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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes ☐ No ☒

As of ~~April 30,~~October 31, 2021, ~~69,314,368~~70,768,243 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

(The following acronyms and terms are found in multiple locations within the document)

From time to time, we make forward-looking statements such as statements regarding projected or future:

These statements are based upon underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our reports filed under the Securities Exchange Act of 1934, as amended (including this Quarterly Report on Form 10-Q), and elsewhere. Forward-looking statements are all statements except those of historical fact including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions.

Forward-looking statements (including those made in this Quarterly Report on Form 10-Q) are subject to a variety of risks, uncertainties and other factors. Most of these factors are beyond our control and may have a significant effect on our operations, results of operations, financial condition or cash flows, which could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others:

Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonable based on, without limitation, an examination of historical operating trends, our records and other information available from third parties. There can be no assurance that our expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New risks, uncertainties and other factors emerge from time to time, and it is not possible for us to predict all such factors, nor can we assess the effect of each such factor on our business or the extent that any such factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statement.

We file annual, quarterly and current reports and proxy statements with the SEC. The SEC maintains a website that contains these documents at www.sec.gov. We make annual, quarterly and current reports and proxy statements available on our website, ~~www.avistacorp.com,~~https://investor.avistacorp.com/, as soon as practicable after electronically filing these documents with the SEC. Except for SEC filings or portions thereof that are specifically referred to in this report, information contained on these websites is not part of this report.


							Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020			2021			2020
Operating Revenues:
Utility revenues:
Utility revenues, exclusive of alternative revenue programs	$	412,182		$	393,820		$	306,398		$	276,351		$	1,019,756		$	944,146
Alternative revenue programs		499			(4,413	)		(10,499	)		(3,972	)		(13,069	)		(4,023	)
Total utility revenues		412,681			389,407			295,899			272,379			1,006,687			940,123
Non-utility revenues		189			823			108			267			445			1,345
Total operating revenues		412,870			390,230			296,007			272,646			1,007,132			941,468
Operating Expenses:
Utility operating expenses:
Resource costs		134,579			129,547			102,133			78,785			327,390			276,297
Other operating expenses		87,555			94,496			85,625			85,551			267,233			266,251
Depreciation and amortization		55,221			51,421			57,722			53,953			169,009			169,282
Taxes other than income taxes		32,309			30,978			25,440			24,016			82,223			79,736
Non-utility operating expenses:
Other operating expenses		1,184			1,360			843			1,697			3,186			3,716
Depreciation and amortization		127			235			30			146			230			569
Total operating expenses		310,975			308,037			271,793			244,148			849,271			795,851
Income from operations		101,895			82,193			24,214			28,498			157,861			145,617
Interest expense		26,304			26,347			26,547			25,812			78,982			77,784
Interest expense to affiliated trusts		109			270			102			128			317			606
Capitalized interest		(1,015	)		(998	)		(1,102	)		(1,009	)		(3,033	)		(2,979	)
Other income-net		(3,684	)		(382	)		(10,267	)		(2,168	)		(23,992	)		(2,019	)
Income before income taxes		80,181			56,956			8,934			5,735			105,587			72,225
Income tax expense		12,164			8,532
Income tax expense (benefit)								(5,432	)		859			9,130			1,472
Net income	$	68,017		$	48,424		$	14,366		$	4,876		$	96,457		$	70,753
Weighted-average common shares outstanding (thousands), basic		69,293			67,239			70,054			68,194			69,582			67,638
Weighted-average common shares outstanding (thousands), diluted		69,506			67,381			70,129			68,337			69,722			67,769

Earnings per common share:
Basic	$	0.98		$	0.72		$	0.21		$	0.07		$	1.39		$	1.05
Diluted	$	0.98		$	0.72		$	0.20		$	0.07		$	1.38		$	1.04


	March 31,			December 31,			September 30,			December 31,
	2021			2020			2021			2020
Assets:
Current Assets:
Cash and cash equivalents	$	21,647		$	14,196		$	19,224		$	14,196
Accounts and notes receivable-less allowances of $12,139 and $11,387, respectively		153,128			163,772
Accounts and notes receivable-less allowances of $12,360 and $11,387, respectively								130,696			163,772
Materials and supplies, fuel stock and stored natural gas		63,160			67,451			87,203			67,451
Regulatory assets		29,225			13,673			37,768			13,673
Other current assets		82,922			84,885			81,384			84,885
Total current assets		350,082			343,977			356,275			343,977
Net utility property		5,027,103			4,991,612			5,168,825			4,991,612
Goodwill		52,426			52,426			52,426			52,426
Non-current regulatory assets		705,921			750,443			875,952			750,443
Other property and investments-net and other non-current assets		263,964			263,639			278,000			263,639
Total assets	$	6,399,496		$	6,402,097		$	6,731,478		$	6,402,097
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	93,100		$	106,613		$	102,824		$	106,613
Current portion of long-term debt								250,000			0
Short-term borrowings		193,000			203,000			199,075			203,000
Regulatory liabilities		45,067			46,435			75,559			46,435
Other current liabilities		161,632			149,831			171,728			149,831
Total current liabilities		492,799			505,879			799,186			505,879
Long-term debt		2,008,742			2,008,534			1,898,235			2,008,534
Long-term debt to affiliated trusts		51,547			51,547			51,547			51,547
Pensions and other postretirement benefits		199,670			211,880			177,333			211,880
Deferred income taxes		607,707			594,712			634,215			594,712
Non-current regulatory liabilities		783,784			784,820			886,351			784,820
Other non-current liabilities and deferred credits		186,657			214,999			182,975			214,999
Total liabilities		4,330,906			4,372,371			4,629,842			4,372,371
Commitments and Contingencies (See Notes to Condensed Consolidated Financial Statements)
Equity:
Shareholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 69,313,337 and 69,238,901 shares issued and outstanding, respectively		1,285,999			1,286,068
Common stock, no par value; 200,000,000 shares authorized; 70,767,212 and 69,238,901 shares issued and outstanding, respectively								1,349,960			1,286,068
Accumulated other comprehensive loss		(14,063	)		(14,378	)		(13,451	)		(14,378	)
Retained earnings		796,654			758,036			765,127			758,036
Total shareholders’ equity		2,068,590			2,029,726			2,101,636			2,029,726
Total liabilities and equity	$	6,399,496		$	6,402,097		$	6,731,478		$	6,402,097

The accompanying condensed consolidated financial statements of Avista Corp. as of and for the interim periods ended ~~March 31,~~September 30, 2021 and ~~March 31,~~September 30, 2020 are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results for the interim periods. All such adjustments are of a normal recurring nature. The condensed consolidated financial statements have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Condensed Consolidated Statements of Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These condensed consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company's audited consolidated financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2020 (2020 Form 10-K).

NOTE 3. BALANCE SHEET COMPONENTS

Materials and Supplies, Fuel Stock and Stored Natural Gas

Inventories of materials and supplies, fuel stock and stored natural gas are recorded at average cost for our regulated operations and the lower of cost or ~~market~~net realizable value for our non-regulated operations and consisted of the following as of ~~March 31,~~September 30, 2021 and December 31, 2020 (dollars in thousands):


	September 30,		December 31,
	2021		2020
Materials and supplies	$	58,238	$	53,258
Fuel stock		5,154		4,658
Stored natural gas		23,811		9,535
Total	$	87,203	$	67,451

March 31,

December 31,

2021

2020

Materials and supplies

$
56,368

$
53,258

Fuel stock

4,843

4,658

Stored natural gas

1,949

9,535

Total

$
63,160

$
67,451

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AVISTA CORPORATION

Other Current Assets

Other current assets consisted of the following as of ~~March 31,~~September 30, 2021 and December 31, 2020 (dollars in thousands):


	March 31,		December 31,		September 30,		December 31,
	2021		2020		2021		2020
Collateral posted for derivative instruments after netting with outstanding derivative liabilities	$	4,810	$	4,336	$	10,604	$	4,336
Prepayments		25,984		24,411		18,523		24,411
Income taxes receivable		44,371		49,814		39,151		49,814
Other		7,757		6,324		13,106		6,324
Total	$	82,922	$	84,885	$	81,384	$	84,885

Net Utility Property

Net utility property, which is recorded at original cost net of accumulated depreciation, consisted of the following as of ~~March 31,~~September 30, 2021 and December 31, 2020 (dollars in thousands):


	March 31,		December 31,		September 30,		December 31,
	2021		2020		2021		2020
Utility plant in service	$	6,865,652	$	6,809,797	$	7,067,842	$	6,809,797
Construction work in progress		193,685		175,767		204,384		175,767
Total		7,059,337		6,985,564		7,272,226		6,985,564
Less: Accumulated depreciation and amortization		2,032,234		1,993,952		2,103,401		1,993,952
Total net utility property	$	5,027,103	$	4,991,612	$	5,168,825	$	4,991,612

Other Property and Investments-Net and Other Non-Current Assets

Other property and investments-net and other non-current assets consisted of the following as of ~~March 31,~~September 30, 2021 and December 31, 2020 (dollars in thousands):


	September 30,		December 31,
	2021		2020
Operating lease ROU assets	$	70,578	$	71,891
Equity investments		83,496		59,318
Finance lease ROU assets		44,607		47,338
Non-utility property		19,248		19,508
Notes receivable		14,759		14,454
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		9,917		9,174
Assets held for sale (1)		0		3,462
Other		23,848		26,947
Total	$	278,000	$	263,639

March 31,

December 31,

2021

2020

Operating lease ROU assets

$
71,410

$
71,891

Finance lease ROU assets

46,428

47,338

Non-utility property

18,398

19,508

Equity investments

61,132

59,318

Investment in affiliated trust

11,547

11,547

Notes receivable

14,665

14,454

Deferred compensation assets

9,469

9,174

Assets held for sale (1)

3,363

3,462

Other

27,552

26,947

Total

$
263,964

$
263,639

(1) ~~The~~

During the second quarter of 2021, the Company ~~is in the process of selling~~sold certain subsidiary assets associated with the Spokane Steam ~~Plant Square and Brew Pub.~~

Plant.

Other current liabilities consisted of the following as of ~~March 31,~~September 30, 2021 and December 31, 2020 (dollars in thousands):


	September 30, 2021		December 31, 2020
Accrued taxes other than income taxes	$	42,945	$	45,099
Derivative liabilities		24,797		14,008
Employee paid time off accruals		28,321		26,495
Accrued interest		29,278		17,083
Pensions and other postretirement benefits		10,970		11,987
Other		35,417		35,159
Total other current liabilities	$	171,728	$	149,831

March 31,
2021

December 31,
2020

Accrued taxes other than income taxes

$
56,630

$
45,099

Derivative liabilities

8,644

14,008

Employee paid time off accruals

28,775

26,495

Accrued interest

28,920

17,083

Pensions and other postretirement benefits

10,512

11,987

Other

28,151

35,159

Total other current liabilities

$
161,632

$
149,831

Table of Contents

AVISTA CORPORATION

Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of ~~March 31,~~September 30, 2021 and December 31, 2020 (dollars in thousands):


	March 31, 2021		December 31, 2020		September 30, 2021		December 31, 2020
Operating lease liabilities	$	68,276	$	67,716	$	69,475	$	67,716
Finance lease liabilities		48,044		48,815		46,501		48,815
Deferred investment tax credits		29,728		29,866		29,452		29,866
Asset retirement obligations		17,126		17,194		16,425		17,194
Derivative liabilities		8,959		37,427		5,580		37,427
Other		14,524		13,981		15,542		13,981
Total	$	186,657	$	214,999	$	182,975	$	214,999

~~Table of Contents~~

~~AVISTA CORPORATION~~

Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of ~~March 31,~~September 30, 2021 and December 31, 2020 (dollars in thousands):


	September 30, 2021				December 31, 2020
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	11,159	$	0	$	2,073	$	5,722
Decoupling surcharge		9,036		12,641		7,123		17,123
Deferred natural gas costs		9,967		4,758		2,308		0
Deferred power costs		7,606		4,043		1,775		1,562
Pension and other postretirement benefit plans		0		192,220		0		198,746
Interest rate swaps		0		195,909		0		214,851
Deferred income taxes (1)		0		242,782		0		108,517
Settlement with Coeur d'Alene Tribe		0		39,205		0		40,043
AFUDC above FERC allowed rate		0		45,093		0		47,393
Demand side management programs		0		3,124		0		3,814
Utility plant to be abandoned		0		29,684		0		28,916
COVID-19 deferrals		0		15,648		0		8,166
Other regulatory assets		0		90,845		394		75,590
Total regulatory assets	$	37,768	$	875,952	$	13,673	$	750,443
Regulatory Liabilities
Income tax related liabilities (1)	$	52,843	$	475,607	$	14,952	$	399,677
Deferred power costs		10,512		9,136		20,299		17,570
Decoupling rebate		2,717		10,283		1,447		1,519
Utility plant retirement costs		0		344,061		0		325,832
Interest rate swaps		0		16,757		0		15,046
COVID-19 deferrals		0		12,673		0		10,949
Other regulatory liabilities		9,487		17,834		9,737		14,227
Total regulatory liabilities	$	75,559	$	886,351	$	46,435	$	784,820

(1) In 2021, the Company received regulatory approval in all jurisdictions to change to flow-through tax treatment of certain basis adjustments, which was $128.8 million as of September 30, 2021.

~~ASC 606 defines the core principle of the~~The revenue recognition model ~~is that~~contained in ASC 606 requires an entity ~~should~~to identify the various performance obligations in a contract, allocate the transaction price among the performance obligations and recognize revenue when (or as) the entity satisfies each performance obligation.

The majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers, which has two performance obligations, (1) having service available for a specified period (typically a month at a time) and (2) the delivery of energy to customers. The total energy price generally has a fixed component (basic charge) related to having service available and a usage-based component, related to the delivery and consumption of energy. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant utility commission authorization determine the charges the Company may bill the customer. Given that all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately at that time.

Revenues from contracts with customers are presented in the Condensed Consolidated Statements of Income in the line item "Utility revenues, exclusive of alternative revenue programs."

The Company has certain wholesale contracts which are not accounted for as derivatives and, accordingly, are within the scope of ASC 606 and considered revenue from contracts with customers. Revenue is recognized as energy is delivered to the customer or the service is available for a specified period of time, consistent with the discussion of rate-regulated sales above.

ASC 606 retained existing GAAP associated with alternative revenue programs, which specified that alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between an entity and a customer. GAAP requires that an entity present revenue arising from alternative revenue programs separately from revenues arising from contracts with customers on the face of the Condensed Consolidated Statements of Income. The Company's decoupling mechanisms (also known as a FCA in Idaho) qualify as alternative revenue programs. Decoupling revenue deferrals are recognized in the Condensed Consolidated Statements of Income during the period they occur (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset or liability is established that will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative revenue program, like decoupling, the revenue must be expected to be collected from customers within 24 months of the deferral to qualify for recognition in the current period Condensed Consolidated Statement of Income. Any amounts included in the Company's decoupling program that are not expected to be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. The amounts expected to be collected from customers within 24 months represents an estimate that must be made by the Company on an ongoing basis due to it being based on the volumes of electric and natural gas sold to customers on a go-forward basis.

Most wholesale electric and natural gas transactions (including both physical and financial transactions), and the sale of fuel are considered derivatives, which are specifically scoped out of ASC 606. As such, these revenues are disclosed separately from revenue from contracts with customers. Revenue is recognized for these items upon the settlement/expiration of the derivative contract. Derivative revenue includes those transactions that are entered into and settled within the same month.

Other utility revenue includes rent, sales of materials, late fees and other charges that do not represent contracts with customers. Other utility revenue also includes the provision for earnings ~~sharing and the deferral and amortization of refunds to customers associated with the TCJA.~~sharing. This revenue is scoped out of ASC 606, as this revenue does not represent items where a customer is a party that has contracted with the Company to obtain goods or services that are an output of the

Company’s ordinary activities in exchange for consideration. As such, these revenues are presented separately from revenue from contracts with customers.

Revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) are reported on a net basis as part of derivative revenues.

Utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) are taxes that are imposed on Avista Utilities as opposed to being imposed on its customers; therefore, Avista Utilities is the taxpayer and records these transactions on a gross basis in revenue from contracts with customers and operating expense (taxes other than income taxes). The utility-related taxes collected from customers at AEL&P are imposed on the customers rather than AEL&P; therefore, the customers are the taxpayers and AEL&P is acting as their agent. As such, these transactions at AEL&P are presented on a net basis within revenue from contracts with customers.

~~Table of Contents~~

~~AVISTA CORPORATION~~

Utility-related taxes that were included in revenue from contracts with customers were as follows for the three and nine months ended ~~March 31~~September 30 (dollars in thousands):

2021

2020

Utility-related taxes
$
19,696

$
18,700


	Three months ended September 30,				Nine months ended September 30,
	2021		2020		2021		2020
Utility-related taxes	$	13,816	$	12,411	$	46,971	$	43,989

Significant Judgments and Unsatisfied Performance Obligations

The only significant judgments involving revenue recognition are estimates surrounding unbilled revenue and receivables from contracts with customers and estimates surrounding the amount of decoupling revenues that will be collected from customers within 24 months (discussed above).

The Company has certain capacity arrangements, where the Company has a contractual obligation to provide either electric or natural gas capacity to its customers for a fixed fee. Most of these arrangements are paid for in arrears by the customers and do not result in deferred revenue and only result in receivables from the customers. The Company does have one capacity agreement where the customer makes payments throughout the ~~year and, depending on the timing of the customer payments, it can result in an immaterial amount of deferred revenue or a receivable from the customer.~~year. As of ~~March 31,~~September 30, 2021, the Company estimates it had unsatisfied capacity performance obligations of ~~$21.2~~$18.8 million, which will be recognized as revenue in future periods as the capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.

Table of Contents

AVISTA CORPORATION

Disaggregation of Total Operating Revenue

The following table disaggregates total operating revenue by segment and source for the three and nine months ended ~~March 31~~September 30 (dollars in thousands):


	Three months ended September 30,						Nine months ended September 30,
	2021			2020			2021			2020
Avista Utilities
Revenue from contracts with customers	$	266,789		$	240,036		$	886,078		$	827,071
Derivative revenues		28,087			24,075			91,151			79,361
Alternative revenue programs		(10,499	)		(3,972	)		(13,069	)		(4,023	)
Deferrals and amortizations for rate refunds to customers		(156	)		1,742			2,664			1,216
Other utility revenues		2,531			1,683			7,348			5,484
Total Avista Utilities		286,752			263,564			974,172			909,109
AEL&P
Revenue from contracts with customers		9,065			8,797			32,331			30,900
Deferrals and amortizations for rate refunds to customers		(48	)		(48	)		(143	)		(143	)
Other utility revenues		130			66			327			257
Total AEL&P		9,147			8,815			32,515			31,014

Other revenues		108			267			445			1,345
Total operating revenues	$	296,007		$	272,646		$	1,007,132		$	941,468

2021

2020

Avista Utilities

Revenue from contracts with customers

$
358,613

$
351,628

Derivative revenues

34,981

31,075

Alternative revenue programs

499

(4,413
)
Deferrals and amortizations for rate refunds to customers

3,189

(2,606
)
Other utility revenues

2,578

1,521

Total Avista Utilities

399,860

377,205

AEL&P

Revenue from contracts with customers

12,779

12,126

Deferrals and amortizations for rate refunds to customers

(47
)

(48
)
Other utility revenues

89

124

Total AEL&P

12,821

12,202

Other revenues

189

823

Total operating revenues

$
412,870

$
390,230

~~Table of Contents~~

~~AVISTA CORPORATION~~

Utility Revenue from Contracts with Customers by Type and Service

The following table disaggregates revenue from contracts with customers associated with the Company's electric operations for the three and nine months ended ~~March 31~~September 30 (dollars in thousands):

	2021						2020
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility		2021						2020
Three months ended March 31,
													Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
Three months ended September 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	113,223	$	6,048	$	119,271	$	107,977	$	5,866	$	113,843	$	94,803	$	3,080	$	97,883	$	85,494	$	3,150	$	88,644
Commercial and governmental		76,284		4,772		81,056		78,849		6,199		85,048
Commercial														86,228		5,920		92,148		79,242		5,582		84,824
Industrial		24,711		1,899		26,610		24,711		0		24,711		28,843		0		28,843		28,472		0		28,472
Public street and highway lighting		1,852		60		1,912		1,783		61		1,844		1,877		65		1,942		1,845		65		1,910
Total retail revenue		216,070		12,779		228,849		213,320		12,126		225,446		211,751		9,065		220,816		195,053		8,797		203,850
Transmission		3,495		0		3,495		3,774		0		3,774		7,372		0		7,372		5,938		0		5,938
Other revenue from contracts with customers		6,140		0		6,140		5,289		0		5,289		11,610		0		11,610		4,551		0		4,551
Total electric revenue from contracts with customers	$	225,705	$	12,779	$	238,484	$	222,383	$	12,126	$	234,509	$	230,733	$	9,065	$	239,798	$	205,542	$	8,797	$	214,339
Nine months ended September 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential													$	292,714	$	13,379	$	306,093	$	272,231	$	13,236	$	285,467
Commercial														243,370		18,768		262,138		226,876		17,479		244,355
Industrial														80,983		0		80,983		77,999		0		77,999
Public street and highway lighting														5,598		184		5,782		5,474		185		5,659
Total retail revenue														622,665		32,331		654,996		582,580		30,900		613,480
Transmission														15,668		0		15,668		14,121		0		14,121
Other revenue from contracts with customers														24,282		0		24,282		13,256		0		13,256
Total electric revenue from contracts with customers													$	662,615	$	32,331	$	694,946	$	609,957	$	30,900	$	640,857

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AVISTA CORPORATION

The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the three and nine months ended ~~March 31~~September 30 (dollars in thousands):


	Three months ended September 30,				Nine months ended September 30,
	2021		2020		2021		2020
	Avista Utilities		Avista Utilities		Avista Utilities		Avista Utilities
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	21,197	$	20,835	$	142,401	$	139,833
Commercial		10,055		9,340		65,428		62,883
Industrial and interruptible		1,477		1,538		5,520		5,276
Total retail revenue		32,729		31,713		213,349		207,992
Transportation		1,921		1,656		6,177		5,747
Other revenue from contracts with customers		1,406		1,125		3,937		3,375
Total natural gas revenue from contracts with customers	$	36,056	$	34,494	$	223,463	$	217,114

Avista Corp. 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 Corp. utilizes derivative instruments, such as forwards, futures, swap derivatives and options, in order to manage the various risks relating to these commodity price exposures. Avista Corp. has an energy resources risk policy and control procedures to manage these risks.

As part of Avista Corp.'s resource procurement and management operations in the electric business, Avista Corp. engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve Avista Corp.'s load obligations and the use of these resources to capture available economic value through wholesale market transactions. These include sales and purchases of 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 load obligations and hedging a portion of the related financial risks. These transactions range from terms of intra-hour up to multiple years.

As part of its resource procurement and management of its natural gas business, Avista Corp. 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 Corp.’s distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, Avista Corp. plans and executes a series of transactions to hedge a portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as three natural gas operating years (November through October) into the future. Avista Corp. also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.

Avista Corp. plans for sufficient natural gas delivery capacity to serve its retail customers for a theoretical peak day event. Avista Corp. generally has more pipeline and storage capacity than what is needed during periods other than a peak-day. Avista Corp. optimizes its natural gas resources by using market opportunities to generate economic value that mitigates the fixed costs. Avista Corp. also optimizes its natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower, typically in the summer, and withdrawing during higher priced months, typically during the winter. However, if market conditions and prices indicate that Avista Corp. should buy or sell natural gas at other times during the year, Avista Corp. engages in optimization transactions to capture value in the marketplace. Natural gas optimization activities include, but are not limited to, wholesale market sales of surplus natural gas supplies, purchases and sales of natural gas to optimize use of pipeline and storage capacity, and participation in the transportation capacity release market.

The following table presents the underlying energy commodity derivative volumes as of ~~March 31,~~September 30, 2021 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):


	Purchases								Sales								Purchases								Sales
	Electric Derivatives				Gas Derivatives				Electric Derivatives				Gas Derivatives				Electric Derivatives				Gas Derivatives				Electric Derivatives				Gas Derivatives
Year	Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs		Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs		Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs		Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs
Remainder 2021		3		92		7,434		48,028		40		754		8,045		29,520		0		31		4,891		24,320		18		103		2,587		13,033
2022		0		0		450		29,345		0		0		1,360		12,950		123		0		2,250		52,353		216		370		2,260		28,898
2023		0		0		0		6,920		0		0		1,360		1,970		0		0		0		18,825		0		0		1,360		7,060
2024		0		0		0		0		0		0		1,370		0		0		0		0		2,275		0		0		1,370		0
2025		0		0		0		0		0		0		1,115		0		0		0		0		0		0		0		1,115		0

As of ~~March 31,~~September 30, 2021, there are 0 expected deliveries of energy commodity derivatives after ~~2025.~~2025.

The following table presents the underlying energy commodity derivative volumes as of December 31, 2020 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 (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs
2021		1		224		10,353		65,188		17		451		5,448		39,273
2022		0		0		450		25,525		0		0		1,360		12,030
2023		0		0		0		4,950		0		0		1,360		900
2024		0		0		0		0		0		0		1,370		0
2025		0		0		0		0		0		0		1,115		0

Purchases

Sales

Electric Derivatives

Gas Derivatives

Electric Derivatives

Gas Derivatives

Year

Physical
(1)
MWh

Financial
(1)
MWh

Physical
(1)
mmBTUs

Financial
(1)
mmBTUs

Physical
(1)
MWh

Financial
(1)
MWh

Physical
(1)
mmBTUs

Financial
(1)
mmBTUs

2021

1

224

10,353

65,188

17

451

5,448

39,273

2022

0

0

450

25,525

0

0

1,360

12,030

2023

0

0

0

4,950

0

0

1,360

900

2024

0

0

0

0

0

0

1,370

0

2025

0

0

0

0

0

0

1,115

0

As of December 31, 2020, there are 0 expected deliveries of energy commodity derivatives after ~~2025.~~2025.

(1)

Physical transactions represent commodity transactions in which Avista Corp. will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts.

~~(1)~~

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~~AVISTA CORPORATION~~

The electric and natural gas derivative contracts above will be included in either power supply costs or natural gas supply costs during the period they are scheduled to be delivered and will be included in the various deferral and 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 Derivatives

A significant portion of Avista Corp.’s 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 Corp.’s short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices. The short-term natural gas transactions are settled within 60 days with U.S. dollars. Avista Corp. hedges a portion of the foreign currency risk by purchasing Canadian currency exchange derivatives when such commodity transactions are initiated. The foreign currency exchange derivatives and the unhedged foreign currency risk have not had a material effect on Avista Corp.’s financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking.

The following table summarizes the foreign currency exchange derivatives that Avista Corp. has outstanding as of ~~March 31,~~September 30, 2021 and December 31, 2020 (dollars in thousands):


	March 31, 2021		December 31, 2020		September 30, 2021		December 31, 2020
Number of contracts		25		22		22		22
Notional amount (in United States dollars)	$	4,916	$	3,860	$	7,692	$	3,860
Notional amount (in Canadian dollars)		6,178		4,949		9,739		4,949

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AVISTA CORPORATION

Interest Rate Swap Derivatives

Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. Avista Corp. hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate swap derivatives and U.S. Treasury lock agreements. These interest rate swap derivatives and U.S. Treasury lock agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances.

The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. has outstanding as of ~~March 31,~~September 30, 2021 and December 31, 2020 (dollars in thousands):


Balance Sheet Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date
March 31, 2021		4		45,000	2021
September 30, 2021							13	$	140,000	2022
		12		130,000	2022		2		20,000	2023
		1		10,000	2023		1		10,000	2024
December 31, 2020		4		45,000	2021		4	$	45,000	2021
		11		120,000	2022		11		120,000	2022
		1		10,000	2023		1		10,000	2023

The fair value of outstanding interest rate swap derivatives can vary significantly from period to period depending on the total notional amount of swap derivatives outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. Avista Corp. is required to make cash payments to settle the interest rate swap derivatives when the fixed rates are higher than prevailing market rates at the date of settlement. Conversely, Avista Corp. receives cash to settle its interest rate swap derivatives when prevailing market rates at the time of settlement exceed the fixed swap rates.

Summary of Outstanding Derivative Instruments

The amounts recorded on the Condensed Consolidated Balance Sheet as of ~~March 31,~~September 30, 2021 and December 31, 2020 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.

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~~AVISTA CORPORATION~~

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of ~~March 31,~~September 30, 2021 (in thousands):


	Fair Value										Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet			Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current liabilities	$	0	$	(22	)	$	0	$	(22	)	$	0	$	(86	)	$	0	$	(86	)
Interest rate swap derivatives
Other current assets		1,743		0			0		1,743
Other property and investments-net and other non-current assets		4,613		(3,820	)		0		793			2,477		0			0		2,477
Other current liabilities		0		(10,978	)		3,910		(7,068	)		2,072		(20,732	)		0		(18,660	)
Other non-current liabilities and deferred credits		1,264		(5,525	)		0		(4,261	)
Energy commodity derivatives
Other current assets		749		(24	)		0		725			49,933		(42,664	)		0		7,269
Other property and investments-net and other non-current assets		2,598		(1,136	)		0		1,462			12,587		(5,895	)		0		6,692
Other current liabilities		17,458		(21,820	)		2,786		(1,576	)		12,539		(30,933	)		12,343		(6,051	)
Other non-current liabilities and deferred credits		95		(4,793	)		0		(4,698	)		108		(5,688	)		0		(5,580	)
Total derivative instruments recorded on the balance sheet	$	28,520	$	(48,118	)	$	6,696	$	(12,902	)	$	79,716	$	(105,998	)	$	12,343	$	(13,939	)

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AVISTA CORPORATION

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2020 (in thousands):


	Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current assets	$	30	$	0		$	0	$	30
Interest rate swap derivatives
Other current liabilities		0		(19,575	)		8,050		(11,525	)
Other non-current liabilities and deferred credits		952		(32,190	)		0		(31,238	)
Energy commodity derivatives
Other current assets		9,203		(8,306	)		0		897
Other property and investments-net and other non-current assets		1,755		(1,159	)		0		596
Other current liabilities		11,037		(14,007	)		487		(2,483	)
Other non-current liabilities and deferred credits		1,725		(8,043	)		129		(6,189	)
Total derivative instruments recorded on the balance sheet	$	24,702	$	(83,280	)	$	8,666	$	(49,912	)

Exposure to Demands for Collateral

Avista Corp.'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 Avista Corp.'s credit ratings or changes in market prices, additional collateral may be required. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against Avista Corp.'s credit facilities and cash. Avista Corp. actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements.

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~~AVISTA CORPORATION~~

The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of ~~March 31,~~September 30, 2021 and December 31, 2020 (in thousands):


	September 30,		December 31,
	2021		2020
Energy commodity derivatives
Cash collateral posted	$	22,947	$	4,953
Letters of credit outstanding		21,500		23,500
Balance sheet offsetting		12,343		616
Interest rate swap derivatives
Cash collateral posted (offset by net derivative positions)		0		8,050

March 31,

December 31,

2021

2020

Energy commodity derivatives

Cash collateral posted

$
7,596

$
4,953

Letters of credit outstanding

12,500

23,500

Balance sheet offsetting

2,786

616

Interest rate swap derivatives

Cash collateral posted (offset by net derivative positions)

3,910

8,050

Certain of Avista Corp.’s derivative instruments contain provisions that require Avista Corp. to maintain an "investment grade" credit rating from the major credit rating agencies. If Avista Corp.’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 following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral Avista Corp. could be required to post as of ~~March 31,~~September 30, 2021 and December 31, 2020 (in thousands):


	September 30,		December 31,
	2021		2020
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features		20,732		50,813
Additional collateral to post		20,732		42,763

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AVISTA CORPORATION

March 31,

December 31,

2021

2020

Interest rate swap derivatives

Liabilities with credit-risk-related contingent features

14,956

50,813

Additional collateral to post

11,046

42,763

NOTE 6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Avista Utilities

Avista Utilities’ maintained the same pension and other postretirement plans during the ~~three~~nine months ended ~~March 31,~~September 30, 2021 as those described as of December 31, 2020. 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 ~~$14~~$42 million in cash to the pension plan for the ~~three~~nine months ended ~~March 31,~~September 30, 2021, ~~and~~the full amount it expects to contribute ~~$42 million~~ in 2021.

The Company uses a December 31 measurement date for its defined benefit 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 ~~March 31~~September 30 (dollars in thousands):

	Pension Benefits						Other Postretirement Benefits
	2021			2020			2021			2020			Pension Benefits						Other Postretirement Benefits
													2021			2020			2021			2020
Three months ended September 30:
Service cost	$	6,246		$	5,546		$	1,008		$	979		$	6,412		$	5,549		$	1,062		$	982
Interest cost		6,580			6,971			1,376			1,515			6,528			6,968			1,305			1,524
Expected return on plan assets		(9,775	)		(9,125	)		(675	)		(630	)		(9,835	)		(8,625	)		(509	)		(590	)
Amortization of prior service cost		75			75			(275	)		(275	)		75			75			(275	)		(275	)
Net loss recognition		1,823			1,654			1,173			1,243			1,592			1,678			777			1,243
Net periodic benefit cost	$	4,949		$	5,121		$	2,607		$	2,832		$	4,772		$	5,645		$	2,360		$	2,884
Nine months ended September 30:
Service cost													$	18,912		$	16,645		$	2,967		$	2,941
Interest cost														19,638			20,906			3,990			4,563
Expected return on plan assets														(29,314	)		(26,375	)		(1,967	)		(1,810	)
Amortization of prior service cost														225			225			(825	)		(825	)
Net loss recognition														5,103			5,011			3,196			3,729
Net periodic benefit cost													$	14,564		$	16,412		$	7,361		$	8,598

Total service costs in the table above are recorded to the same accounts as labor expense. Labor and benefits expense is recorded to various projects based on whether the work is a capital project or an operating expense. Approximately 40 percent of all labor and benefits is capitalized to utility property and 60 percent is expensed to utility other operating expenses.

The non-service portion of costs in the table above are recorded to other expense below income from operations in the Condensed Consolidated Statements of Income or capitalized as a regulatory asset. Approximately 40 percent of the costs are capitalized to regulatory assets and 60 percent is expensed to the income statement.

AEL&P has a committed line of credit in the amount of ~~$25.0~~$25.0 million that expires in November ~~2024. As~~2024. There were 0 borrowings as of ~~March 31,~~September 30, 2021 and $1.0 million as of December 31, 2020, ~~there were borrowings of $0 and $1.0 million, respectively,~~ and there were 0 letters of credit outstanding under this committed line of ~~credit.~~credit as of September 30, 2021 and December 31, 2020. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the committed line of credit.

NOTE ~~11.~~12. 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 and material ~~capital~~finance leases) and long-term debt to affiliated trusts are reported at their carrying value on the Condensed Consolidated Balance ~~Sheets.~~Sheets, which may be different from the estimated fair value. See below for the estimated fair value of long-term debt and long-term debt to affiliated trusts.

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 fair values derived from 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.

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~~AVISTA CORPORATION~~

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, but 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 ~~March 31,~~September 30, 2021 and December 31, 2020 (dollars in thousands):


	September 30, 2021				December 31, 2020
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	963,500	$	1,162,759	$	963,500	$	1,189,824
Long-term debt (Level 3)		1,130,000		1,263,916		1,060,000		1,235,248
Snettisham finance lease obligation (Level 3)		49,549		55,000		51,750		58,700
Long-term debt to affiliated trusts (Level 3)		51,547		43,815		51,547		43,815

March 31, 2021

December 31, 2020

Carrying
Value

Estimated
Fair Value

Carrying
Value

Estimated
Fair Value

Long-term debt (Level 2)

$
963,500

$
1,129,375

$
963,500

$
1,189,824

Long-term debt (Level 3)

1,060,000

1,081,300

1,060,000

1,235,248

Snettisham finance lease obligation (Level 3)

51,016

51,000

51,750

58,700

Long-term debt to affiliated trusts (Level 3)

51,547

43,815

51,547

43,815

These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The price ranges obtained from the third party brokers consisted of ~~par values~~market prices of 85.00 percent to ~~136.39,~~139.35 percent of the principal

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AVISTA CORPORATION

amount, where a ~~par value~~market price of 100.0 percent (adjusted for unamortized discount or premium) represents the carrying value recorded on the Condensed Consolidated Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices; however, due to their limited trading activity, they are classified as Level 2 because brokers must generate quotes and make estimates if there is no trading activity near a period end. Level 3 long-term debt consists of private placement bonds and debt to affiliated trusts, which typically have no secondary trading activity. Fair values in Level 3 are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for Avista Corp. bonds. Due to the unique nature of the Snettisham finance lease obligation, the estimated fair value of these items was determined based on a discounted cash flow model using available market information. The Snettisham finance lease obligation was discounted to present value using the Morgan Markets A Ex-Fin discount rate as published on ~~March 31,~~September 30, 2021 and December 31, 2020.

~~Table of Contents~~

~~AVISTA CORPORATION~~

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 ~~March 31,~~September 30, 2021 and December 31, 2020 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, 2021
Assets:
Energy commodity derivatives	$	0	$	75,059	$	0	$	(61,098	)	$	13,961
Level 3 energy commodity derivatives:
Natural gas exchange agreement		0		0		108		(108	)		0
Interest rate swap derivatives		0		4,549		0		(2,072	)		2,477
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		1,888		0		0		0			1,888
Equity securities (2)		7,916		0		0		0			7,916
Total	$	9,804	$	79,608	$	108	$	(63,278	)	$	26,242
Liabilities:
Energy commodity derivatives	$	0	$	74,023	$	0	$	(73,441	)	$	582
Level 3 energy commodity derivatives:
Natural gas exchange agreement		0		0		11,157		(108	)		11,049
Foreign currency exchange derivatives		0		86		0		0			86
Interest rate swap derivatives		0		20,732		0		(2,072	)		18,660
Total	$	0	$	94,841	$	11,157	$	(75,621	)	$	30,377
December 31, 2020
Assets:
Energy commodity derivatives	$	—	$	23,645	$	—	$	(22,152	)	$	1,493
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		75		(75	)		—
Foreign currency exchange derivatives		—		30		—		—			30
Interest rate swap derivatives		—		952		—		(952	)		—
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		2,471		—		—		—			2,471
Equity securities (2)		6,228		—		—		—			6,228
Total	$	8,699	$	24,627	$	75	$	(23,179	)	$	10,222
Liabilities:
Energy commodity derivatives	$	—	$	23,030	$	—	$	(22,768	)	$	262
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		8,485		(75	)		8,410
Interest rate swap derivatives		—		51,765		—		(9,002	)		42,763
Total	$	—	$	74,795	$	8,485	$	(31,845	)	$	51,435

Level 1

Level 2

Level 3

Counterparty
and Cash
Collateral
Netting (1)

Total

March 31, 2021

Assets:

Energy commodity derivatives

$
—

$
20,805

$
—

$
(18,618
)

$
2,187

Level 3 energy commodity derivatives:

Natural gas exchange agreement

—

—

95

(95
)

—

Interest rate swap derivatives

—

7,620

—

(5,084
)

2,536

Deferred compensation assets:

Mutual Funds:

Fixed income securities (2)

2,154

—

—

—

2,154

Equity securities (2)

7,115

—

—

—

7,115

Total

$
9,269

$
28,425

$
95

$
(23,797
)

$
13,992

Liabilities:

Energy commodity derivatives

$
—

$
21,477

$
—

$
(21,404
)

$
73

Level 3 energy commodity derivatives:

Natural gas exchange agreement

—

—

6,296

(95
)

6,201

Foreign currency exchange derivatives

—

22

—

—

22

Interest rate swap derivatives

—

20,323

—

(8,994
)

11,329

Total

$
—

$
41,822

$
6,296

$
(30,493
)

$
17,625

December 31, 2020

Assets:

Energy commodity derivatives

$
—

$
23,645

$
—

$
(22,152
)

$
1,493

Level 3 energy commodity derivatives:

Natural gas exchange agreement

—

—

75

(75
)

—

Foreign currency exchange derivatives

—

30

—

—

30

Interest rate swap derivatives

—

952

—

(952
)

—

Deferred compensation assets:

Mutual Funds:

Fixed income securities (2)

2,471

—

—

—

2,471

Equity securities (2)

6,228

—

—

—

6,228

Total

$
8,699

$
24,627

$
75

$
(23,179
)

$
10,222

Liabilities:

Energy commodity derivatives

$
—

$
23,030

$
—

$
(22,768
)

$
262

Level 3 energy commodity derivatives:

Natural gas exchange agreement

—

—

8,485

(75
)

8,410

Interest rate swap derivatives

—

51,765

—

(9,002
)

42,763

Total

$
—

$
74,795

$
8,485

$
(31,845
)

$
51,435

~~(1)~~26

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 included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.~~

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AVISTA CORPORATION

(1)

(2)

These assets are included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.

The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 5 for additional discussion of derivative netting.

To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate the fair value of energy commodity derivative instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange pricing for similar instruments, adjusted for basin differences, using market quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2.

To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness, with consideration given to the potential non-performance risk by the Company. Future cash flows of the interest rate swap derivatives are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period.

To establish fair value for foreign currency derivatives, the Company uses forward market curves for Canadian dollars against the US dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative. Forward foreign currency market curves are provided by third party brokers. The Company's credit spread is factored into the locked-in price of the foreign exchange contracts.

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 ~~$0.2~~$0.1 million and ~~$0.5~~$0.5 million as of ~~March 31,~~September 30, 2021 and December 31, 2020, respectively.

Level 3 Fair Value

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 ~~March 31,~~September 30, 2021 (dollars in thousands):


	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	September 30, 2021			Technique	Input	Average Price
Natural gas exchange agreement	$	(11,049	)	Internally derived weighted average cost of gas	Forward purchase	$2.41 - $3.83/mmBTU $2.92 Weighted Average
					Forward sales prices	$2.40 - $8.25/mmBTU $4.96 Weighted Average
					Purchase volumes	130,000 - 310,000 mmBTUs
					Sales volumes	75,000 - 310,000 mmBTUs

Fair Value
(Net) at

Valuation

Unobservable

Range and Weighted

March 31, 2021

Technique

Input

Average Price
Natural gas exchange agreement

$
(6,201
)

Internally derived weighted average cost of gas

Forward purchase

$1.84 - $2.85/mmBTU
$2.21 Weighted Average

Forward sales prices

$1.90 - $4.25/mmBTU
$3.53 Weighted Average

Purchase volumes

130,000 - 310,000 mmBTUs

Sales volumes

75,000 - 310,000 mmBTUs

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AVISTA CORPORATION

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 ~~March 31~~September 30 (dollars in thousands):

Natural Gas
Exchange
Agreement

Three months ended March 31, 2021:

Balance as of January 1, 2021

$
(8,410
)
Total gains (realized/unrealized):

Included in regulatory assets/liabilities (1)

3,220

Settlements

(1,011
)
Ending balance as of March 31, 2021 (2)

$
(6,201
)
Three months ended March 31, 2020:

Balance as of January 1, 2020

$
(2,976
)
Total gains (realized/unrealized):

Included in regulatory assets/liabilities (1)

485

Settlements

238

Ending balance as of March 31, 2020 (2)

$
(2,253
)


		Natural Gas Exchange Agreement
Three months ended September 30, 2021:
Balance as of June 30, 2021		$	(6,078	)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1)	All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net income or other comprehensive income during any of the periods presented in the table above.		(4,971	)

Settlements			0
Ending balance as of September 30, 2021 (2)	~~There were no purchases, issuances~~	$	(11,049	)
Three months ended September 30, 2020:
Balance as of June 30, 2020		$	(2,628	)
Total gains or ~~transfers from other categories~~(losses) (realized/unrealized):
Included in regulatory assets/liabilities (1)			(1,046	)
Settlements			0
Ending balance as of ~~any derivatives instruments during the periods presented~~September 30, 2020 (2)		$	(3,674	)
Nine months ended September 30, 2021:
Balance as of December 31, 2020		$	(8,410	)
Total gains (realized/unrealized):
Included in ~~the table above.~~regulatory assets/liabilities (1)			(1,482	)
Settlements			(1,157	)
Ending balance as of September 30, 2021 (2)		$	(11,049	)
Nine months ended September 30, 2020:
Balance as of December 31, 2019		$	(2,976	)
Total gains (realized/unrealized):
Included in regulatory assets/liabilities (1)			(952	)
Settlements			254
Ending balance as of September 30, 2020 (2)		$	(3,674	)

(1)

All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net income or other comprehensive income during any of the periods presented in the table above.

(2)

There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented in the table above.

NOTE ~~12.~~13. COMMON STOCK

~~The Company has authority to issue a maximum of approximately 3.2 million shares under its sales agency agreements, of which approximately 1.3 million shares remain unissued as of March 31, 2021.~~ The Company has board ~~authority,~~ and ~~has requested~~ regulatory authority to issue ~~3.0~~3.9 million shares of common stock in ~~addition to~~public offerings. Of this number, the ~~1.3~~Company issued 1.1 million shares ~~previously authorized but remaining unissued. During~~and 1.4 million shares during the three and nine months ended ~~March 31,~~September 30, 2021, ~~and March 31, 2020, the Company did 0t issue shares~~respectively, under the sales agency ~~agreements.~~agreements relating to the Company's periodic offering program, leaving 2.5 million shares authorized to be issued.

NOTE ~~13.~~14. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss, net of tax, consisted of the following as of ~~March 31,~~September 30, 2021 and December 31, 2020 (dollars in thousands):


	September 30, 2021		December 31, 2020
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $3,575 and $3,822, respectively	$	13,451	$	14,378

March 31,
2021

December 31,
2020

Unfunded benefit obligation for pensions and other postretirement benefit plans -
net of taxes of $3,738 and $3,822, respectively

$
14,063

$
14,378

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AVISTA CORPORATION

The following table details the reclassifications out of accumulated other comprehensive loss to net income by component for the three and nine months ended ~~March 31~~September 30 (dollars in thousands):


	Amounts Reclassified from Accumulated Other Comprehensive Loss
	Three months ended September 30,						Nine months ended September 30,
Details about Accumulated Other Comprehensive Loss Components (Affected Line Item in Statement of Income)	2021			2020			2021			2020
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (a)	$	(200	)	$	(200	)	$	(600	)	$	(600	)
Amortization of net loss (a)		2,369			3,120			8,299			9,341
Adjustment due to effects of regulation (a)		(1,784	)		(2,642	)		(6,525	)		(7,925	)
Total before tax (b)		385			278			1,174			816
Tax expense (b)		(81	)		(58	)		(247	)		(171	)
Net of tax (b)	$	304		$	220		$	927		$	645

Amounts Reclassified from Accumulated Other
Comprehensive Loss
Details about Accumulated Other Comprehensive Loss Components
(Affected Line Item in Statement of Income)

2021

2020

Amortization of defined benefit pension items

Amortization of net prior service cost (a)

$
(200
)

$
(200
)

Amortization of net loss (a)

3,191

3,100

Adjustment due to effects of regulation (a)

(2,592
)

(2,641
)

Total before tax (b)

399

259

Tax expense (b)

(84
)

(54
)

Net of tax (b)

$
315

$
205

(a)

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

~~(a)~~

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

(b)

Description is also the affected line item on the Condensed Consolidated Statement of Income.

~~(b)~~

~~Description is also the affected line item on the Condensed Consolidated Statement of Income.~~

NOTE ~~14.~~15. EARNINGS PER COMMON SHARE

The following table presents the computation of basic and diluted earnings per common share for the three and nine months ended ~~March 31~~September 30 (in thousands, except per share amounts):


					Three months ended September 30,				Nine months ended September 30,
	2021		2020		2021		2020		2021		2020
Numerator:
Net income	$	68,017	$	48,424	$	14,366	$	4,876	$	96,457	$	70,753
Denominator:
Weighted-average number of common shares outstanding-basic		69,293		67,239		70,054		68,194		69,582		67,638
Effect of dilutive securities:
Performance and restricted stock awards		213		142		75		143		140		131
Weighted-average number of common shares outstanding-diluted		69,506		67,381		70,129		68,337		69,722		67,769
Earnings per common share:
Basic	$	0.98	$	0.72	$	0.21	$	0.07	$	1.39	$	1.05
Diluted	$	0.98	$	0.72	$	0.20	$	0.07	$	1.38	$	1.04

There were 0 shares excluded from the calculation because they were antidilutive.

NOTE ~~16.~~17. 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). 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; therefore, it is considered one segment. AEL&P is a separate reportable business segment, as it has separate financial reports that are reviewed in detail by the Chief Operating Decision Maker and its operations and risks are sufficiently different from Avista Utilities and the other businesses at AERC that it cannot be aggregated with any other operating segments. The Other category, which is not a reportable segment, includes other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital.

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AVISTA CORPORATION

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


	Avista Utilities			Alaska Electric Light and Power Company		Total Utility			Other			Intersegment Eliminations (1)			Total
For the three months ended September 30, 2021:
Operating revenues	$	286,752		$	9,147	$	295,899		$	108		$	0		$	296,007
Resource costs		101,109			1,024		102,133			0			0			102,133
Other operating expenses		82,006			3,619		85,625			843			0			86,468
Depreciation and amortization		55,039			2,683		57,722			30			0			57,752
Income (loss) from operations		23,416			1,563		24,979			(765	)		0			24,214
Interest expense (2)		25,015			1,523		26,538			132			(21	)		26,649
Income taxes		(6,371	)		18		(6,353	)		921			0			(5,432	)
Net income		9,086			41		9,127			5,239			0			14,366
Capital expenditures (3)		107,519			1,462		108,981			373			0			109,354
For the three months ended September 30, 2020:
Operating revenues	$	263,564		$	8,815	$	272,379		$	267		$	0		$	272,646
Resource costs		77,843			942		78,785			0			0			78,785
Other operating expenses		82,151			3,400		85,551			1,697			0			87,248
Depreciation and amortization		51,499			2,454		53,953			146			0			54,099
Income (loss) from operations		28,284			1,790		30,074			(1,576	)		0			28,498
Interest expense (2)		24,277			1,561		25,838			131			(29	)		25,940
Income taxes		1,060			59		1,119			(260	)		0			859
Net income (loss)		5,546			268		5,814			(938	)		0			4,876
Capital expenditures (3)		105,494			2,860		108,354			803			0			109,157
For the nine months ended September 30, 2021:
Operating revenues	$	974,172		$	32,515	$	1,006,687		$	445		$	0		$	1,007,132
Resource costs		324,464			2,926		327,390			0			0			327,390
Other operating expenses		257,333			9,900		267,233			3,186			0			270,419
Depreciation and amortization		161,332			7,677		169,009			230			0			169,239
Income (loss) from operations		149,670			11,162		160,832			(2,971	)		0			157,861
Interest expense (2)		74,423			4,571		78,994			392			(87	)		79,299
Income taxes		4,932			1,819		6,751			2,379			0			9,130
Net income		80,861			4,816		85,677			10,780			0			96,457
Capital expenditures (3)		318,354			4,454		322,808			938			0			323,746
For the nine months ended September 30, 2020:
Operating revenues	$	909,109		$	31,014	$	940,123		$	1,345		$	0		$	941,468
Resource costs		274,468			1,829		276,297			0			0			276,297
Other operating expenses		256,570			9,681		266,251			3,716			0			269,967
Depreciation and amortization		161,934			7,348		169,282			569			0			169,851
Income (loss) from operations		137,219			11,337		148,556			(2,939	)		0			145,617
Interest expense (2)		73,449			4,709		78,158			393			(161	)		78,390
Income taxes		460			1,840		2,300			(828	)		0			1,472
Net income (loss)		69,130			4,991		74,121			(3,368	)		0			70,753
Capital expenditures (3)		291,417			6,417		297,834			1,389			0			299,223
Total Assets:
As of September 30, 2021:	$	6,345,036		$	269,061	$	6,614,097		$	123,355		$	(5,974	)	$	6,731,478
As of December 31, 2020:	$	6,035,340		$	268,971	$	6,304,311		$	109,658		$	(11,872	)	$	6,402,097

Avista
Utilities

Alaska
Electric
Light and
Power
Company

Total Utility

Other

Intersegment
Eliminations
(1)

Total

For the three months ended March 31, 2021:

Operating revenues

$
399,860

$
12,821

$
412,681

$
189

$
0

$
412,870

Resource costs

133,840

739

134,579

0

0

134,579

Other operating expenses

84,599

2,956

87,555

1,184

0

88,739

Depreciation and amortization

52,724

2,497

55,221

127

0

55,348

Income (loss) from operations

96,693

6,324

103,017

(1,122
)

0

101,895

Interest expense (2)

24,800

1,525

26,325

129

(41
)

26,413

Income taxes

10,718

1,333

12,051

113

0

12,164

Net income

64,058

3,476

67,534

483

0

68,017

Capital expenditures (3)

96,394

809

97,203

28

0

97,231

For the three months ended March 31, 2020:

Operating revenues

$
377,205

$
12,202

$
389,407

$
823

$
0

$
390,230

Resource costs

129,557

(10
)

129,547

0

0

129,547

Other operating expenses

91,279

3,217

94,496

1,360

0

95,856

Depreciation and amortization

48,974

2,447

51,421

235

0

51,656

Income (loss) from operations

76,534

6,246

82,780

(587
)

0

82,193

Interest expense (2)

24,983

1,589

26,572

131

(86
)

26,617

Income taxes

7,404

1,301

8,705

(173
)

0

8,532

Net income (loss)

45,979

3,395

49,374

(950
)

0

48,424

Capital expenditures (3)

94,056

1,470

95,526

109

0

95,635

Total Assets:

As of March 31, 2021:

$
6,031,502

$
270,554

$
6,302,056

$
110,117

$
(12,677
)

$
6,399,496

As of December 31, 2020:

$
6,035,340

$
268,971

$
6,304,311

$
109,658

$
(11,872
)

$
6,402,097

(1)

Intersegment eliminations reported as interest expense represent intercompany interest.

(2)

Including interest expense to affiliated trusts.

(3)

The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows.

We have reviewed the accompanying condensed consolidated balance sheet of Avista Corporation and subsidiaries (the "Company") as of ~~March 31,~~September 30, 2021, the related condensed consolidated statements of income, comprehensive income, and equity for the three-month and nine-month periods ended September 30, 2021 and 2020, and of cash flows for the ~~three-month~~nine-month periods ended ~~March 31,~~September 30, 2021 and 2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2020, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the year then ended (not presented herein); and in our report dated February 23, 2021, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

This interim financial information is the responsibility of the Company's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

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

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations has been prepared in accordance with the SEC’s Regulation S-K for interim financial information and with the instructions to Form 10-Q. This Management’s Discussion and Analysis of Financial Condition and Results of Operations does not contain the full detail or analysis that would accompany financial statements for a full fiscal year; therefore, it should be read in conjunction with the Company's 2020 Form 10-K.

Our business segments have not changed during the ~~three~~nine months ended ~~March 31,~~September 30, 2021. See the 2020 Form 10-K as well as “Note 1617 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.

The following table presents net income for each of our business segments (and the other businesses) for the three and nine months ended ~~March 31~~September 30 (dollars in thousands):

~~Avista Utilities' net~~Net income for the three months ended ~~March 31,~~September 30, 2021 increased compared to the three months ended ~~March 31,~~September 30, 2020 primarily due to increased net income at our other businesses, and timing of recognition of income taxes. These items were partially offset by higher power supply costs and a $2.5 million write off of Colstrip SmartBurn assets disallowed in the Washington general rate case. Net income for the nine months ended September 30, 2021 increased compared to 2020 primarily due to an increase in utility margin ~~(operating revenues less resource costs)~~ as a result of general rate increases, ~~in Washington~~timing of recognition of income taxes, and ~~Oregon~~non-decoupled revenue growth and customer growth. These increases were partially offset by higher power supply costs. In addition, ~~during~~ the ~~first quarter of~~nine months ended September 30, 2020 ~~we recorded~~included an accrual for customer refunds related to the outcome of ~~the~~our 2015 Washington general rate cases, ~~and~~ an ~~expense~~accrual for disallowed replacement power during an unplanned outage at ~~Colstrip.~~

~~AEL&P net income increased slightly, primarily due to~~Colstrip and a ~~decrease in generation and distribution operating and maintenance costs, which was partially offset by a decrease in margin due to weather that was warmer in the first quarter of 2021 compared~~contribution to the ~~first quarter of 2020.~~Colstrip community fund.

The increase in net income at our other businesses was primarily due to increased earnings from our ~~investments.~~investments during the second and third quarters.

More detailed explanations of the fluctuations are provided in the results of operations and business segment discussions (Avista Utilities, AEL&P, and the other businesses) that follow this section.

The Pacific Northwest experienced hot and dry weather conditions throughout the second and third quarters of 2021 compared to normal weather conditions for this time of year. These weather conditions resulted in higher than usual customer loads, as well as lower than usual hydroelectric generation. In these periods, we often have excess generation to sell into the wholesale markets, which benefits our net power supply costs. This did not occur at expected levels in 2021 primarily due to the hot and dry weather conditions throughout the Pacific Northwest.

As a result of our lower than normal hydroelectric generation capability and in order to serve higher than usual loads, we were required to rely more heavily than usual on purchased power and our thermal generation, which in turn resulted in higher than authorized resource costs due to higher volumes of energy and fuel purchased and higher market prices of each. For the nine-months

ended September 30, 2021 we have recognized a pre-tax expense of $7.1 million under the ERM, compared to a $5.9 million pre-tax benefit recognized in the first nine months of 2020.

These hot conditions had a minimal impact on revenues, as the majority of the increase in revenues associated with increased usage was offset with decoupling revenues due to the decoupling mechanisms that cover a majority of our customers.

The COVID-19 pandemic has impacted our business, as well as the global, national and local economies. However, as we progress ~~into~~through 2021, the economies in our service territory have opened, and we expect ~~an increase in vaccinations and a decrease in COVID-19 cases to make~~ the impacts of the pandemic to be less severe than 2020. This was the ~~prior year.~~ case through the third quarter. The pandemic has affected and may continue to affect our results of operations, financial condition, liquidity and cash flows in the following ways:

During the first quarter of 2021, when compared to normal, we did not experience a material variation in total loads due to COVID-19; however, we did observe increases in residential loads offset by decreases in commercial loads. We expect continued economic recovery and improvement in employment through the remainder of 2021. We have decoupling and other regulatory mechanisms in Washington, Idaho and Oregon, which mitigate the impact of changes in loads and revenues for residential and certain commercial customer classes. Over 90 percent of our utility revenue is covered by regulatory mechanisms.

Customer disconnections for non-payment have resumed in our Washington and Oregon jurisdictions continue to be suspended. In Washington, there is a moratorium on disconnections for residential and commercial customers until July 31, 2021. In Oregon, there is a moratorium on disconnections for residential customers until June 30, 2021.all jurisdictions.

We are offsetting some of the negative impacts of COVID-19 (primarily an increase in bad debt expense) at Avista Utilities with cost savings and benefits from the Coronavirus Aid, Relief, and Economic Security Act. We have received accounting orders in each of our jurisdictions to defer the recognition of COVID-19 expenses as well as identified cost savings of other COVID-19 related benefits. ~~As of March 31, 2021, we have~~COVID-19 deferred a cumulative regulatory ~~asset~~assets and liabilities as of ~~$11.8 million~~September 30, 2021 and ~~a cumulative regulatory liability of $11.6 million for COVID-19 related items among all jurisdictions. As of~~ December 31, 2020 were as follows (dollars in thousands):

Several vaccine mandates have been issued by various governmental entities. To the extent that governmental mandates are applicable to us, we ~~had deferred~~are assessing our options as to how to comply with the mandates while minimizing the impact on our operations. If we mandate vaccines, it could result in a ~~cumulative regulatory asset~~loss of ~~$8.2 million and a cumulative regulatory liability of $10.9 million among all jurisdictions.~~employees which could cause disruption to operations.

~~We do not expect the impact of COVID-19 to change our estimate of utility capital expenditures for 2021 or to have a material impact on our operating cash flows as compared to 2020.~~

After considering the impacts of COVID-19, and the issuances of long-term debt and equity during 2021, we expect net cash flows from operations, together with cash available under our committed lines of credit, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.

We cannot predict the duration and severity of the COVID-19 ~~pandemic.~~pandemic or if emerging variants will result in the reimplementation of economic restrictions. The longer and more severe the economic restrictions and business disruption, the greater the impact on our operations, results of operations, financial condition and cash flows.

We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We expect to continue to file for rate adjustments to:

With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, but are not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items.

In March 2020, we received an order from the WUTC that approved a partial multi-party settlement agreement. The approved rates were designed to increase annual base electric revenues by $28.5 million, or 5.7 percent, and annual natural gas base revenues by $8.0 million, or 8.5 percent, effective April 1, 2020. The revenue increases incorporate a 9.4 percent ~~return on equity (ROE)~~ROE with a common equity ratio of 48.5 percent and a ~~rate of return on rate (ROR) base~~ROR of 7.21 percent.

As part of the WUTC order, we are returning approximately $40 million from the ERM rebate to customers over a two-year period.

Included in the WUTC order iswas the acceleration of depreciation of Colstrip Units 3 & 4 to reflect a remaining useful life through December 31, 2025. The order ~~utilizes~~utilized certain electric tax benefits associated with the 2018 tax reform to partially offset these increased costs. The order also sets aside $3 million for community transition efforts to mitigate the impacts of the eventual closure of Colstrip, half funded by customers and half funded by our shareholders. We recorded this liability and recognized the shareholder portion of the expense in the first quarter of 2020. The funds were issued to the Montana Community Fund in the first quarter of 2021.

Lastly, the order included the extension of electric and natural gas decoupling mechanisms through March 31, 2025, with one modification in that new customers added after any test period will not be decoupled until ~~included~~those customers are embedded in a ~~future~~rate case test ~~period.~~year.

In September 2021, we received an order from the WUTC that approved a partial multi-party settlement agreement and resolved all other remaining issues. The approved rates are designed to increase annual base electric revenues by $13.6 million, or 2.6 percent, and annual natural gas base revenues by $8.1 million, or 7.7 percent, effective October ~~2020, we filed~~1, 2021. The revenue increases are based on a 9.4 percent ROE with a common equity ratio of 48.5 percent and a ROR of 7.12 percent.

While base rates increased, there was no increase in billed rates at this time because of the use of offsetting tax benefits. With the approval of these customer tax credits, the company recognized an adjustment in the third quarter.

The WUTC's order approved recovery of capital additions including investments in advanced metering infrastructure, wildfire resiliency, joining the Western Energy Imbalance Market, and other projects. The WUTC disallowed $2.5 million of costs associated with Colstrip SmartBurn technology.

The WUTC order also approves the Company's request to defer incremental wildfire expenses incurred from January 1, 2021 to September 30, 2021, as well as the Company's use of a wildfire balancing account to track the level of expense associated with wildfire resiliency going forward.

We expect to file multi-year electric and natural gas general rate cases with the ~~WUTC. We have requested an overall increase~~WUTC in ~~base electric revenues~~the first quarter of $44.2 million (or 8.3 percent), which would be entirely offset by a tax credit to customers of the same amount. Additionally, we have requested an overall increase in base natural gas revenues of $12.8 million (or 12.2 percent), which would be entirely offset by a tax credit to customers of the same amount for a period of time. The revenue increases incorporate a 9.9 percent ROE with a common equity ratio of 50 percent and a ROR of 7.43 percent.2022.

Included in our general rate case requests are the recovery of our Advanced Metering Infrastructure (AMI) project costs. AMI project costs represented 42 percent of our electric base rate request and 54 percent of our natural gas base rate request.

This bill, which was ~~passed by the Washington legislature, would aid in transforming the regulation~~signed into law and is effective as of ~~electrical and natural gas companies toward~~July 25, 2021, is designed to promote multi-year rate plans and performance-based rate ~~making.~~making for electric and natural gas utilities. The bill includes ~~the following provisions:~~a number of provisions such as required multi-year rate plans from 2-4 years in length, methodologies the WUTC may use to minimize regulatory lag ~~in the initial year, and each subsequent year~~and/or adjust for under earning

and starts an investigation into Performance Based Ratemaking Metrics, an initial move that may help to modify the ~~historic~~historical test-year ratemaking construct. ~~Ultimately, it~~On October 20, 2021, the WUTC issued a notice of opportunity to comment on a proposed work plan to be conducted in various phases between 2021 and 2025, initially focusing on Performance Based Ratemaking and identifying performance metrics. Thereafter, the WUTC will ~~require commissioners, present~~address revenue adjustment mechanisms and ~~future,~~performance incentives in the context of multi-year rate plans. The new law leaves much to ~~effectuate~~ the ~~change.~~discretion of the WUTC, and we cannot predict the extent to which the WUTC will embrace the options now permitted.

In January 2021, we filed electric and natural gas general rate cases with the IPUC.

In September 2021, the IPUC approved the all party settlement agreement. The ~~proposal is a two-year rate plan, with new~~approved rates ~~taking effect~~under the settlement agreement are designed to increase annual base electric revenues by $10.6 million, or 4.3 percent, effective September 1, 2021, and $8.0 million, or 3.1 percent, effective September 1, 2022. For natural gas, the proposed rates under the settlement agreement are designed to decrease annual base natural gas revenues by $1.6 million, or 3.7 percent, effective September 1, 2021, and increase annual base revenues by $0.9 million, or 2.2 percent, effective September 1, 2022. The parties have agreed to use the customer tax credits, related to flow through of certain tax items, included in our original filing to offset overall proposed changes to electric and natural gas ~~incorporate~~rates over the two-year plan.

The settlement is based on a ~~proposed ROR on rate base of 7.30~~9.4 percent ROE with a common equity ratio of 50 percent and a ~~9.9 percent ROE.~~ROR of 7.05 percent.

Our request, if approved, is designed to increase annual electric base revenues by $24.8 million, or 10.1 percent, effective September 1, 2021 and $8.7 million, or 3.2 percent, effective September 1, 2022. We are proposing to apply a tax credit to customers that would fully offset the increase for September 1, 2021, resulting in no bill change for customers for a period of time. For natural gas, the rate request is designed to increase annual base revenues by $0.05 million, or 0.1 percent effective September 1, 2021 and $1.0 million, or 2.2 percent effective September 1, 2022. The tax credit to customers for natural gas would more than fully offset the September 1, 2021 increase, resulting in a rate reduction for all customers, and would continue for a ten-year period. We are proposing to offset the majority of the increase for the September 1, 2022 rate change with other deferred customer credits.

Through several settlement stipulations the parties resolved all issues in the general rate case and in December 2020, the OPUC approved the settlement stipulations.

These stipulations approved by the OPUC ~~increased~~were designed to increase annual base revenue by $3.9 million, or 5.7 percent, effective January 16, 2021. The approved ROE is 9.4 percent, with a common equity ratio of 50 percent and a ROR of 7.24 percent.

~~We expect to file~~On October 22, 2021, we filed a natural gas general rate case with the OPUC inthat, if approved, would allow us to recover costs for ongoing natural gas infrastructure and other investments without increasing customer bills. The proposal is designed to increase overall natural gas base revenue by $3.8 million and is based on a proposed rate of return of 7.35 percent with a common equity ratio of 50 percent and a 9.9 percent return on equity. We have proposed that the ~~second half~~increase be fully offset for a two-year period with tax customer credits (related to the flow through of ~~2021.~~certain tax items) of the same amount.

AEL&P is required to file ~~its’~~its next general rate case by August 30, 2022.

PGAs are designed to pass through changes in natural gas costs to Avista Utilities' customers with no change in utility margin (operating revenues less resource costs) or net income. In Oregon, we absorb (cost or benefit) 10 percent of the difference between

actual and projected natural gas costs included in retail rates for supply that is not hedged. Total net deferred natural gas costs among all jurisdictions were assets of ~~$3.5~~$14.7 million and $1.4 million as of ~~March 31,~~September 30, 2021 and December 31, 2020, respectively.

The ERM is an accounting method used to track certain differences between Avista Utilities' actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for our Washington customers. Under the ERM, Avista Utilities makes an annual filing on or before April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. See the 2020 Form 10-K for a full discussion of the mechanics of the ERM and the various sharing bands. Total net deferred power costs under the ERM were liabilities of ~~$32.8~~$19.6 million and $37.9 million as of ~~March 31,~~September 30, 2021 and December 31, 2020, respectively. These deferred power cost balances represent amounts due to customers. Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million in the rebate or surcharge direction, we must make a filing with the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers.

The cumulative rebate balance exceeds $30 million and as a result, our 2019 filing contained a proposed rate refund. The ERM proceeding was considered with our 2019 general rate case proceeding and a refund was approved and is being returned to customers over a two-year period that began on April 1, 2020. See further discussion in the section "Washington General Rate Cases" above.

Avista Utilities has a PCA mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were assets of ~~$3.2~~$11.6 million as of ~~March 31,~~September 30, 2021 and $2.5 million as of December 31, 2020. These deferred power cost balances represent amounts due from customers.

Decoupling (also known as an FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of our jurisdictions, Avista Utilities' electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed "normal" kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and "normal" sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only

residential and certain commercial customer classes are included in our decoupling mechanisms. See the 2020 Form 10-K for a discussion of the mechanisms in each jurisdiction.

Total net cumulative decoupling deferrals among all jurisdictions were regulatory assets of ~~$22.0~~$8.7 million as of ~~March 31,~~September 30, 2021 and $21.3 million as of December 31, 2020. These decoupling assets represent amounts due from customers.

See "Results of Operations - Avista Utilities" for further discussion of the amounts recorded to operating revenues in 2021 and 2020 related to the decoupling mechanisms.

The following provides an overview of changes in our Condensed Consolidated Statements of Income. More detailed explanations are provided, particularly for operating revenues and operating expenses, in the business segment discussions (Avista Utilities, AEL&P, and the other businesses) that follow this section.

The balances included below for utility operations reconcile to the Condensed Consolidated Statements of Income.

Three months ended ~~March 31,~~September 30, 2021 compared to the three months ended ~~March 31,~~September 30, 2020

The following graph shows the total change in net income for the ~~first~~third quarter of 2021 compared to the ~~first~~third quarter of 2020, as well as the various factors that caused such change (dollars in millions):

Utility revenues increased at Avista Utilities when compared to the third quarter of 2020. This was primarily due to warmer weather than the third quarter of 2020, customer growth, and reduced COVID-19 restrictions. In addition, utility revenues increased due to general rate increases in Oregon.

Utility resource costs increased at Avista Utilities due to increased purchased power, fuel for generation and other fuel costs, as well as higher natural gas purchases. See "Summer Weather Conditions" in the Executive Level Summary above for further discussion on the increase in net power supply expenses. There was also an increase at AEL&P due to an increase in deferred power supply expenses.

Utility operating expenses slightly increased when compared to the third quarter of 2020. This increase includes $2.5 million of SmartBurn technology assets disallowed for recovery through rates in the Washington 2020 rate case final order. This additional expense was offset by $1.9 million of deferred incremental wildfire expenses incurred from January 1, 2021 to September 30, 2021 as approved by WUTC, as well as a decrease in bad debt expense when compared to the third quarter of 2020. During the third quarter of 2020, we had only received regulatory approval to defer COVID-19 related bad debt expense in our Idaho jurisdiction, whereas we deferred COVID-19 related bad debt expense for Washington and Oregon jurisdictions during the third quarter of 2021.

Utility depreciation and amortization increased primarily due to additions to utility plant.

Income tax expense decreased primarily due to a change in tax methodology to a flow through method, as accepted by IPUC and WUTC through our general rate cases. See “Note 7 of the Notes to Condensed Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate.

The increase in other was primarily related to net investment gains during the third quarter of 2021, compared to net investment losses during the third quarter of 2020.

Nine months ended September 30, 2021 compared to the nine months ended September 30, 2020

The following graph shows the total change in net income for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020, as well as various factors that caused such change (dollars in millions):

Utility revenues increased at Avista Utilities primarily due increased loads from non-decoupled customers as a result of reduced COVID-19 restrictions during the nine months ended September 30, 2021 and weather that was warmer than normal and the prior year. In addition, utility revenues increased due to general rate increases in Washington, Idaho and Oregon and customer growth. During the first ~~quarter~~nine months of 2020, there was a $4.9 million decrease to revenue due to the outcome of the 2015 Washington general rate cases.

Utility resource costs increased at Avista Utilities due to increased purchased power, fuel for generation and other fuel costs, as well as higher natural gas purchases. See "Summer Weather Conditions" in the Executive Level Summary above for further discussion of the increased net power supply costs. There was an increase at AEL&P due to an increase in deferred power supply expenses.

The ~~decrease~~increase in utility operating expenses was primarily due to a decrease in bad debt expense (net of COVID-19 regulatory deferrals in the first quarter of 2021) and an accrual in the first quarter of 2020 for disallowed replacement power during an unplanned outage at Colstrip. The above decreases were partially offset by increases in generation and distribution operating and maintenance costs at Avista ~~Utilities.~~Utilities, as well as a $2.5 million write off of Colstrip SmartBurn technology assets disallowed under the 2020 Washington general rate case. The increases were partially offset by an accrual during the nine months ended September 30, 2020 for disallowed replacement power during an unplanned outage at Colstrip and a decrease in bad debt expense when compared to the nine months ended September 30, 2020. During the first nine months of 2020, we had only received regulatory approval to defer COVID-19 related bad debt expense in our Idaho jurisdiction, whereas we deferred COVID-19 related bad debt expense for all jurisdictions during the first nine months of 2021.

Utility depreciation and amortization ~~increased~~decreased primarily due to a one-time increase to depreciation expense during the first nine months of 2020 as we were able to utilize $10.9 million ($8.4 million when tax-effected) of electric tax benefits to offset costs associated with accelerating the depreciation of Colstrip based on a settlement in Washington. This was mostly offset by additions to utility plant.

38Income taxes increased primarily due to a decrease in tax expense during the nine months ended September 30, 2020 related to the offset of $8.4 million of deferred income taxes against accelerated depreciation for Colstrip based on a settlement in Washington and an increase in pre-tax earnings. This was offset by a change in tax methodology to flow through method for certain items in 2021, as accepted by IPUC and WUTC through our general rate cases. Our effective tax rate was 8.6 percent for the first nine months of 2021

compared to ~~gains on investments recognized during the first quarter of 2021.~~

~~Income taxes increased primarily due to an increase in income before taxes. Our effective tax rate was 15.2~~2.0 percent for the first ~~quarter of 2021 compared to 15.0 percent for the first quarter~~nine months of 2020. See “Note 7 of the Notes to Condensed Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate.

The increase in other was primarily related to net investment gains during the first nine months of 2021, compared to net investment losses during the first nine months of 2020. Additionally, other increased due to the sale of certain subsidiary assets associated with the Spokane Steam Plant during the first nine months of 2021.

The following discussion for Avista Utilities includes two financial measures that are considered “non-GAAP financial measures”: electric utility margin and natural gas utility margin. In the AEL&P section, we include a discussion of utility margin, which is also a non-GAAP financial measure.

Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. Electric utility margin is electric operating revenues less electric resource costs, while natural gas utility margin is natural gas operating revenues less natural gas resource costs. The most directly comparable GAAP financial measure to electric and natural gas utility margin is utility operating revenues as presented in "Note 1617 of the Notes to Condensed Consolidated Financial Statements."

The presentation of electric utility margin and natural gas utility margin is intended to enhance the understanding of operating performance. We use these measures internally and believe they provide useful information to investors in their analysis of how changes in loads (due to weather, economic or other conditions), rates, supply costs and other factors impact our results of operations. Changes in loads, as well as power and natural gas supply costs, are generally deferred and recovered from customers through regulatory accounting mechanisms. Accordingly, the analysis of utility margin generally excludes most of the change in revenue resulting from these regulatory mechanisms. We present electric and natural gas utility margin separately below for Avista Utilities since each business has different cost sources, cost recovery mechanisms and jurisdictions, so we believe that separate analysis is beneficial. These measures are not intended to replace utility operating revenues as determined in accordance with GAAP as an indicator of operating performance. Reconciliations of operating revenues to utility margin are set forth below.

Three months ended ~~March 31,~~September 30, 2021 compared to the three months ended ~~March 31,~~September 30, 2020

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three months ended ~~March 31,~~September 30, 2021 and 2020 (dollars in millions and MWhs in thousands):

Total electric operating revenues in the graph above include intracompany sales of ~~$6.0~~$9.4 million and ~~$6.1~~$10.2 million for the three months ended ~~March 31,~~September 30, 2021 and 2020, respectively.

The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility electric operating revenues for the three months ended ~~March 31~~September 30 (dollars in thousands):

Total electric revenues increased ~~$11.4~~$22.8 million for the ~~first~~third quarter of 2021 as compared to the ~~first~~third quarter of 2020. The primary fluctuations that occurred during the period were as follows:

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three months ended ~~March 31,~~September 30, 2021 and 2020 (dollars in millions and therms in thousands):

Total natural gas operating revenues in the graph above include intracompany sales of ~~$12.5~~$16.3 million and ~~$12.8~~$13.8 million for the three months ended ~~March 31,~~September 30, 2021 and 2020, respectively.

The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility natural gas operating revenues for the three months ended ~~March 31~~September 30 (dollars in thousands):

Total natural gas revenues increased ~~$10.8~~$2.2 million for the ~~first~~third quarter of 2021 as compared to the ~~first~~third quarter of 2020. The primary fluctuations that occurred during the period were as follows:

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the three months ended ~~March 31,~~September 30, 2021 and 2020:

The following graphs present Avista Utilities' resource costs for the three months ended ~~March 31,~~September 30, 2021 and 2020 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of ~~$12.5~~$16.3 million and ~~$12.8~~$13.8 million for the three months ended ~~March 31,~~September 30, 2021 and 2020, respectively.

Total electric resource costs increased ~~$2.3~~$24.4 million for the ~~first~~third quarter of 2021 as compared to the ~~first~~third quarter of 2020. The primary fluctuations that occurred during the period were as follows:

Total natural gas resource costs in the graph above include intracompany resource costs of ~~$6.0~~$9.4 million and ~~$6.1~~$10.2 million for the three months ended ~~March 31,~~September 30, 2021 and 2020, respectively.

Total natural gas resource costs increased ~~$1.5~~$0.6 million for the ~~first~~third quarter of 2021 as compared to the ~~first~~third quarter of 2020 primarily due to the following:

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 1617 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the three months ended ~~March 31,~~September 30, 2021 and 2020 (dollars in thousands):

Electric utility margin ~~increased $9.0~~decreased $1.7 million and natural gas utility margin increased ~~$9.3~~$1.6 million.

Electric utility margin ~~increased~~decreased primarily due to customer growth and a general rate increase in Washington, effective April 1, 2020. In addition, the first quarter of 2020 included an accrual for customer refunds of $1.4 million related to our 2015 Washington general rate case. These was partially offset by an increase inincreased net power supply costs as compared to the prior ~~year; however, in both years, costs were lower than those recovered through our rates (authorized costs).~~year. For the ~~first~~third quarter of 2021, we had a ~~$4.3~~$3.8 million pre-tax ~~benefit~~expense under the ERM in Washington, compared to a ~~$5.2~~$0.3 million pre-tax benefit for the ~~first~~third quarter of 2020.

Natural gas utility margin increased primarily due to a general rate increase in Oregon, effective January 16, 2021 and ~~Washington, effective April 1, 2020, and~~ customer growth. ~~Also, the first quarter~~

Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the condensed consolidated financial statements but are included in the separate results for electric and natural gas presented above.

Nine months ended September 30, 2021 compared to the nine months ended September 30, 2020

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the nine months ended September 30, 2021 and 2020 (dollars in millions and MWhs in thousands):

Total electric operating revenues in the graph above include intracompany sales of $21.9 million and $25.1 million for the nine months ended September 30, 2021 and 2020, respectively.

The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility electric operating revenues for the nine months ended September 30 (dollars in thousands):

Total electric revenues increased $48.3 million for the first nine months of 2021 as compared to the first nine months of 2020. The primary fluctuations that occurred during the period were as follows:

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the nine months ended September 30, 2021 and 2020 (dollars in millions and therms in thousands):

Total natural gas operating revenues in the graph above include intracompany sales of $42.8 million and $37.8 million for the nine months ended September 30, 2021 and 2020, respectively.

The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility natural gas operating revenues for the nine months ended September 30 (dollars in thousands):

Total natural gas revenues increased $18.6 million for the first nine months of 2021 as compared to the first nine months of 2020. The primary fluctuations that occurred during the period were as follows:

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the nine months ended September 30, 2021 and 2020:

The following graphs present Avista Utilities' resource costs for the nine months ended September 30, 2021 and 2020 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of $42.8 million and $37.8 million for the nine months ended September 30, 2021 and 2020, respectively.

Total electric resource costs increased $45.9 million for the first nine months of 2021 as compared to the first nine months of 2020. The primary fluctuations that occurred during the period were as follows:

Total natural gas resource costs in the graph above include intracompany resource costs of $21.9 million and $25.1 million for the nine months ended September 30, 2021 and 2020, respectively.

Total natural gas resource costs increased $5.9 million for the first nine months of 2021 as compared to the first nine months of 2020 primarily due to the following:

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 17 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the nine months ended September 30, 2021 and 2020 (dollars in thousands):

Electric utility margin increased $2.4 million and natural gas utility margin increased $12.7 million.

Electric utility margin increased primarily due to customer growth and a general rate increase in Washington, effective April 1, 2020. In addition, the first three quarters of 2020 included an accrual for customer refunds of $1.4 million related to our 2015 Washington general rate case. This was partially offset by an increase in net power supply costs as compared to the prior year due, in part, to the hot, dry weather conditions experienced in 2021 (see "Summer Weather Conditions" in the Executive Level Summary above). For the first nine months of 2021, we had a $7.1 million pre-tax expense under the ERM in Washington, compared to a $5.9 million pre-tax benefit for the first nine months of 2020.

Natural gas utility margin increased primarily due to a general rate increase in Oregon, effective January 16, 2021 and Washington, effective April 1, 2020, and customer growth. Also, the first quarter of 2020 included an accrual for customer refunds of $3.6 million related to our 2015 Washington general rate case.

Three months ended ~~March 31,~~September 30, 2021 compared to the three months ended ~~March 31,~~September 30, 2020 and nine months ended September 30, 2021 compared to the nine months ended September 30, 2020

Net income for AEL&P was ~~$3.5~~less than $0.1 million for the three months ended ~~March 31,~~September 30, 2021 ~~compared to $3.4 million~~and $0.3 for the three months ended ~~March 31,~~September 30, 2020. Net income was $4.8 million for the nine months ended September 30, 2021 compared to $5.0 million for the nine months ended September 30, 2020.

The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the three and nine months ended ~~March 31,~~September 30, 2021 and 2020 (dollars in thousands):

Utility margin ~~decreased~~increased slightly for 2021, primarily due to ~~warmer temperatures in the first quarter of~~higher sales volumes to commercial customers for 2021 compared to ~~the first quarter of~~ 2020.

AEL&P had normal levels of hydroelectric generation during the first quarters of 2021 and 2020. A portion of the sales to interruptible customers is used to reduce the overall cost of power to AEL&P's firm customers. When interruptible sales are below a certain threshold, AEL&P recognizes a regulatory asset and records a reduction to deferred power supply costs (resource costs) to reflect a future billable amount to its firm customers when the cost of power rates are reset.

Our other businesses had net income of ~~$0.5~~$5.2 million for the three months ended ~~March 31,~~September 30, 2021 compared to a net loss of ~~$1.0~~$0.9 million for the three months ended ~~March 31,~~September 30, 2020. Net income was $10.8 million for the nine months ended September 30, 2021 compared to a net loss of $3.4 million for the nine months ended September 30, 2020.

The increase in net income primarily relates to net investment gains during the ~~first~~three and nine months ended September 30, 2021. This is compared to 2020 that resulted in net investment losses. In addition, 2021 net income increased due to the sale of certain subsidiary assets associated with the Spokane Steam Plant during the second quarter of 2021. ~~Also, during~~During the first ~~quarter~~nine months of 2020 there was an impairment loss and an accrual for bad debt. ~~We are in the process of selling certain subsidiary assets associated with Steam Plant Square and Brew Pub and we expect the sale to be completed during the second quarter of 2021.~~

The preparation of our consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus, actual results could differ from the amounts reported and disclosed herein. Our critical accounting policies that require the use of estimates and assumptions were discussed in detail in the 2020 Form 10-K and have not changed materially.

Our sources of overall liquidity and the requirements for liquidity have not materially changed in the ~~three~~nine months ended ~~March 31,~~September 30, 2021. See the 2020 Form 10-K for further discussion.

As of ~~April~~September 30, 2021, we had ~~$182.4~~$105.4 million of available liquidity under the Avista Corp. committed line of credit and $25.0 million under the AEL&P committed line of credit. With our $400.0 million credit facility that expires in ~~April 2022~~June 2026 and AEL&P's $25.0 million credit facility that expires in November 2024, we believe that we have adequate liquidity to meet our needs for the next 12 months.

Net cash provided by operating activities was ~~$145.1~~$228.9 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2021, compared to ~~$135.3~~$282.5 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2020. The ~~increase~~decrease is primarily due to an increase in ~~net income. As compared to 2020, certain net assets and liabilities increased cash provided by operating activities by $14.9 million.~~

~~The above increases in net cash provided by operating activities was partially offset by~~ power and natural gas cost deferrals, ~~which increased during 2021 due to higher natural gas prices during the year,~~ which decreased cash flows by ~~$7.8~~$40.2 million, as compared to ~~an increase~~a decrease to operating cash flows of ~~$6.4~~$6.5 million in 2020. Additionally, during the ~~first quarter of~~nine months ended September 30, 2021 we contributed ~~$14.0~~$42.0 million to the pension plan, compared to ~~$7.3~~$22.0 million in ~~the first quarter of~~ 2020. Additionally, changes in certain current assets and liabilities decreased cash provided by operating activities by $34.0 million.

Net cash used in investing activities was ~~$96.5~~$326.9 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2021, compared to ~~$95.1~~$301.0 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2020. During the ~~three~~nine months ended ~~March 31,~~September 30, 2021, we paid ~~$97.2~~$322.8 million for utility capital expenditures compared to ~~$95.5~~$297.8 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2020.

Net cash ~~used~~provided by financing activities was ~~$41.2~~$103.0 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2021, compared to net cash ~~used~~provided of ~~$31.1~~$93.3 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2020. In the ~~first quarter of~~nine months ended September 30, 2021, we increased our ~~short-term~~short term borrowings ~~decreased $10.0~~by $66.0 million, compared to decreasing short term borrowings by $35.8 million in 2020. This was offset by a decrease in the issuance of ~~$0.8~~long term debt during the period, from $165.0 million in ~~the first quarter~~2020 to $70.0 million in 2021.

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as of ~~March 31,~~September 30, 2021 and December 31, 2020 (dollars in thousands):

Our shareholders’ equity increased ~~$38.9~~$71.9 million during the first ~~three~~nine months of 2021 primarily due to net income and the issuance of common stock, which was partially offset by dividends.

We need to finance capital expenditures and acquire additional funds for operations from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduce the amount of cash flow available to fund capital expenditures, purchased power, fuel and natural gas costs, dividends and other requirements.

Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 ~~million with~~million. In June 2021, we entered into an amendment that extends the expiration date ~~of April 2022. During~~to June 2026, with the ~~second quarter of 2021, we expect~~option to extend ~~the revolving line of credit agreement~~for an additional one year period (subject to ~~April 2026.~~customary conditions). The committed line of credit is secured by non-transferable first mortgage bonds we issued to the agent bank that would only become due and payable in the event, and then only to the extent, that we default on our obligations under the committed line of credit.

The Avista Corp. credit facility contains customary covenants, ~~and default provisions,~~ including a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at the end of any ~~time.~~fiscal quarter, and customary events of default, including a Change in Control (as defined in the agreement). As of ~~March 31,~~September 30, 2021, we were in compliance with this covenant with a ratio of ~~53.5~~54.5 percent.

AEL&P has a $25.0 million committed line of credit that expires in November 2024. As of ~~March 31,~~September 30, 2021, there were no borrowings or letters of credit outstanding under this committed line of credit.

The AEL&P credit facility contains customary covenants and default provisions including a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of ~~March 31,~~September 30, 2021, AEL&P was in compliance with this covenant with a ratio of ~~52.0~~51.3 percent.

Balances outstanding and interest rates of borrowings under Avista Corp.'s committed line of credit were as follows as of and for the ~~three~~nine months ended ~~March 31~~September 30 (dollars in thousands):

As of ~~March 31,~~September 30, 2021, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements, and none of Avista Corp.'s subsidiaries constituted a “significant subsidiary” as defined in Avista Corp.'s committed line of credit.

In April 2020, we entered into a one-year credit agreement with two financial institutions in the amount of $100.0 million. We borrowed the entire $100.0 million available under this agreement and repaid the outstanding balance in April 2021.

During 2021, we expect to issue approximately ~~$120~~$140 million of long-term debt and ~~$75~~$90 million of ~~equity. We intend to use the proceeds from our~~common stock (including $70.0 million of long-term debt and ~~equity issuances~~$61.3 million of common stock issued during the nine months ended September 30, 2021). During 2022, we expect to issue approximately $370 million of long-term debt and $90 million of common stock in order to refinance $250 million of maturing long-term debt and fund ~~planned~~ capital expenditures.

After considering the expected issuances of long-term debt and ~~equity~~common stock during 2021, we expect net cash flows from operations, together with cash available under our committed lines of credit to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.

We are making capital investments to enhance service and system reliability for our customers and replace aging infrastructure. ~~Our estimates~~We expect Avista Utilities capital expenditures to $450 million in 2021, and about $445 million for ~~2021 through~~each of 2022 and 2023 ~~have not materially changed during the three months ended March 31, 2021.~~to support continued customer growth and maintain our system to provide safe, reliable energy to our customers. See the 2020 Form 10-K for further information on our expected capital expenditures.

As of ~~March 31,~~September 30, 2021, we had ~~$16.6~~$25.6 million in letters of credit outstanding under our $400.0 million committed line of credit, compared to $27.6 million as of December 31, 2020.

In the ~~three~~nine months ended ~~March 31,~~September 30, 2021 we contributed ~~$14~~$42.0 million to the pension plan, ~~and we expect to contribute a total of $42 million in~~fulfilling our expected contributions for 2021. We expect to contribute a total of ~~$150~~$108 million to the pension plan in the period ~~2021~~2022 through 2025, with annual contributions of $42 million in ~~2021 and~~ 2022 and $22 million in 2023 to 2025.

The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including changes to the fair value of pension plan assets, changes in actuarial assumptions (in particular the discount rate used in determining the benefit obligation), or changes in federal legislation. We may change our pension plan contributions in the future depending on changes to any variables, including those listed above.

See "Note 6 of the Notes to Condensed Consolidated Financial Statements" for additional information regarding the pension plan.

Our future contractual obligations have not materially changed during the ~~three~~nine months ended ~~March 31,~~September 30, 2021, except for the following:

Our environmental issues and contingencies disclosures have not materially changed during the ~~three~~nine months ended ~~March 31,~~September 30, 2021 except as discussed below:

In April 2019, we announced a goal to serve our customers with 100 percent clean electricity by 2045 and to have a carbon-neutral supply of electricity by the end of 2027. To help achieve our goals and add to our clean electricity portfolio ~~in the last three years,~~ we have implemented ~~four~~ renewable energy projects on behalf of our ~~customers: the Community Solar project (0.4 MW) in Spokane Valley, Washington (owned by Avista Corp.),~~customers, including the Solar Select project (28 MW) in Lind, Washington (PPA), and the Rattlesnake Flat Wind project (144 MW) in Adams County, Washington (PPA)~~, and~~. We also entered into a PPA for an additional 5 percent of the output from Chelan PUD’s hydroelectric projects. The contract with Chelan PUD begins in 2024. These resources are in addition to our existing clean hydroelectric generation, biomass generation, and ~~additional~~other wind and solar projects.

To achieve our clean energy goals, we expect that energy storage and other technologies, which are either not currently available or are not cost-effective under a lowest reasonable cost regulatory standard, will advance such that itthose technologies will ~~allow~~assist us ~~to meet~~in meeting our goals while also maintaining reliability and affordability for our customers. If the required technology is not available or not affordable in the future, we may not meet our goals in the desired timeframe. Meeting our clean energy goals may also require accommodation from economic regulatory agencies insofar as the Company may need to acquire emission offsets to meet its goals.

In October 2021, Avista Utilities filed its first Clean Energy Implementation Plan (CEIP) with the WUTC. This filing will trigger comments from interested parties in early 2022, with WUTC action to follow thereafter in 2022.

Our CEIP is a road map of specific actions we propose to take over the next four years (2022-2025) to show the progress being made toward clean energy goals established by the Clean Energy Transformation Act (CETA), which was passed by the Washington legislature and enacted into law in 2019. CETA requires electric supply to be greenhouse gas neutral by 2030 and 100 percent renewable or generated from zero-carbon resources by 2045.

While the CEIP represents our current objectives, it is subject to change from time to time in the future as circumstances warrant.

In January 2021, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the Affordable Clean Energy Rule and remanded the record back to the EPA for further consideration consistent with its opinion. The Court also vacated the repeal of the Clean Power Plan (CPP). Subsequently, the EPA indicated, in a February 12, 2021 Memorandum from Acting Assistant Administrator Joseph Goffman that “…EPA understands the decision as leaving neither of those rules, and thus no CAA section 111(d) regulation, in place with respect to greenhouse gas (GHG) emissions from electric generating units (EGUs). As a practical matter, the reinstatement of the CPP would not make sense.”

In 2021, the legislature passed the Climate Commitment Act, which establishes a cap and invest program to help achieve Washington’s greenhouse gas limits by 2050. The Washington Department of Ecology is responsible for the implementation and the start of this program by January 1, 2023, including the adoption of annual allowance budgets for the first compliance period of the program by October 1, 2022. There are various rule making proceedings regarding the details of the program pending before the Department of Ecology. We will actively monitor and participate in these rulemakings as they proceed but cannot reasonably predict how these programs may impact our facilities at this time.

On March 10, 2020, the governor of Oregon issued an Executive Order (EO) establishing GHG emissions reduction goals of at least 45 percent below 1990 emission levels by 2035 and at least 80 percent below 1990 emission levels by 2050 and directed state agencies and commissions to facilitate such GHG emission goals targeting a variety of sources and industries. Although the EO does not specifically direct actions of natural gas distribution businesses like Avista, the OPUC is directed to prioritize proceedings and activities that advance decarbonization in the utility sector, mitigate energy burden experienced by utility customers and ensure system reliability and resource adequacy. The EO also directs other agencies to cap and reduce GHG emissions from transportation fuels and all other liquid and gaseous fuels, including natural gas, adopt building energy efficiency goals for new building construction, reduce methane gas emissions from landfills and food waste, and submit a proposal for adoption of state goals for carbon sequestration and storage by Oregon’s forest, wetlands and agricultural lands.

The Oregon Department of Environmental Quality (ODEQ) is developing cap and reduce rules known as the Climate Protection Program (CPP). Final rules are expected to be considered for adoption by the Environmental Quality Commission in December 2021 and become effective in 2022. The OPUC has opened a Natural Gas Fact-Finding effort to analyze the potential natural gas utility bill impacts that may result from limiting GHG emissions of regulated natural gas utilities under the ODEQ’s CPP and to identify appropriate regulatory tools to mitigate potential customer impacts. According to the OPUC Staff, the ultimate goal of the Fact-Finding Docket will be to inform future policy decisions and other key analyses to be considered in 2022, after the CPP is in place. We expect the OPUC Staff will present a final report on the Fact-Finding effort to the OPUC in February 2022 with recommendations for further OPUC engagement later in 2022.

See the 2020 Form 10-K for further discussion of environmental issues and contingencies.

In July 2021, the Department of Homeland Security, acting through the Transportation Security Administration (TSA), announced the issuance of a security directive that requires owners and operators of TSA-designated critical pipeline facilities that transport hazardous liquids and natural gas to implement specified protections against cyber intrusions. The security directive requires designated owners and operators of such facilities to implement specific mitigation measures to protect against ransomware attacks and other known threats to information and operational technology systems, develop and implement a cybersecurity contingency and recovery plan and conduct a cybersecurity architecture design review.

The Company is assessing the extent to which its facilities are or may be affected, directly or indirectly, by the directive. The Company is engaged in a continuous program of testing and updating its cybersecurity measures. As reported in the 2020 Form 10-K, the Company’s natural gas distribution facilities, as well as most of its gas-fired generation facilities, are interconnected with the gas transportation systems of several interstate gas pipelines.

Colstrip is a coal-fired generating plant in southeastern Montana that includes four units and which is owned by six separate entities. We have a 15 percent ownership interest in Units 3 & 4 and provide financing for our ownership interest in the project. The other owners are Puget Sound Energy, Portland General Electric, PacifiCorp, NorthWestern Energy ~~PacifiCorp~~ and Talen Montana (which is also the operator of the plant). In January 2020, the owners of Units 1 & 2, in which we have no ownership, closed those two units. The owners of Units 3 & 4 currently share operating and capital costs pursuant to the terms of an operating agreement among ~~them (the Ownership and Operation Agreement).~~ them.

As a result of CETA in Washington and the varied impacts that this law has had on the different co-owners of Colstrip Units 3 & 4, business disagreements have arisen among the co-owners, which in turn has led to disagreements in the interpretation of the Ownership and Operating Agreement. In order to address and resolve these disagreements, the owners have commenced an arbitration proceeding as provided for in the Ownership and Operating Agreement. See “Note 1516 of the Notes to Condensed Consolidated Financial Statements” for ~~further~~ discussion ~~surrounding the~~of pending arbitration ~~proceeding.~~

~~In response~~proceedings, recent Montana legislation, and other matters related to a letter from several non-governmental organizations, the WUTC issued a Notice of Opportunity to Respond to Request to Initiate Investigation on April 13, 2021, in which it sought comment on whether it should “initiate a proceeding to investigate Colstrip’s ongoing expenses resulting in a ‘clear order or determination from the [WUTC] that continued funding to maintain and operate Colstrip is not consistent with prudent utility practice.’” The Company has responded, requesting that the WUTC deny the request to initiate a proceeding. At this time, we cannot predict whether the WUTC will initiate an investigation.

~~In the course of the 2021 legislative session, the Montana Legislature passed two bills that are specifically directed at the ownership and operation of~~ Colstrip. ~~The Company took legal action against one of the bills and intends to challenge the legality and constitutionality of the other bill.~~ See ~~“Note 15 of the Notes to Condensed Consolidated Financial Statements” for further discussion surrounding Montana legislation.~~

The material risks to our businesses, and our mitigation process and procedures to address these risks, were discussed in our 2020 Form 10-K and have not materially changed during the ~~three~~nine months ended ~~March 31,~~September 30, 2021. See the 2020 Form 10-K.

Our financial risks have not materially changed during the ~~three~~nine months ended ~~March 31, 2021, other than the changes noted due to COVID-19.~~September 30, 2021. Refer to the 2020 Form 10-K. The financial risks included below are required interim disclosures, even if they have not materially changed from December 31, 2020.

We use a variety of techniques to manage our interest rate risks. We have an interest rate risk policy and have established a policy to limit our variable rate exposures to a percentage of total capitalization. Additionally, interest rate risk is managed by monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and establishing fixed rate long-term debt with varying maturities. See "Note 5 of the Notes to Condensed Consolidated Financial Statements" for a summary of our interest rate swap derivatives outstanding as of ~~March 31,~~September 30, 2021 and December 31, 2020 and the amount of additional collateral we would have to post in certain circumstances.

Under the terms of interest rate swap derivatives that we enter into periodically, we may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the instrument. A downgrade in our credit ratings could further impact the amount of collateral required. See “Credit Ratings” in the 2020 Form 10-K for further information. As of ~~March 31,~~September 30, 2021, we had interest rate swap derivatives outstanding with a notional amount totaling ~~$185.0~~$170.0 million and we had no cash deposited as collateral ~~in the amount of $3.9 million~~ and no letters of credit outstanding for these interest rate swap derivatives. If our credit ratings were lowered to below “investment grade” based on our interest rate swap derivatives outstanding at ~~March 31,~~September 30, 2021, we would potentially be required to post the following additional collateral (in thousands):

Our energy commodity risks have not materially changed during the ~~three~~nine months ended ~~March 31,~~September 30, 2021. See the 2020 Form 10-K. The following table presents energy commodity derivative fair values as a net asset or (liability) as of ~~March 31,~~September 30, 2021 that are expected to settle in each respective year (dollars in thousands). There are no expected deliveries of energy commodity derivatives after 2025.

The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2020 that are expected to be delivered in each respective year (dollars in thousands). There are no expected deliveries of energy commodity derivatives after 2025.

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 deferral and recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to eventually be collected through retail rates from customers.

In April 2021, we filed our 2021 Electric Integrated Resource Plan (IRP) with the WUTC and the IPUC. Then on April 30th, we filed an amended IRP to include the results of the 2020 Renewable RFP. The WUTC and the IPUC review the IRPs and give the public the opportunity to comment. The WUTC and the IPUC do not approve or disapprove of the content in the IRPs; rather they acknowledge ~~that~~ the IRPs ~~were~~are prepared in accordance with applicable ~~standards if that is the case.~~standards.

Highlights of the 2021 IRP include the following expectations and/or assumptions:

~~See “Future Resource Needs” in the 2020 Form 10-K for further discussion on the 2020 IRP.~~

The information required by this item is set forth in the Enterprise Risk Management section of "Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations" and is incorporated herein by reference.

The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) (Act) that are designed to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. With the participation of the Company’s principal executive officer and principal financial officer, the Company's management evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level as of ~~March 31,~~September 30, 2021.

There have been no changes in the Company's internal control over financial reporting that occurred during the ~~first~~third quarter of 2021 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

See “Note 1516 of Notes to Condensed Consolidated Financial Statements” in “Part I. Financial Information Item 1. Condensed Consolidated Financial Statements.”

Refer to the 2020 Form 10-K for disclosure of risk factors that could have a significant impact on our results of operations, financial condition or cash flows and could cause actual results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Quarterly Report on Form 10-Q), and elsewhere. These risk factors have not materially changed from the disclosures provided in the 2020 Form 10-K with the exception of the following:

The COVID 19 pandemic is disrupting our business and could have a negative effect on our results of operations, financial condition and cash flows.

The COVID-19 pandemic is currently impacting our business, as well as the global, national and local economy. We cannot predict the full extent to which COVID-19 will impact our operations, results of operations, cash flows, financial condition or capital resources. It is possible that the continued spread of COVID-19 and efforts to contain the virus will continue to cause an economic slowdown, resulting in significant disruptions in various public, commercial or industrial activities and causing employee absences which could interfere with operation and maintenance of the Company’s facilities. Any of these circumstances could adversely affect our operations, results of operations, financial condition and cash flows in many ways, including, but not limited to:

We cannot predict the duration and severity of the COVID-19 pandemic. The longer and more severe the economic restrictions and business disruptions are, the greater the impact on our operations, results of operations, financial condition and cash flows will be.

In addition to these risk factors, see also “Forward-Looking Statements” for additional factors which could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.

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


Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock	AVA	New York Stock Exchange


Item No.		Page No.

	Acronyms and Terms	iii
	Forward-Looking Statements	1
	Available Information	4
Part I. Financial Information
Item 1.	Condensed Consolidated Financial Statements	5
	Condensed Consolidated Statements of Income - Three and Nine Months Ended ~~March 31,~~September 30, 2021 and 2020	5
	Condensed Consolidated Statements of Comprehensive Income - Three and Nine Months Ended ~~March 31,~~September 30, 2021 and 2020	6
	Condensed Consolidated Balance Sheets - ~~March 31,~~September 30, 2021 and December 31, 2020	7
	Condensed Consolidated Statements of Cash Flows - ~~Three~~Nine Months Ended ~~March 31,~~September 30, 2021 and 2020	8
	Condensed Consolidated Statements of Equity - Three and Nine Months Ended ~~March 31,~~September 30, 2021 and 2020	10
	Notes to Condensed Consolidated Financial Statements	11
	Note 1. Summary of Significant Accounting Policies	11
	Note 2. New Accounting Standards	12
	Note 3. Balance Sheet Components	12
	Note 4. Revenue	1514
	Note 5. Derivatives and Risk Management	18
	Note 6. Pension Plans and Other Postretirement Benefit Plans	22
	Note 7. Income Taxes	2322
	Note 8. Committed Lines of Credit	23
	Note 9. Credit Agreement	24
	Note 10. Long Term Debt	24
	Note 11. Long-Term Debt to Affiliated Trusts	24
	Note ~~11.~~12. Fair Value	2425
	Note ~~12.~~13. Common Stock	28
	Note ~~13.~~14. Accumulated Other Comprehensive Loss	28
	Note ~~14.~~15. Earnings per Common Share	29
	Note ~~15.~~16. Commitments and Contingencies	29
	Note ~~16.~~17. Information by Business Segments	3132
	Report of Independent Registered Public Accounting Firm	3334

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3435
	Business Segments	3435
	Executive Level Summary	3435
	Regulatory Matters	3536
	Results of Operations - Overall	3839
	Non-GAAP Financial Measures	3942

	Results of Operations - Alaska Electric Light and Power Company	4755
	Results of Operations - Other Businesses	4755
	Critical Accounting Policies and Estimates	4756
	Liquidity and Capital Resources	4856
	Overall Liquidity	4856
	Review of Cash Flow Statement	4856
	Capital Resources	4857
	Capital Expenditures	5058
	Off-Balance Sheet Arrangements	5058
	Pension Plan	5058
	Contractual Obligations	5058
	Environmental Issues and Other Contingencies	5059
	Colstrip	5161
	Enterprise Risk Management	5161
	Future Resource Needs	5362

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	5463

Item 4.	Controls and Procedures	5463

Part II. Other Information
Item 1.	Legal Proceedings	5464

Item 1A.	Risk Factors	5464

Item 6.	Exhibits	5566

	Signature	5667


Acronym/Term	Meaning
aMW	-	Average Megawatt - a measure of the average rate at which a particular generating source produces energy over a period of time
AEL&P	-	Alaska Electric Light and Power Company, the primary operating subsidiary of AERC, which provides electric services in Juneau, Alaska
AERC	-	Alaska Energy and Resources Company, the Company's wholly-owned subsidiary based in Juneau, Alaska
AFUDC	-	Allowance for Funds Used During Construction; represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period
ASC	-	Accounting Standards Codification
ASU	-	Accounting Standards Update
Avista Capital	-	Parent company to the Company’s non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC.
Avista Corp.	-	Avista Corporation, the Company
Avista Utilities	-	Operating division of Avista Corp. (not a subsidiary) comprising the regulated utility operations in the Pacific Northwest
Capacity	-	The rate at which a particular generating source is capable of producing energy, measured in KW or MW
Cabinet Gorge	-	The Cabinet Gorge Hydroelectric Generating Project, located on the Clark Fork River in Idaho
CETA	-	Clean Energy Transformation Act
Colstrip	-	The coal-fired Colstrip Generating Plant in southeastern Montana
Cooling degree days	-	The measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures)
COVID-19	-	Coronavirus disease 2019, a respiratory illness that was declared a pandemic in March 2020
Deadband or ERM deadband	-	The first $4.0 million in annual power supply costs above or below the amount included in base retail rates in Washington under the ERM in the state of Washington
EIM	-	Energy Imbalance Market
Energy	-	The amount of electricity produced or consumed over a period of time, measured in KWh or MWh. Also, refers to natural gas consumed and is measured in dekatherms
EPA	-	Environmental Protection Agency
ERM	-	The Energy Recovery Mechanism, a mechanism for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Washington
FASB	-	Financial Accounting Standards Board
FCA	-	Fixed Cost Adjustment, the electric and natural gas decoupling mechanism in Idaho
FERC	-	Federal Energy Regulatory Commission
GAAP	-	Generally Accepted Accounting Principles
Heating degree days	-	The measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).
IPUC	-	Idaho Public Utilities Commission
~~Juneau~~KW, KWh	-	~~The City and Borough of Juneau, Alaska~~
~~KW, KWh~~	-	Kilowatt (1000 watts): a measure of generating power or capability. Kilowatt-hour (1000 watt hours): a measure of energy produced over a period of time


MW, MWh	-	Megawatt: 1000 KW. Megawatt-hour: 1000 KWh
Noxon Rapids	-	The Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana
OPUC	-	The Public Utility Commission of Oregon
PCA	-	The Power Cost Adjustment mechanism, a procedure for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Idaho
PGA	-	Purchased Gas Adjustment
PPA	-	Power Purchase Agreement
RCA	-	The Regulatory Commission of Alaska
REC	-	Renewable energy credit
ROE	-	Return on equity
ROR	-	Rate of return on rate base
ROU	-	Right-of-use lease asset
SEC	-	U.S. Securities and Exchange Commission
~~TCJA~~Therm	-	~~The "Tax Cuts and Jobs Act," signed into law on December 22, 2017~~
~~Therm~~	-	Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy)
Watt	-	Unit of measurement of electric power or capability; a watt is equal to the rate of work represented by a current of one ampere under a pressure of one volt
WUTC	-	Washington Utilities and Transportation Commission


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

	FOR THE QUARTERLY PERIOD ENDED ~~March 31,~~ September 30, 2021 OR


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

	FOR THE TRANSITION PERIOD FROM TO


Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
Emerging growth company	☐

	2021					2020
Federal income taxes at statutory rates	$	16,838		21.0	%	$	11,961		21.0	%
Increase (decrease) in tax resulting from:
Tax effect of regulatory treatment of utility plant differences		(3,240	)	(4.0	)		(2,402	)	(4.2	)
State income tax expense		552		0.7			1,227		2.1
Settlement of equity awards		930		1.1			165		0.3
Other		(2,916	)	(3.6	)		(2,419	)	(4.2	)
Total income tax expense	$	12,164		15.2	%	$	8,532		15.0	%

	Natural Gas Exchange Agreement
Three months ended March 31, 2021:
Balance as of January 1, 2021	$	(8,410	)
Total gains (realized/unrealized):
Included in regulatory assets/liabilities (1)		3,220
Settlements		(1,011	)
Ending balance as of March 31, 2021 (2)	$	(6,201	)
Three months ended March 31, 2020:
Balance as of January 1, 2020	$	(2,976	)
Total gains (realized/unrealized):
Included in regulatory assets/liabilities (1)		485
Settlements		238
Ending balance as of March 31, 2020 (2)	$	(2,253	)


	Electric Decoupling Revenues
	2021			2020
Current year decoupling deferrals (a)	$	(9,508	)	$	(1,316	)
Amortization of prior year decoupling deferrals (b)		(3,667	)		(4,067	)
Total electric decoupling revenue	$	(13,175	)	$	(5,383	)


	Natural Gas Decoupling Revenues
	2021		2020
Current year decoupling deferrals (a)	$	2,458	$	1,540
Amortization of prior year decoupling deferrals (b)		218		(129	)
Total natural gas decoupling revenue	$	2,676	$	1,411


	Electric Customers				Natural Gas Customers
	2021		2020		2021		2020
Residential		356,846		350,831		332,403		327,073
Commercial		44,117		43,510		36,329		36,074
Interruptible		—		—		44		40
Industrial		1,204		1,297		191		239
Public street and highway lighting		680		629		—		—
Total retail customers		402,847		396,267		368,967		363,426


	Electric				Natural Gas				Intracompany						Total
	2021		2020		2021		2020		2021			2020			2021		2020
Operating revenues	$	248,110	$	225,416	$	64,299	$	62,107	$	(25,657	)	$	(23,959	)	$	286,752	$	263,564
Resource costs		89,894		65,527		36,872		36,275		(25,657	)		(23,959	)		101,109		77,843
Utility margin	$	158,216	$	159,889	$	27,427	$	25,832	$	—		$	—		$	185,643	$	185,721


	September 30, 2021					December 31, 2020
	Amount		Percent of total			Amount		Percent of total
Current portion of long-term debt and leases	$	257,337		5.6	%	$	7,184		0.2	%
Short-term borrowings		199,075		4.3	%		203,000		4.6	%
Long-term debt to affiliated trusts		51,547		1.1	%		51,547		1.2	%
Long-term debt and leases		2,014,212		43.5	%		2,125,065		48.0	%
Total debt		2,522,171		54.5	%		2,386,796		54.0	%
Total Avista Corporation shareholders’ equity		2,101,636		45.5	%		2,029,726		46.0	%
Total	$	4,623,807		100.0	%	$	4,416,522		100.0	%


	2021			2020
Borrowings outstanding at end of period	$	269,000		$	50,000
Letters of credit outstanding at end of period	$	25,618		$	25,573
Maximum borrowings outstanding during the period	$	338,000		$	257,000
Average borrowings outstanding during the period	$	190,641		$	178,537
Average interest rate on borrowings during the period		1.15	%		1.28	%
Average interest rate on borrowings at end of period		1.09	%		1.20	%


	March 31, 2021		September 30, 2021
Additional collateral taking into account contractual thresholds	$	5,380	$	9,040
Additional collateral without contractual thresholds		11,046		20,732


15		Letter Re: Unaudited Interim Financial Information (1)

31.1		Certification of Chief Executive Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) (1)

31.2		Certification of Chief Financial Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) (1)

32		Certification of Corporate Officers (Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) (2)

101.INS		Inline XBRL Instance Document. The instance document does not appear in the interactive data file because its inline XBRL tags are embedded within the inline XBRL document.
101.SCH		Inline XBRL Taxonomy Extension Schema Document
101.CAL		Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB		Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE		Inline XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF		Inline XBRL Taxonomy Extension Definition Linkbase Document
104		Cover page formatted as Inline XBRL and contained in Exhibit 101.

(1)		Filed herewith.
(2)		Furnished herewith.


		AVISTA CORPORATION
		(Registrant)




Date:	~~May 4,~~November 2, 2021	/s/ Mark T. Thies
		Mark T. Thies
		Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)