

171

131

536

511

Income from operations

170

(782)

(713)

(434)

Interest expense

^[1]

525

824

1,801

2,691

Income taxes

(578)

(1,477)

(1,349)

(2,237)

Net income (loss) attributable to Avista Corporation

(1,074)

(2,514)

(2,613)

(3,767)

Payments to Acquire Other Property, Plant, and Equipment

619

139

660

Total assets

87,156

95,638

Total Non-Utility [Member]

Segment Reporting Information [Line Items]

Operating revenues

57,402

48,547

163,510

145,614

Resource costs

Other operating expenses

47,709

44,449

141,075

134,222

Depreciation and amortization

4,080

3,391

12,010

9,966

Income from operations

5,612

707

10,425

1,426

Interest expense

^[1]

923

1,354

3,066

3,992

Income taxes

1,514

(982)

2,829

(1,319)

Net income (loss) attributable to Avista Corporation

1,966

(1,874)

3,146

(2,805)

Payments to Acquire Other Property, Plant, and Equipment

381

1,642

1,725

3,908

Total assets

440,284

418,358

Intersegment Eliminations [Member]

Segment Reporting Information [Line Items]

Operating revenues

^[2]

(450)

(1,350)

Resource costs

^[2]

Other operating expenses

^[2]

(450)

(1,350)

Depreciation and amortization

^[2]

Income from operations

^[2]

Interest expense

^[1],[2]

(77)

(91)

(230)

(274)

Income taxes

^[2]

Net income (loss) attributable to Avista Corporation

^[2]

Payments to Acquire Other Property, Plant, and Equipment

^[2]

$ 0

Total assets

^[2]

$ 0

[1]	Including interest expense to affiliated trusts.
[2]	Intersegment eliminations reported as operating revenues and resource costs represent intercompany purchases and sales of electric capacity and energy. Intersegment eliminations reported as interest expense represent intercompany interest.

Subsequent Events Business Acquisition (Details)	3 Months Ended		9 Months Ended		12 Months Ended
Subsequent Events Business Acquisition (Details)	Sep. 30, 2013 USD ($) employee $ / shares	Sep. 30, 2012 USD ($)	Sep. 30, 2013 USD ($) employee $ / shares	Sep. 30, 2012 USD ($)	Dec. 31, 2012 USD ($) employee
Revenues	$ 335,875,000	$ 340,632,000	$ 1,170,829,000	$ 1,136,474,000
AEL&P [Member]
Number of Customers \| employee					15,900
Total Rate Base					$ 111,000,000
Entity Number of Employees \| employee	60		60
Revenues					$ 42,000,000
Alaska Energy Resources Company [Member]
Merger Consideration - Total			$ 170,000,000
Representative Reimbursement Amount			500,000
Business Combination, Acquisition Related Costs			$ 100,000
Minimum [Member] \| Alaska Energy Resources Company [Member]
Business Combination Equity Consideration Share Price \| $ / shares	$ 21.48		$ 21.48
Maximum [Member] \| Alaska Energy Resources Company [Member]
Business Combination Equity Consideration Share Price \| $ / shares	$ 34.30		$ 34.30