(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,~~July 31, 2021, ~~69,314,368~~69,667,790 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, 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.

The accompanying condensed consolidated financial statements of Avista Corp. as of and for the interim periods ended ~~March 31,~~June 30, 2021 and ~~March 31,~~June 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 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corp. is primarily an electric and natural gas utility with certain other business ventures. Avista Utilities is an operating division of Avista Corp., comprising its regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana, most of whom are employees who operate the Company's Noxon Rapids generating facility.

AERC is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, which comprises Avista Corp.'s regulated utility operations in Alaska.

Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 16 for business segment information.

Basis of Reporting

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

Regulation

The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and Alaska. The Company is also subject to federal regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its operations.

Derivative Assets and Liabilities

Derivatives are recorded as either assets or liabilities on the Condensed Consolidated Balance Sheets measured at estimated fair value.

The WUTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. Realized benefits and costs result in adjustments to retail rates through PGAs, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rate cases. The resulting regulatory assets associated with energy commodity derivative instruments have been concluded to be probable of recovery through future rates.

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AVISTA CORPORATION

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

For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process.

The Company has multiple master netting agreements with a variety of entities that allow for cross-commodity netting of derivative agreements with the same counterparty (i.e. power derivatives can be netted with natural gas derivatives). In addition, some master netting agreements allow for the netting of commodity derivatives and interest rate swap derivatives for the same counterparty. The Company does not have any agreements which allow for cross-affiliate netting among multiple affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the Condensed Consolidated Balance Sheets.

Fair Value Measurements

Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, as well as derivatives related to interest rate swaps and foreign currency exchange contracts, are reported at estimated fair value on the Condensed Consolidated Balance Sheets. See Note 11 for the Company’s fair value disclosures.

Contingencies

~~Contingencies~~

The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses loss contingencies that do not meet these conditions for accrual if there is a reasonable possibility that a material loss may be incurred. See Note 15 for further discussion of the Company's commitments and contingencies.

NOTE 2. NEW ACCOUNTING STANDARDS

There are no new accounting standards with a material impact to the Company.

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,~~June 30, 2021 and December 31, 2020 (dollars in thousands):


	June 30,		December 31,
	2021		2020
Materials and supplies	$	57,068	$	53,258
Fuel stock		5,780		4,658
Stored natural gas		19,930		9,535
Total	$	82,778	$	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,~~June 30, 2021 and December 31, 2020 (dollars in thousands):


	March 31,		December 31,		June 30,		December 31,
	2021		2020		2021		2020
Collateral posted for derivative instruments after netting with outstanding derivative liabilities	$	4,810	$	4,336	$	25,089	$	4,336
Prepayments		25,984		24,411		22,444		24,411
Income taxes receivable		44,371		49,814		25,945		49,814
Other		7,757		6,324		9,662		6,324
Total	$	82,922	$	84,885	$	83,140	$	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,~~June 30, 2021 and December 31, 2020 (dollars in thousands):


	March 31,		December 31,		June 30,		December 31,
	2021		2020		2021		2020
Utility plant in service	$	6,865,652	$	6,809,797	$	6,980,002	$	6,809,797
Construction work in progress		193,685		175,767		185,011		175,767
Total		7,059,337		6,985,564		7,165,013		6,985,564
Less: Accumulated depreciation and amortization		2,032,234		1,993,952		2,064,251		1,993,952
Total net utility property	$	5,027,103	$	4,991,612	$	5,100,762	$	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,~~June 30, 2021 and December 31, 2020 (dollars in thousands):


	June 30,		December 31,
	2021		2020
Operating lease ROU assets	$	70,941	$	71,891
Equity investments		69,921		59,318
Finance lease ROU assets		45,518		47,338
Non-utility property		18,925		19,508
Notes receivable		14,803		14,454
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		9,660		9,174
Assets held for sale (1)		0		3,462
Other		19,749		26,947
Total	$	261,064	$	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,~~June 30, 2021 and December 31, 2020 (dollars in thousands):


	June 30, 2021		December 31, 2020
Accrued taxes other than income taxes	$	42,117	$	45,099
Derivative liabilities		33,276		14,008
Employee paid time off accruals		28,998		26,495
Accrued interest		16,594		17,083
Pensions and other postretirement benefits		12,429		11,987
Other		38,271		35,159
Total other current liabilities	$	171,685	$	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

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AVISTA CORPORATION

Other Non-Current Liabilities and Deferred Credits

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


	March 31, 2021		December 31, 2020		June 30, 2021		December 31, 2020
Operating lease liabilities	$	68,276	$	67,716	$	68,820	$	67,716
Finance lease liabilities		48,044		48,815		47,273		48,815
Deferred investment tax credits		29,728		29,866		29,590		29,866
Asset retirement obligations		17,126		17,194		16,734		17,194
Derivative liabilities		8,959		37,427		4,426		37,427
Other		14,524		13,981		15,700		13,981
Total	$	186,657	$	214,999	$	182,543	$	214,999

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~~AVISTA CORPORATION~~

Regulatory Assets and Liabilities

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


	June 30, 2021				December 31, 2020
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	5,652	$	1,410	$	2,073	$	5,722
Decoupling surcharge		9,768		13,911		7,123		17,123
Pension and other postretirement benefit plans		0		194,005		0		198,746
Interest rate swaps		0		197,302		0		214,851
Deferred income taxes (1)		0		238,234		0		108,517
Settlement with Coeur d'Alene Tribe		0		39,484		0		40,043
AFUDC above FERC allowed rate		0		48,961		0		47,393
Demand side management programs		0		1,449		0		3,814
Utility plant to be abandoned		0		27,599		0		28,916
COVID-19 deferrals		0		14,292		0		8,166
Other regulatory assets		11,754		93,448		4,477		77,152
Total regulatory assets	$	27,174	$	870,095	$	13,673	$	750,443
Regulatory Liabilities
Income tax related liabilities (1)	$	45,431	$	485,165	$	14,952	$	399,677
Deferred power costs		14,996		13,118		20,299		17,570
Decoupling rebate		849		3,754		1,447		1,519
Utility plant retirement costs		0		336,940		0		325,832
Interest rate swaps		0		15,637		0		15,046
COVID-19 deferrals		0		12,680		0		10,949
Other regulatory liabilities		8,900		15,149		9,737		14,227
Total regulatory liabilities	$	70,176	$	882,443	$	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 $127.5 million.

March 31, 2021

December 31, 2020

Current

Non-Current

Current

Non-Current

Regulatory Assets

Energy commodity derivatives

$
3,637

$
3,237

$
2,073

$
5,722

Decoupling surcharge

18,150

6,812

7,123

17,123

Pension and other postretirement benefit plans

0

196,153

0

198,746

Interest rate swaps

0

177,824

0

214,851

Deferred income taxes

0

111,537

0

108,517

Settlement with Coeur d'Alene Tribe

0

39,764

0

40,043

AFUDC above FERC allowed rate

0

48,270

0

47,393

Demand side management programs

0

904

0

3,814

Utility plant to be abandoned

0

27,599

0

28,916

COVID-19 deferrals

0

11,759

0

8,166

Other regulatory assets

7,438

82,062

4,477

77,152

Total regulatory assets

$
29,225

$
705,921

$
13,673

$
750,443

Regulatory Liabilities

Income tax related liabilities

$
15,013

$
395,859

$
14,952

$
399,677

Deferred power costs

18,955

13,859

20,299

17,570

Decoupling rebate

1,396

1,604

1,447

1,519

Utility plant retirement costs

0

330,897

0

325,832

Interest rate swaps

0

17,218

0

15,046

COVID-19 deferrals

0

11,628

0

10,949

Other regulatory liabilities

9,703

12,719

9,737

14,227

Total regulatory liabilities

$
45,067

$
783,784

$
46,435

$
784,820

~~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. 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.

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~~AVISTA CORPORATION~~

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

2021

2020

Utility-related taxes
$
19,696

$
18,700


	Three months ended June 30,				Six months ended June 30,
	2021		2020		2021		2020
Utility-related taxes	$	13,459	$	12,879	$	33,155	$	31,578

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,~~June 30, 2021, the Company estimates it had unsatisfied capacity performance obligations of ~~$21.2~~$19.8 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.

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AVISTA CORPORATION

Disaggregation of Total Operating Revenue

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


	Three months ended June 30,						Six months ended June 30,
	2021			2020			2021			2020
Avista Utilities
Revenue from contracts with customers	$	260,676		$	235,405		$	619,289		$	587,034
Derivative revenues		28,083			24,211			63,064			55,285
Alternative revenue programs		(3,069	)		4,362			(2,570	)		(51	)
Deferrals and amortizations for rate refunds to customers		(369	)		2,080			2,820			(525	)
Other utility revenues		2,239			2,281			4,817			3,801
Total Avista Utilities		287,560			268,339			687,420			645,544
AEL&P
Revenue from contracts with customers		10,487			9,978			23,266			22,104
Deferrals and amortizations for rate refunds to customers		(48	)		(47	)		(95	)		(95	)
Other utility revenues		108			67			197			191
Total AEL&P		10,547			9,998			23,368			22,200

Other revenues		148			255			337			1,078
Total operating revenues	$	298,255		$	278,592		$	711,125		$	668,822

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

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~~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 six months ended ~~March 31~~June 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 June 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	113,223	$	6,048	$	119,271	$	107,977	$	5,866	$	113,843	$	84,688	$	4,251	$	88,939	$	78,760	$	4,190	$	82,950
Commercial and governmental		76,284		4,772		81,056		78,849		6,199		85,048
Commercial														80,858		6,177		87,035		68,785		5,729		74,514
Industrial		24,711		1,899		26,610		24,711		0		24,711		27,429		0		27,429		24,816		0		24,816
Public street and highway lighting		1,852		60		1,912		1,783		61		1,844		1,869		59		1,928		1,846		59		1,905
Total retail revenue		216,070		12,779		228,849		213,320		12,126		225,446		194,844		10,487		205,331		174,207		9,978		184,185
Transmission		3,495		0		3,495		3,774		0		3,774		4,801		0		4,801		4,409		0		4,409
Other revenue from contracts with customers		6,140		0		6,140		5,289		0		5,289		6,532		0		6,532		3,415		0		3,415
Total electric revenue from contracts with customers	$	225,705	$	12,779	$	238,484	$	222,383	$	12,126	$	234,509	$	206,177	$	10,487	$	216,664	$	182,031	$	9,978	$	192,009
Six months ended June 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential													$	197,911	$	10,299	$	208,210	$	186,737	$	10,045	$	196,782
Commercial														157,142		12,848		169,990		147,634		11,938		159,572
Industrial														52,140		0		52,140		49,527		0		49,527
Public street and highway lighting														3,721		119		3,840		3,629		121		3,750
Total retail revenue														410,914		23,266		434,180		387,527		22,104		409,631
Transmission														8,296		0		8,296		8,183		0		8,183
Other revenue from contracts with customers														12,672		0		12,672		8,705		0		8,705
Total electric revenue from contracts with customers													$	431,882	$	23,266	$	455,148	$	404,415	$	22,104	$	426,519

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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 six months ended ~~March 31~~June 30 (dollars in thousands):


	2021		2020
	Avista Utilities		Avista Utilities
Three months ended June 30:
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	33,703	$	34,826
Commercial		15,598		14,142
Industrial and interruptible		1,819		1,543
Total retail revenue		51,120		50,511
Transportation		1,973		1,738
Other revenue from contracts with customers		1,406		1,125
Total natural gas revenue from contracts with customers	$	54,499	$	53,374
Six months ended June 30:
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	121,204	$	118,998
Commercial		55,373		53,544
Industrial and interruptible		4,043		3,737
Total retail revenue		180,620		176,279
Transportation		4,256		4,090
Other revenue from contracts with customers		2,531		2,250
Total natural gas revenue from contracts with customers	$	187,407	$	182,619

2021

2020

Avista Utilities

Avista Utilities

Three months ended March 31,

NATURAL GAS OPERATIONS

Revenue from contracts with customers

Residential

$
87,501

$
84,173

Commercial and governmental

39,775

39,401

Industrial and interruptible

2,224

2,194

Total retail revenue

129,500

125,768

Transportation

2,283

2,352

Other revenue from contracts with
customers

1,125

1,125

Total natural gas revenue from
contracts with customers

$
132,908

$
129,245

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,~~June 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		11		62		5,875		37,413		47		378		4,504		22,943
2022		0		0		450		29,345		0		0		1,360		12,950		0		0		450		37,835		0		268		2,260		20,820
2023		0		0		0		6,920		0		0		1,360		1,970		0		0		0		12,000		0		0		1,360		6,160
2024		0		0		0		0		0		0		1,370		0		0		0		0		910		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,~~June 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

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AVISTA CORPORATION

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,~~June 30, 2021 and December 31, 2020 (dollars in thousands):


	March 31, 2021		December 31, 2020		June 30, 2021		December 31, 2020
Number of contracts		25		22		18		22
Notional amount (in United States dollars)	$	4,916	$	3,860	$	6,140	$	3,860
Notional amount (in Canadian dollars)		6,178		4,949		7,490		4,949

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,~~June 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
June 30, 2021							4	$	45,000	2021
		12		130,000	2022		12		130,000	2022
		1		10,000	2023		1		10,000	2023
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,~~June 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,~~June 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	$	(88	)	$	0	$	(88	)
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			1,318		0			0		1,318
Other current liabilities		0		(10,978	)		3,910		(7,068	)		1,966		(38,135	)		5,850		(30,319	)
Other non-current liabilities and deferred credits		1,264		(5,525	)		0		(4,261	)
Energy commodity derivatives
Other current assets		749		(24	)		0		725			3,430		(46	)		0		3,384
Other property and investments-net and other non-current assets		2,598		(1,136	)		0		1,462			5,442		(2,425	)		0		3,017
Other current liabilities		17,458		(21,820	)		2,786		(1,576	)		32,554		(41,589	)		6,166		(2,869	)
Other non-current liabilities and deferred credits		95		(4,793	)		0		(4,698	)		78		(4,504	)		0		(4,426	)
Total derivative instruments recorded on the balance sheet	$	28,520	$	(48,118	)	$	6,696	$	(12,902	)	$	44,788	$	(86,787	)	$	12,016	$	(29,983	)

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,~~June 30, 2021 and December 31, 2020 (in thousands):


	June 30,		December 31,
	2021		2020
Energy commodity derivatives
Cash collateral posted	$	31,255	$	4,953
Letters of credit outstanding		20,000		23,500
Balance sheet offsetting		6,166		616
Interest rate swap derivatives
Cash collateral posted (offset by net derivative positions)		5,850		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

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AVISTA CORPORATION

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,~~June 30, 2021 and December 31, 2020 (in thousands):


	June 30,		December 31,
	2021		2020
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features		38,135		50,813
Additional collateral to post		32,285		42,763

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~~six months ended ~~March 31,~~June 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~~$28 million in cash to the pension plan for the ~~three~~six months ended ~~March 31,~~June 30, 2021 and it expects to contribute ~~$42~~$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 six months ended ~~March 31~~June 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 June 30:
Service cost	$	6,246		$	5,546		$	1,008		$	979		$	6,254		$	5,550		$	897		$	980
Interest cost		6,580			6,971			1,376			1,515			6,530			6,967			1,309			1,524
Expected return on plan assets		(9,775	)		(9,125	)		(675	)		(630	)		(9,704	)		(8,625	)		(783	)		(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			1,688			1,679			1,246			1,243
Net periodic benefit cost	$	4,949		$	5,121		$	2,607		$	2,832		$	4,843		$	5,646		$	2,394		$	2,882
Six months ended June 30:
Service cost													$	12,500		$	11,096		$	1,905		$	1,959
Interest cost														13,110			13,938			2,685			3,039
Expected return on plan assets														(19,479	)		(17,750	)		(1,458	)		(1,220	)
Amortization of prior service cost														150			150			(550	)		(550	)
Net loss recognition														3,511			3,333			2,419			2,486
Net periodic benefit cost													$	9,792		$	10,767		$	5,001		$	5,714

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.

NOTE 7. INCOME TAXES

In accordance with interim reporting requirements, the Company uses an estimated annual effective tax rate for computing its provisions for income taxes. An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments, and tax credits. The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements, accounting method changes, or adjustments to tax expense or benefits attributable to prior years. Discrete events are recorded in the interim period in which they occur or become known. The estimated annual tax rate is applied to year-to-date pre-tax income to determine income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period’s year-to-date amount.

The following table summarizes the significant factors impacting the difference between our effective tax rate and the federal statutory rate for the three and six months ended ~~March 31~~June 30 (dollars in thousands):


	Three months ended June 30,										Six months ended June 30,
	2021					2020					2021					2020
Federal income taxes at statutory rates	$	3,459		21.0	%	$	2,002		21.0	%	$	20,297		21.0	%	$	13,963		21.0	%
Increase (decrease) in tax resulting from:
Tax effect of regulatory treatment of utility plant differences		(3,204	)	(19.5	)		(2,415	)	(25.3	)		(6,444	)	(6.7	)		(4,817	)	(7.2	)
State income tax expense		280		1.7			(325	)	(3.4	)		832		0.9			902		1.4
Non-plant excess deferred turnaround (1)		0		0			(8,390	)	(88.0	)		0		0			(8,476	)	(12.7	)
Settlement of equity awards		(21	)	(0.1	)		0		0			909		1.0			165		0.1
Other		1,884		11.5			1,209		12.7			(1,032	)	(1.1	)		(1,124	)	(1.7	)
Total income tax expense	$	2,398		14.6	%	$	(7,919	)	(83.0	)%	$	14,562		15.1	%	$	613		0.9	%

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
%
(1)

In March 2020, the WUTC approved an all-party settlement agreement related to electric tax benefits that were set aside for Colstrip in the 2020 general rate case order. In the approved settlement agreement, the parties agreed to utilize $10.9 million ($8.4 million when tax-effected) of the electric tax benefits to offset costs associated with accelerating the depreciation of Colstrip Units 3 & 4, to reflect a remaining useful life of those units through December 31, 2025. In the second quarter 2020, the Company recorded a one-time increase to depreciation expense with an offsetting decrease to income tax expense.

NOTE 8. COMMITTED LINES OF CREDIT

Avista Corp.

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

Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company’s revolving committed line of credit were as follows as of ~~March 31,~~June 30, 2021 and December 31, 2020 (dollars in thousands):


	June 30,			December 31,
	2021			2020
Balance outstanding at end of period	$	296,000		$	102,000
Letters of credit outstanding at end of period	$	24,118		$	27,618
Average interest rate at end of period		1.08	%		1.22	%

March 31,

December 31,

2021

2020

Balance outstanding at end of period

$
93,000

$
102,000

Letters of credit outstanding at end of period

$
16,618

$
27,618

Average interest rate at end of period

1.17
%

1.22
%

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AVISTA CORPORATION

As of ~~March 31,~~June 30, 2021 and December 31, 2020, the borrowings outstanding under Avista Corp.'s committed line of credit were classified as short-term borrowings on the Condensed Consolidated Balance Sheet.

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~~AVISTA CORPORATION~~

AEL&P

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,~~June 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 June 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 9. CREDIT AGREEMENT

In April 2020, the Company entered into a one-year Credit Agreement with various financial institutions, in the amount of ~~$100~~$100.0 million. The Company borrowed the entire ~~$100.0~~$100.0 million in April 2020 and repaid the outstanding balance in April ~~2021.~~2021.

NOTE 10. LONG-TERM DEBT TO AFFILIATED TRUSTS

In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of ~~$51.5~~$51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued ~~$50.0~~$50.0 million of Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly.

The distribution rates paid were as follows during the ~~three~~six months ended ~~March 31,~~June 30, 2021 and the year ended December 31, 2020:


	March 31,			December 31,			June 30,			December 31,
	2021			2020			2021			2020
Low distribution rate		1.07	%		1.10	%		1.01	%		1.10	%
High distribution rate		1.10	%		2.79	%		1.10	%		2.79	%
Distribution rate at the end of the period		1.07	%		1.10	%		1.01	%		1.10	%

Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued ~~$1.5~~$1.5 million of Common Trust Securities to the Company. The Preferred Trust Securities may be redeemed at the option of Avista Capital II at any time and mature on June 1, 2037. In December 2000, the Company purchased ~~$10.0~~$10.0 million of these Preferred Trust Securities.

The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on, and redemption price and liquidation amount for, the Preferred Trust Securities to the extent that Avista Capital II has funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust Securities will be mandatorily redeemed. The Company does not include these capital trusts in its consolidated financial statements as Avista Corp. is not the primary beneficiary. As such, the sole assets of the capital trusts are ~~$51.5~~$51.5 million of junior subordinated deferrable interest debentures of Avista Corp., which are reflected on the Condensed Consolidated Balance Sheets. Interest expense to affiliated trusts in the Condensed Consolidated Statements of Income represents interest expense on these debentures.

NOTE 11. 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 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 than 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).

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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,~~June 30, 2021 and December 31, 2020 (dollars in thousands):


	June 30, 2021				December 31, 2020
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	963,500	$	1,167,592	$	963,500	$	1,189,824
Long-term debt (Level 3)		1,060,000		1,187,539		1,060,000		1,235,248
Snettisham finance lease obligation (Level 3)		50,283		56,200		51,750		58,700
Long-term debt to affiliated trusts (Level 3)		51,547		63,511		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 of ~~85.00~~98.02 to ~~136.39,~~138.97, where a par value of 100.0 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,~~June 30, 2021 and December 31, 2020.

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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,~~June 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
June 30, 2021
Assets:
Energy commodity derivatives	$	0	$	41,385	$	0	$	(34,984	)	$	6,401
Level 3 energy commodity derivatives:
Natural gas exchange agreement		0		0		119		(119	)		0
Interest rate swap derivatives		0		3,284		0		(1,966	)		1,318
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		1,963		0		0		0			1,963
Equity securities (2)		7,585		0		0		0			7,585
Total	$	9,548	$	44,669	$	119	$	(37,069	)	$	17,267
Liabilities:
Energy commodity derivatives	$	0	$	42,367	$	0	$	(41,150	)	$	1,217
Level 3 energy commodity derivatives:
Natural gas exchange agreement		0		0		6,197		(119	)		6,078
Foreign currency exchange derivatives		0		88		0		0			88
Interest rate swap derivatives		0		38,135		0		(7,816	)		30,319
Total	$	0	$	80,590	$	6,197	$	(49,085	)	$	37,702
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)

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.

~~(1)~~

(2)

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

~~(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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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,~~June 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,~~June 30, 2021 (dollars in thousands):


	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	June 30, 2021			Technique	Input	Average Price
Natural gas exchange agreement	$	(6,078	)	Internally derived weighted average cost of gas	Forward purchase	$1.97 - $4.10/mmBTU $2.49 Weighted Average
					Forward sales prices	$2.09 - $5.08/mmBTU $3.69 Weighted Average
					Purchase volumes	40,000 - 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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The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the ~~three~~six months ended ~~March 31~~June 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 June 30, 2021:
Balance as of March 31, 2021		$	(6,201	)
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.		268

Settlements			(145	)
Ending balance as of June 30, 2021 (2)	~~There were no purchases, issuances~~	$	(6,078	)
Three months ended June 30, 2020:
Balance as of March 31, 2020		$	(2,253	)
Total gains or ~~transfers from other categories~~(losses) (realized/unrealized):
Included in regulatory assets/liabilities (1)			(391	)
Settlements			16
Ending balance as of ~~any derivatives instruments during the periods presented~~June 30, 2020 (2)		$	(2,628	)
Six months ended June 30, 2021:
Balance as of December 31, 2020		$	(8,410	)
Total gains (realized/unrealized):
Included in ~~the table above.~~regulatory assets/liabilities (1)			3,488
Settlements			(1,156	)
Ending balance as of June 30, 2021 (2)		$	(6,078	)
Six months ended June 30, 2020:
Balance as of December 31, 2019		$	(2,976	)
Total gains (realized/unrealized):
Included in regulatory assets/liabilities (1)			94
Settlements			254
Ending balance as of June 30, 2020 (2)		$	(2,628	)

(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. 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~~approximately 3.9 million shares of common stock in ~~addition to the 1.3 million shares previously authorized but remaining unissued.~~public offerings. During the three and six months ended ~~March 31,~~June 30, 2021, ~~and March 31, 2020,~~ the Company ~~did 0t issue~~issued 0.3 million shares under the sales agency ~~agreements.~~agreements relating to the Company's periodic offering program.

NOTE 13. ACCUMULATED OTHER COMPREHENSIVE LOSS

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


	June 30, 2021		December 31, 2020
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $3,656 and $3,822, respectively	$	13,755	$	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 six months ended ~~March 31~~June 30 (dollars in thousands):


	Amounts Reclassified from Accumulated Other Comprehensive Loss
	Three months ended June 30,						Six months ended June 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	)	$	(400	)	$	(400	)
Amortization of net loss (a)		2,739			3,121			5,930			6,221
Adjustment due to effects of regulation (a)		(2,149	)		(2,642	)		(4,741	)		(5,283	)
Total before tax (b)		390			279			789			538
Tax expense (b)		(82	)		(59	)		(166	)		(113	)
Net of tax (b)	$	308		$	220		$	623		$	425

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. EARNINGS PER COMMON SHARE

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


					Three months ended June 30,				Six months ended June 30,
	2021		2020		2021		2020		2021		2020
Numerator:
Net income	$	68,017	$	48,424	$	14,074	$	17,453	$	82,091	$	65,877
Denominator:
Weighted-average number of common shares outstanding-basic		69,293		67,239		69,404		67,481		69,348		67,360
Effect of dilutive securities:
Performance and restricted stock awards		213		142		130		108		172		125
Weighted-average number of common shares outstanding-diluted		69,506		67,381		69,534		67,589		69,520		67,485
Earnings per common share:
Basic	$	0.98	$	0.72	$	0.20	$	0.26	$	1.18	$	0.98
Diluted	$	0.98	$	0.72	$	0.20	$	0.26	$	1.18	$	0.98

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

NOTE 15. COMMITMENTS AND CONTINGENCIES

In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.

Boyds Fire (State of Washington Department of Natural Resources (DNR) v. Avista)

In August 2019, the Company was served with a complaint, captioned “State of Washington Department of Natural Resources v. Avista Corporation,” seeking recovery up to ~~$4.4~~$4.4 million for fire suppression and investigation costs and related expenses incurred in connection with a wildfire that occurred in Ferry County, Washington in August 2018. Specifically, the complaint alleges that the fire, which became known as the “Boyds Fire,” was caused by a dead ponderosa pine tree falling into an overhead distribution line, and

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that Avista Corp. was negligent in failing to identify and remove the tree before it came into contact with the line. Avista Corp.

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~~AVISTA CORPORATION~~

disputes that the tree in question was the cause of the fire and that it was negligent in failing to identify and remove it. Additional lawsuits have subsequently been filed by private landowners seeking property damages, and holders of insurance subrogation claims seeking recovery of insurance proceeds paid.

The lawsuits were filed in the Superior Court of Ferry County, Washington and subsequently consolidated into a single action. The Company intends to vigorously defend itself in the litigation. However, the Company cannot predict the outcome of these matters.

Labor Day Windstorm

General

In September 2020, a severe windstorm occurred in eastern Washington and northern Idaho. The extreme weather event resulted in customer outages and the cause of multiple wildfires in the region. With respect to wildfires, the Company’s investigation determined that the primary cause of the fires was extreme high winds. To date, the Company has not found any evidence that the fires were caused by any deficiencies in its equipment, maintenance activities or vegetation management practices.

The Company has become aware of instances where, during the course of the storm, ~~otherwise healthy~~ trees and limbs, located in areas outside its maintenance right-of-way, broke under the extraordinary wind conditions and caused damage to its energy delivery system at or near what is believed to be the potential area of origin of a wildfire. Those instances include what has been referred to as: the Babb Road fire (near Malden and Pine City, Washington); the Christensen Road fire (near Airway Heights, Washington); and the Mile Marker 49 fire (near Orofino, Idaho). These wildfires covered, in total, approximately 22,000 acres. The Company currently estimates approximately 230 residential, commercial and other structures were impacted. Parallel investigations by applicable state agencies ~~including the Washington Department of Natural Resources,~~ are ongoing, and the Company is cooperating with those efforts. With respect to the Christensen Road Fire and the Mile Marker 49 Fire, the Company’s investigation determined that the primary cause of the fires was extreme high winds. To date, the Company has not found any evidence that the fires were caused by any deficiencies in its equipment, maintenance activities or vegetation management practices. See further discussion below regarding the Babb Road Fire.

In addition to the instances identified above, the Company is aware of a 5-acre fire that occurred in Colfax, Washington, which damaged several residential structures. The Company’s investigation ~~has found~~determined that the Company’s facilities were not involved in the ignition of this fire in any way.

The Company contends that there is no evidence of negligence ~~with respect to any of the fires,~~ and ~~the Company~~ intends to vigorously defend any claims for damages that may be asserted against it with respect to the wildfires arising out of the extreme wind event.

~~Colstrip~~Babb Road Fire

On May 14, 2021 the Company learned that the DNR had completed its investigation and issued a report on the Babb Road Fire. The Babb Road fire covered approximately 15,000 acres and destroyed approximately 220 structures. There are no reports of personal injury or death resulting from the fire.

The DNR report concluded, among other things, that



the fire was ignited when a branch of a multi-dominant Ponderosa Pine tree was broken off by the wind and fell on an Avista Corp. distribution line;



the tree was located approximately 30 feet from the center of Avista Corp.’s distribution line and approximately 20 feet beyond Avista Corp.’s right-of-way;



the tree showed some evidence of insect damage, damage at the top of the tree from porcupines, a small area of scarring where a lateral branch/leader (LBL) had apparently broken off in the past, and some past signs of Gall Rust disease.

The DNR report concluded as follows: “It is my opinion that because of the unusual configuration of the tree, and its proximity to the powerline, a closer inspection was warranted. A nearer inspection of the tree should have revealed the cut LBL ends and its previous failure, and necessitated determination of the failure potential of the adjacent LBL, implicated in starting the Babb Road Fire.”

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The DNR report acknowledged that, other than the multi-dominant nature of the tree, the conditions mentioned above would not have been easily visible without close-up inspection of, or cutting into, the tree. The report also acknowledged that, while the presence of multiple tops would have been visible from the nearby roadway, the tree did not fail at a v-fork due to the presence of multiple tops. The Company contends that applicable inspection standards did not require a closer inspection of the otherwise healthy tree, nor was the Company in any way negligent with respect to its maintenance, inspection or vegetation management practices. The Company intends to vigorously defend any such assertion, if made. At this time, no material claims have been asserted against Avista Corp. for damages resulting from the Babb Road Fire.

Colstrip

The Washington CETA imposes deadlines by which coal-fired resources, such as Colstrip, must be excluded from the rate base of Washington utilities and by which electricity from such resources may no longer be delivered to Washington retail customers. Not all of the co-owners of Colstrip Units 3 & 4 are Washington utilities subject to CETA, and the co-owners have differing needs for the generating capacity of these units. Accordingly, business disagreements have arisen among the co-owners, including, but not limited to, disagreements as to the shut-down date or dates of these units. These business disagreements, in turn, have led to disagreements as to the interpretation of the Ownership and Operating Agreement, including, but not limited to, the rights of the co-owners to discontinue operations of, or otherwise terminate their interest in, Unit 3 and/or Unit 4. ~~In order~~The Ownership and Operating Agreement does contain an arbitration clause that dictates a dispute resolution process to address and resolve these ~~disagreements,~~disagreements. At least one owner, Talen Montana, has challenged the ~~owners have commenced an~~validity of the arbitration ~~proceeding as provided for~~clause contained in the Ownership and Operating ~~Agreement.~~Agreement on the basis that it is not consistent with recently-enacted amendments to Montana Code Section 27-5-323. Along with a majority of the owners of Colstrip, the Company has initiated legal proceedings in Washington to compel arbitration in accordance with the Ownership and Operating Agreement, as well as legal proceedings in Montana to challenge the constitutionality of the amendments to Montana Code Section 27-5-323.

In addition to amending Montana Code Section 27-5-323, during the course of the 2021 legislative session the Montana Legislature passed two bills specifically directed at the ownership and operation of Colstrip. The first, Montana Senate Bill 265, purports to amend Section 27-5-323 of the Montana Code to provide that an agreement designating venue or disputes involving an electric generation facility located in Montana is not valid unless it requires arbitration in Montana before a panel of three arbitrators. The Ownership and Operating Agreement for Colstrip Units 3 & 4 includes an arbitration provision, through which all owners agreed to resolve disputes regarding the Agreement through arbitration in Spokane County, Washington before a single arbitrator. The Company, together with Puget Sound Energy, Portland General Electric, and PacifiCorp (Pacific Northwest Colstrip owners), has commenced an action in Spokane County Superior Court to compel arbitration of the pending disputes regarding interpretation of the Ownership & Operating Agreement in accordance with the requirements of the parties’ Agreement. The Pacific Northwest Colstrip owners have also commenced action in the U.S. District Court for the District of Montana to challenge the legality and constitutionality of the legislation.

~~The Montana Legislature has also passed Montana~~ Senate Bill 266, which ~~would~~amended Montana’s Consumer Protection Act (MC 30-14-103 et seq.) to make it(i) the failure or refusal of an owner of Colstrip to fund its share of operating costs, and (ii) conduct by one or more of the owners of Colstrip to bring about permanent closure of a generating unit of Colstrip without seeking and obtaining the unanimous consent of the owners, an unfair or deceptive act or practice ~~within~~in the ~~meaning~~conduct of trade or commerce under Montana’s Consumer Protection ~~Act, for one or more~~Act. Along with a majority of the owners of ~~a jointly owned electrical generation facility~~Colstrip, the Company has initiated legal proceedings to ~~fail to fund its share~~challenge the constitutionality of ~~operating costs associated with that facility, or to engage in any conduct that would bring about a permanent closure~~

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~~of one or more generating units of such a facility without first obtaining the consent of all co-owners of that facility.~~Senate Bill 266. The Company intends to ~~challenge the legality~~vigorously defend and ~~constitutionality~~protect its interests (and those of its stakeholders) in this ~~bill as well.~~and all other legal proceedings relating to Colstrip.

The Company is not able to predict the outcome, nor an amount or range of potential impact in the event of an outcome that is adverse to the Company’s interests.

National Park Service (NPS) - Natural and Cultural Damage Claim

In March 2017, the Company accessed property managed by the National Park Service (NPS) to prevent the imminent failure of a power pole that was surrounded by flood water in the Spokane River. The Company voluntarily reported its actions to the NPS several days later. Thereafter, in March 2018, the NPS notified the Company that it might seek recovery for unspecified costs and damages allegedly caused during the incident pursuant to the System Unit Resource Protection Act (SURPA), 54 U.S.C. 100721 et seq. Almost three years later, in January 2021, the United States Department of Justice (DOJ) requested that the Company and the DOJ renew discussions relating to the matter. By letter dated July 7, 2021, the DOJ communicated that it may seek damages of approximately $2 million in connection with the incident for alleged damage to "natural and cultural resources". In addition, the DOJ indicated that it may seek treble damages under the SURPA and state law, bringing its total potential claim to approximately $6 million.

The Company disputes the position taken by the DOJ with respect to the incident, as well as the nature and extent of the DOJ’s alleged damages, and will vigorously defend itself in any litigation that may arise with respect to the matter. The Company and the DOJ have agreed to engage in fact finding discussions to understand their respective positions and determine whether a resolution of the dispute may be possible. However, the Company cannot predict the outcome of the matter.

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Other Contingencies

In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes that any ultimate liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant. See "Note 22 of the Notes to Consolidated Financial Statements" in the 2020 Form 10-K for additional discussion regarding other contingencies.

NOTE 16. 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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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 June 30, 2021:
Operating revenues	$	287,560		$	10,547	$	298,107		$	148		$	0		$	298,255
Resource costs		89,515			1,163		90,678			0			0			90,678
Other operating expenses		90,728			3,325		94,053			1,159			0			95,212
Depreciation and amortization		53,569			2,497		56,066			73			0			56,139
Income (loss) from operations		29,561			3,275		32,836			(1,084	)		0			31,752
Interest expense (2)		24,608			1,523		26,131			131			(25	)		26,237
Income taxes		585			468		1,053			1,345			0			2,398
Net income		7,717			1,299		9,016			5,058			0			14,074
Capital expenditures (3)		114,441			2,183		116,624			537			0			117,161
For the three months ended June 30, 2020:
Operating revenues	$	268,340		$	9,997	$	278,337		$	255		$	0		$	278,592
Resource costs		67,069			896		67,965			0			0			67,965
Other operating expenses		83,140			3,064		86,204			659			0			86,863
Depreciation and amortization		61,462			2,446		63,908			188			0			64,096
Income (loss) from operations		32,217			3,302		35,519			(593	)		0			34,926
Interest expense (2)		24,188			1,561		25,749			130			(47	)		25,832
Income taxes		(8,004	)		480		(7,524	)		(395	)		0			(7,919	)
Net income (loss)		17,605			1,328		18,933			(1,480	)		0			17,453
Capital expenditures (3)		91,867			2,087		93,954			477			0			94,431
For the six months ended June 30, 2021:
Operating revenues	$	687,420		$	23,368	$	710,788		$	337		$	0		$	711,125
Resource costs		223,355			1,902		225,257			0			0			225,257
Other operating expenses		175,327			6,281		181,608			2,343			0			183,951
Depreciation and amortization		106,293			4,994		111,287			200			0			111,487
Income (loss) from operations		126,254			9,599		135,853			(2,206	)		0			133,647
Interest expense (2)		49,408			3,048		52,456			260			(66	)		52,650
Income taxes		11,303			1,801		13,104			1,458			0			14,562
Net income		71,775			4,775		76,550			5,541			0			82,091
Capital expenditures (3)		210,835			2,992		213,827			565			0			214,392
For the six months ended June 30, 2020:
Operating revenues	$	645,545		$	22,199	$	667,744		$	1,078		$	0		$	668,822
Resource costs		196,625			887		197,512			0			0			197,512
Other operating expenses		174,420			6,280		180,700			2,019			0			182,719
Depreciation and amortization		110,436			4,893		115,329			423			0			115,752
Income (loss) from operations		108,935			9,548		118,483			(1,364	)		0			117,119
Interest expense (2)		49,171			3,149		52,320			262			(132	)		52,450
Income taxes		(600	)		1,781		1,181			(568	)		0			613
Net income (loss)		63,584			4,723		68,307			(2,430	)		0			65,877
Capital expenditures (3)		185,923			3,557		189,480			586			0			190,066
Total Assets:
As of June 30, 2021:	$	6,272,062		$	270,922	$	6,542,984		$	116,654		$	(13,337	)	$	6,646,301
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.

~~(1)~~33

~~Intersegment eliminations reported as interest expense represent intercompany interest.~~

~~(2)~~

~~Including interest expense to affiliated trusts.~~

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~~(3)~~

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of

Avista Corporation

Spokane, Washington

Results of Review of Interim Financial Information

We have reviewed the accompanying condensed consolidated balance sheet of Avista Corporation and subsidiaries (the "Company") as of ~~March 31,~~June 30, 2021, the related condensed consolidated statements of income, comprehensive income, and equity, for the three-month and six-month periods ended June 30, 2021 and 2020 and of cash flows for the ~~three-month~~six-month periods ended ~~March 31,~~June 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.

Basis for Review Results

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.

/s/ Deloitte & Touche LLP

Portland, Oregon

~~May 4,~~August 3, 2021

3334

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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.

Business Segments

Our business segments have not changed during the ~~three~~six months ended ~~March 31,~~June 30, 2021. See the 2020 Form 10-K as well as “Note 16 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 six months ended ~~March 31~~June 30 (dollars in thousands):

2021

2020

Avista Utilities

$
64,058

$
45,979

AEL&P

3,476

3,395

Other

483

(950
)
Net income

$
68,017

$
48,424


	Three months ended June 30,					Six months ended June 30,
	2021		2020			2021		2020
Avista Utilities	$	7,717	$	17,605		$	71,775	$	63,584
AEL&P		1,299		1,328			4,775		4,723
Other		5,058		(1,480	)		5,541		(2,430	)
Net income	$	14,074	$	17,453		$	82,091	$	65,877

Executive Level Summary

Overall Results

Avista Utilities' net income for the three months ended ~~March 31,~~June 30, 2021 ~~increased~~decreased compared to the three months ended ~~March 31,~~June 30, 2020 primarily due to ~~an increase~~a decrease in utility margin (operating revenues less resource costs) as a result of higher power supply costs and to higher operating and maintenance costs. These higher resource costs were partially offset by increases in revenues attributable to an increase in loads from non-decoupled customers due to weather that was warmer than the second quarter of 2020, eased COVID-19 restrictions, and customer growth. Net income for the first half of 2021 increased compared to the first half of 2020 primarily due to an increase in utility margin as a result of general rate increases, ~~in Washington and Oregon~~non-decoupled revenue growth and customer ~~growth.~~growth, which were partially offset by higher power supply costs. In addition, ~~during~~ the first ~~quarter~~half of 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 and the sale of certain subsidiary assets associated with the Spokane Steam Plant during the second quarter. During the first half of 2020, we had impairment losses and accruals for bad debt.

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.

Heat Wave

At the end of June 2021, the Pacific Northwest experienced an unprecedented heat wave. Many locations set all-time high temperature records. Our peak electric native load requirement was 1,889 MW on June 30, 2021, the highest in the Company’s history. As a result of the high system loads and the strain on the electric grid, we implemented focused, protective outages that impacted 22,000 electric customers. These outages were a protective measure intended to minimize broader customer impact and prevent extensive damage to the system that could have resulted in prolonged outages. The protective outages did not have a material impact on our electric revenue.

The second quarter is usually our highest hydroelectric generation period and 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 due, for the most part, to the hot and dry weather conditions throughout the Pacific Northwest, which resulted in higher than usual customer loads and lower

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than usual hydroelectric generation. This condition was compounded by our thermal plants having planned maintenance outages and being off-line during the first part of the heat wave.

Consequently, we had higher than usual net power supply costs primarily due to higher customer loads, lower than normal hydroelectric generation, as well as higher market prices for purchased power and natural gas for fuel. Our position in the ERM in Washington moved from a benefit of $4.3 million at March 31, 2021 to an expense of $3.3 million at June 30, 2021.

COVID-19 Pandemic

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 less severe than the prior year. This was the case in the second quarter. The pandemic has affected and may continue to affect our results of operations, financial condition, liquidity and cash flows in the following ways:

Results of Operations

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.

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Customer disconnections for non-payment in our Washington ~~and Oregon jurisdictions~~jurisdiction continue to be ~~suspended.~~suspended until September 30, 2021. In ~~Washington, there is a moratorium on~~our Oregon jurisdiction, customer disconnections for ~~residential and commercial customers until July 31, 2021. In Oregon, there is a moratorium on disconnections for residential customers until June 30,~~non-payment resumed August 1, 2021.

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,~~June 30, 2021, we have deferred a cumulative regulatory asset of ~~$11.8~~$14.3 million and a cumulative regulatory liability of ~~$11.6~~$12.7 million for COVID-19 related items among all jurisdictions. As of December 31, 2020, we had deferred a cumulative regulatory asset of $8.2 million and a cumulative regulatory liability of $10.9 million among all jurisdictions.

Financial Condition, Liquidity and Cash Flows

~~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.

Regulatory Matters

General Rate Cases

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:



seek recovery of operating costs and capital investments, and



seek the opportunity to earn reasonable returns as allowed by regulators.

•

~~seek recovery of operating costs and capital investments, and~~

•

~~seek the opportunity to earn reasonable returns as allowed by regulators.~~

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.

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Avista Utilities

Washington General Rate Cases

2019 General Rate Cases

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) 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.

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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 in a future test period.

2020 General Rate Cases

In October 2020, we filed electric and natural gas general rate cases with the WUTC. We have requested an overall increase in base electric revenues 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.

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.

In May 2021, we reached a partial settlement agreement with certain parties to our Washington electric and natural gas general rate cases and submitted the partial settlement agreement to the WUTC for its consideration. Under the partial settlement stipulation, the settling parties have reached agreement on issues in the areas of power supply, costs and benefits related to joining the Western Energy Imbalance Market, a special contract with a large industrial customer, and other issues.

In May 2021, we filed our Rebuttal Testimony, which was responsive to the testimonies filed by other parties to the case in April 2021 and addressed the remaining issues. We lowered our requested revenue requirement from $44.2 million electric and $12.8 million natural gas to $40.2 million electric and $10.7 million natural gas, reflecting updated information learned during the pendency of the case. We continue to support a 9.9 percent ROE and a common equity ratio of 50 percent. A final order is expected prior to the rate effective date of October 1, 2021.

Washington Engrossed Substitute Senate Bill 5295

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 of the rate plan, allow~~and/or adjust for ~~an out-of-cycle multi-year rate plan should the utility underearn;~~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~~The new law leaves much to the discretion of the WUTC, and we cannot predict the extent to which the WUTC will ~~require commissioners, present and future, to effectuate~~embrace the ~~change.~~options now permitted.

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Idaho General Rate Cases

2021 General Rate Cases

In January 2021, we filed electric and natural gas general rate cases with the IPUC. The proposal is a two-year rate plan, with new rates taking effect September 1, 2021 and September 1, 2022. ~~The~~

In June 2021, all parties to our Idaho electric and natural gas ~~incorporate~~general rate cases reached a settlement agreement that has been submitted to the IPUC for consideration.

The proposed ~~ROR~~rates 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 included in our original filing to offset overall proposed changes to electric and natural gas rates over the two-year plan.

The settlement is based on ~~rate base of 7.30~~a 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.

Oregon General Rate Cases

2020 General Rate Case

In March 2020, we filed a natural gas general rate case with the OPUC.

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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.

2021 General Rate Case

We expect to file a natural gas general rate case with the OPUC in the ~~second half~~fourth quarter of 2021.

AEL&P

Alaska General Rate Case

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

Avista Utilities

Purchased Gas Adjustments

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~~$8.7 million and $1.4 million as of ~~March 31,~~June 30, 2021 and December 31, 2020, respectively.

Power Cost Deferrals and Recovery Mechanisms

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

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were liabilities of ~~$32.8~~$28.1 million and $37.9 million as of ~~March 31,~~June 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~~$7.7 million as of ~~March 31,~~June 30, 2021 and $2.5 million as of December 31, 2020. These deferred power cost balances represent amounts due from customers.

Decoupling Mechanisms

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

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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~~$19.1 million as of ~~March 31,~~June 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.

Results of Operations - Overall

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.

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

The following graph shows the total change in net income for the ~~first~~second quarter of 2021 compared to the ~~first~~second 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 second quarter of 2020. This was primarily due to increased electric loads from non-decoupled customers due to weather that was warmer than the second quarter of 2020 and reduced COVID-19 restrictions. In addition, utility revenues increased due to general rate increases in ~~Washington and~~ Oregon and customer growth. ~~During the first quarter 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 "Heat Wave" 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.

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 a result of delayed maintenance projects during the second quarter of 2020 due to COVID-19 restrictions. In the second quarter of 2021, we had a maintenance schedule that was closer to normal. This was partially offset by a decrease in bad debt expense. During the second quarter of 2020, we had not received regulatory approval to defer COVID-19 related bad debt expense, whereas we deferred COVID-19 related bad debt expense during the second quarter of 2021.

Utility depreciation and amortization ~~increased~~decreased primarily due to a one-time increase in depreciation expense during the second quarter 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 Units 3 & 4 based on a settlement in Washington. This decrease to utility depreciation and amortization was partially offset by additions to utility plant.

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

Income taxes increased primarily due to ~~an increase~~a decrease in tax expense during the second quarter of 2020 relating to the offset of deferred income ~~before taxes.~~taxes against accelerated depreciation for Colstrip as provided in the 2019 Washington general rate case settlement. This amounted was $8.4 million in 2020. Our effective tax rate was ~~15.2~~14.6 percent for the ~~first~~second quarter of 2021 compared to ~~15.0~~negative 83 percent for the ~~first~~second quarter of 2020. See “Note 7 of the Notes to Condensed Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate.

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Six months ended June 30, 2021 compared to the six months ended June 30, 2020

Utility revenues increased at Avista Utilities primarily due increased loads from non-decoupled customers as a result of reduced COVID-19 restrictions during the first half of 2021 and weather that was warmer than normal and the prior year in the second quarter. In addition, utility revenues increased due to general rate increases in Washington and Oregon and customer growth. During the first half 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 "Heat Wave" 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 increase in utility operating expenses was primarily due to increases in generation and distribution operating and maintenance costs at Avista Utilities. The increases were partially offset by an accrual during the first half of 2020 for disallowed replacement power during an unplanned outage at Colstrip and a decrease in bad debt expense when compared to the first half of 2020. During the first six months of 2020, we had not received regulatory approval to defer COVID-19 related bad debt expense, whereas we deferred COVID-19 related bad debt expense during the first half of 2021.

Utility depreciation and amortization decreased primarily due to a one-time increase to depreciation expense during the first half 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 Units 3 & 4 based on a settlement in Washington. This was partially offset by additions to utility plant.

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

Income taxes increased primarily due to a decrease in tax expense during the first half of 2020 relating to the offset of deferred income taxes against accelerated depreciation for Colstrip as provided in the 2019 Washington general rate case settlement. This was $8.4 million in 2020. In addition, income taxes increased due to an increase in income before taxes. Our effective tax rate was 15.1 percent for the first half of 2021 compared to 0.9 percent for the first half of 2020. See “Note 7 of the Notes to Condensed Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate.

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Non-GAAP Financial Measures

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 16 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.

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Results of Operations - Avista Utilities

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

Utility Operating Revenues

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

(1)

This balance includes public street and highway lighting, which is considered part of retail electric revenues.

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~~(1)~~

~~This balance includes public street and highway lighting, which is considered part of retail electric revenues.~~

Total electric operating revenues in the graph above include intracompany sales of ~~$6.0~~$6.5 million and ~~$6.1~~$8.8 million for the three months ended ~~March 31,~~June 30, 2021 and 2020, respectively.

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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~~June 30 (dollars in thousands):


	Electric Decoupling Revenues
	2021			2020
Current year decoupling deferrals (a)	$	(4,765	)	$	5,842
Amortization of prior year decoupling deferrals (b)		(3,249	)		(3,658	)
Total electric decoupling revenue	$	(8,014	)	$	2,184

Electric Decoupling Revenues

2021

2020

Current year decoupling deferrals (a)

$
4,326

$
5,131

Amortization of prior year decoupling deferrals (b)

(3,545
)

(4,608
)
Total electric decoupling revenue

$
781

$
523

(a)

Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.

(b)

Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

~~(a)~~

~~(b)~~

Total electric revenues increased ~~$11.4~~$14.2 million for the ~~first~~second quarter of 2021 as compared to the ~~first~~second quarter of 2020. The primary fluctuations that occurred during the period were as follows:

•

~~a $2.7 million increase in retail electric revenue due to an increase in revenue per MWh (increased revenues $2.5 million) and an increase in total MWhs sold (increased revenues $0.2 million).~~



a $20.6 million increase in retail electric revenue due to an increase in MWhs sold.

~~The increase in revenue per MWh was primarily due to a general rate increase in Washington, effective April 1, 2020.~~

The increase in total retail MWhs sold was primarily the result of weather that was warmer than normal and the prior year, which increased cooling loads, and customer growth. Also, there was a lifting of COVID-19 restrictions during the second quarter of 2021, which contributed to the increased loads for our commercial and industrial customers. Compared to the second quarter of 2020, residential electric use per customer increased 5 percent and commercial use per customer increased 16 percent. Cooling degree days in Spokane were significantly above normal and the second quarter of 2020, which resulted in our highest peak load in company history. Heating degree days in Spokane were 22 percent below normal, and 19 percent below the second quarter of 2020. See "Heat Wave" in the Executive Level Summary above.

The increase in total retail MWhs sold was primarily the result of an increase in residential sales volumes and customer growth. This was partially offset by a decrease in commercial sales volumes mostly due to the impact of COVID-19. In addition, weather was colder than the prior year, which increased heating loads. Compared to the first quarter of 2020, residential electric use per customer increased 2 percent and commercial use per customer decreased 5 percent. Heating degree days in Spokane were 3 percent below normal, but 3 percent above the first quarter of 2020.

•

a $0.7 million decrease in wholesale electric revenues due to a decrease in sales volumes (decreased revenues $5.2 million), partially offset by an increase in sales prices (increased revenues $4.5 million). The fluctuation in volumes was primarily the result of differences in the available opportunities for us to optimize our generation assets as compared to the prior year.

•

~~a $7.4 million increase in sales of fuel as part of thermal generation resource optimization activities.~~

•

a $0.3 million increase in electric decoupling revenue, with most of the surcharges in 2021 resulting from lower than normal usage for non-residential customers. There were also smaller surcharges to residential customers due to weather that was warmer than normal.

•

~~a $1.7 million increase in other primarily because in the first quarter of 2020, we accrued $1.4 million for customer refunds related to our 2015 Washington general rate case.~~

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

a $7.7 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $5.9 million) and a decrease in sales volumes (decreased revenues $1.8 million). The fluctuation of volumes is because in the current year we had to utilize our thermal generation assets more than normal due to lower than normal hydroelectric generation and to serve increased customer loads. This limited our opportunities to sell generation in the wholesale power markets as compared to the second quarter of 2020.



a $12.0 million increase in sales of fuel as part of thermal generation resource optimization activities.



a $10.2 million decrease in electric decoupling revenue. The rebates in 2021 resulted from higher than normal usage from residential and non-residential customers because of weather that was warmer than normal.

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

(1)

This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues.

~~(1)~~

~~This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues.~~

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Total natural gas operating revenues in the graph above include intracompany sales of ~~$12.5~~$14.1 million and ~~$12.8~~$11.2 million for the three months ended ~~March 31,~~June 30, 2021 and 2020, respectively.

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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~~June 30 (dollars in thousands):


	Natural Gas Decoupling Revenues
	2021		2020
Current year decoupling deferrals (a)	$	4,433	$	2,657
Amortization of prior year decoupling deferrals (b)		512		(479	)
Total natural gas decoupling revenue	$	4,945	$	2,178

Natural Gas Decoupling Revenues

2021

2020

Current year decoupling deferrals (a)

$
(1,543
)

$
(3,556
)
Amortization of prior year decoupling deferrals (b)

1,261

(1,380
)
Total natural gas decoupling revenue

$
(282
)

$
(4,936
)
(a)

(b)

~~(a)~~

~~(b)~~

Total natural gas revenues increased ~~$10.8~~$5.5 million for the ~~first~~second quarter of 2021 as compared to the ~~first~~second quarter of 2020. The primary fluctuations that occurred during the period were as follows:

•

a $3.7 million increase in natural gas retail revenues (including industrial, which is included in other) due to an increase in volumes (increased revenues $3.9 million), partially offset by a decrease in retail rates (decreased revenues $0.2 million).



a $0.6 million increase in natural gas retail revenues (including industrial, which is included in other) due to an increase in retail rates (increased revenues $1.0 million), partially offset by a decrease in volumes (decreased revenues $0.4 million).

Retail natural gas sales volumes increased in the first quarter of 2021 as compared to the first quarter of 2020 primarily due to higher residential, commercial and industrial usage and customer growth. The higher residential usage was primarily due to weather that was colder than the prior year, which increased heating loads. Compared to the first quarter of 2020, residential use per customer increased 3 percent, commercial use per customer increased 0.3 percent and industrial use per customer increased 32 percent. Heating degree days in Spokane were 3 percent

Retail rates increased due to general rate increases in Oregon, effective January 16, 2021.

Retail natural gas sales volumes decreased in the second quarter of 2021 as compared to the second quarter of 2020 primarily due to lower residential usage, partially offset by customer growth and increased usage for commercial customers. The lower residential usage was primarily due to weather that was warmer than normal and the prior year, which decreased heating loads in April. The increase in commercial loads was primarily due to the lifting of COVID-19 restrictions during the second quarter of 2021. Compared to the second quarter of 2020, residential use per customer decreased 9 percent and commercial use per customer increased 5 percent. Heating degree days in

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Spokane were 22 percent below normal, and 19 percent below the second quarter of 2020. Heating degree days in Medford were 27 percent below normal and 18 percent below the second quarter of 2020.



a $2.8 million increase in wholesale natural gas revenues due to an increase in prices (increased revenues $12.0 million), partially offset by a decrease in volumes of excess gas sold in the wholesale market (decreased revenues $9.2 million). Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.



a $2.8 million increase in natural gas decoupling revenue primarily due to higher surcharges in the second quarter of 2021. This resulted from lower than normal usage in the second quarter of 2021 because of weather that was warmer than normal.

~~below normal, but 3 percent above the first quarter of 2020. Heating degree days in Medford were normal but 4 percent below the first quarter of 2020.~~

~~Retail rates decreased due to decoupling rate decreases, partially offset by general rate increases in Oregon, effective January 16, 2021 and Washington, effective April 1, 2020.~~

•

a $2.6 million decrease in wholesale natural gas revenues due to a decrease in volumes of excess gas sold in the wholesale market (decreased revenues $13.7 million), partially offset by an increase in prices (increased revenues $11.1 million). Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.

•

~~a $4.6 million increase in natural gas decoupling revenue primarily because in 2020, we were amortizing decoupling surcharges, whereas in 2021, we are amortizing decoupling rebates.~~

•

~~a $5.1 million increase in other primarily because in the first quarter of 2020, we accrued $3.6 million for customer refunds related to our 2015 Washington general rate case.~~

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


	Electric Customers				Natural Gas Customers
	2021		2020		2021		2020
Residential		355,802		349,472		331,795		326,504
Commercial		44,106		43,388		36,463		36,149
Interruptible		—		—		44		38
Industrial		1,209		1,298		189		241
Public street and highway lighting		664		648		—		—
Total retail customers		401,781		394,805		368,491		362,932

Electric Customers

Natural Gas Customers

2021

2020

2021

2020

Residential

354,191

349,368

330,124

326,126

Commercial

43,968

43,300

36,483

36,194

Interruptible

—

—

37

43

Industrial

1,210

1,295

192

241

Public street and highway lighting

649

638

—

—

Total retail customers

400,018

394,601

366,836

362,604

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Utility Resource Costs

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

Total electric resource costs in the graph above include intracompany resource costs of ~~$12.5~~$14.1 million and ~~$12.8~~$11.2 million for the three months ended ~~March 31,~~June 30, 2021 and 2020, respectively.

Total electric resource costs increased ~~$2.3~~$19.2 million for the ~~first~~second quarter of 2021 as compared to the ~~first~~second quarter of 2020. The primary fluctuations that occurred during the period were as follows:

•

~~a $1.3 million increase in power purchased due to an increase in the volume of power purchases (increased costs $2.5 million), partially offset by a decrease in wholesale prices (decreased costs $1.2~~

a $10.1 million increase in power purchased due to an increase in wholesale prices (increased costs $7.8 million) and an increase in the volume of power purchases (increased costs $2.3 million). The fluctuation in volumes was primarily the ~~result of differences in the available opportunities for us to optimize our generation assets as compared to the prior year.~~

•

a $4.3 million increase in fuel for generation primarily related to higher natural gas prices during the first quarter as a result of cold weather throughout the country in February and supply constraints during that same time period.

•

a $5.9 million increase in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.

•

~~a $9.1 million decrease in other electric resource costs, primarily related to increased amortizations associated with the Washington ERM.~~

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

result of differences in the available opportunities for us to optimize our generation assets as compared to the prior year. Additionally, during the second quarter of 2021, we had increased customer loads and lower than normal hydroelectric generation as a result of the heat wave experienced in the Pacific Northwest, which contributed to our need to purchase power. See "Heat Wave" in the Executive Level Summary above.



a $4.0 million increase in fuel for generation primarily related to lower hydroelectric generation and increased retail sales volumes, which required increased thermal generation. Also, there were higher natural gas prices during the second quarter.



a $9.7 million increase in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.



a $4.6 million decrease in other electric resource costs, primarily related to the deferral of increased power supply costs above authorized.

Total natural gas resource costs in the graph above include intracompany resource costs of ~~$6.0~~$6.5 million and ~~$6.1~~$8.8 million for the three months ended ~~March 31,~~June 30, 2021 and 2020, respectively.

Total natural gas resource costs increased ~~$1.5~~$3.8 million for the ~~first~~second quarter of 2021 as compared to the ~~first~~second quarter of 2020 primarily due to the following:



a $5.9 million increase in natural gas purchased due to an increase in the price of natural gas (increased costs $17.3 million), partially offset by a decrease in volumes (decreased costs $11.4 million).



a $2.2 million decrease from net amortizations and deferrals of natural gas costs.

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•

a $4.7 million increase in natural gas purchased due to an increase in the price of natural gas (increased costs $17.7 million), partially offset by a decrease in volumes (decreased costs $13.0 million).

•

~~a $3.2 million decrease from net amortizations and deferrals of natural gas costs.~~

Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 16 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the three months ended ~~March 31,~~June 30, 2021 and 2020 (dollars in thousands):


	Electric				Natural Gas				Intracompany						Total
	2021		2020		2021		2020		2021			2020			2021		2020
Operating revenues	$	228,019	$	213,785	$	80,070	$	74,555	$	(20,529	)	$	(20,000	)	$	287,560	$	268,340
Resource costs		71,289		52,092		38,755		34,977		(20,529	)		(20,000	)		89,515		67,069
Utility margin	$	156,730	$	161,693	$	41,315	$	39,578	$	—		$	—		$	198,045	$	201,271

Electric

Natural Gas

Intracompany

Total

2021

2020

2021

2020

2021

2020

2021

2020

Operating revenues

$
257,580

$
246,208

$
160,796

$
149,950

$
(18,516
)

$
(18,953
)

$
399,860

$
377,205

Resource costs

77,867

75,531

74,489

72,979

(18,516
)

(18,953
)

133,840

129,557

Utility margin

$
179,713

$
170,677

$
86,307

$
76,971

$
—

$
—

$
266,020

$
247,648

Electric utility margin ~~increased $9.0~~decreased $5.0 million and natural gas utility margin increased ~~$9.3~~$1.7 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~~second quarter of 2021, we had a ~~$4.3~~$7.6 million pre-tax ~~benefit~~expense under the ERM in Washington, compared to a ~~$5.2~~$0.4 million pre-tax benefit for the ~~first~~second quarter of 2020.

~~Table~~ The increase in net power supply costs was primarily due to higher customer loads, which required additional resources to serve those loads. We also had lower than normal hydroelectric generation due to hot and dry weather in the Pacific Northwest. Because of ~~Contents~~this, we had to rely on thermal generation and power market purchases to serve our additional load. In addition, hydroelectric generation was lower and electric loads were higher throughout the Pacific Northwest, so this increased market prices for purchased power, as well as natural gas prices for fuel. See "Heat Wave" in the Executive Level Summary above.

~~AVISTA CORPORATION~~

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.~~

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.

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Six months ended June 30, 2021 compared to the six months ended June 30, 2020

Utility Operating Revenues

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

(1)

This balance includes public street and highway lighting, which is considered part of retail electric revenues.

Total electric operating revenues in the graph above include intracompany sales of $12.5 million and $14.9 million for the six months ended June 30, 2021 and 2020, respectively.

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	Electric Decoupling Revenues
	2021			2020
Current year decoupling deferrals (a)	$	(439	)	$	10,973
Amortization of prior year decoupling deferrals (b)		(6,794	)		(8,266	)
Total electric decoupling revenue	$	(7,233	)	$	2,707

(a)

(b)

Total electric revenues increased $25.6 million for the first half of 2021 as compared to the first half of 2020. The primary fluctuations that occurred during the period were as follows:



a $23.4 million increase in retail electric revenue due to an increase in total MWhs sold (increased revenues $20.9 million) and an increase in revenue per MWh (increased revenues $2.5 million).

The increase in total retail MWhs sold was primarily the result of weather that was warmer than normal and the prior year in the second quarter, which increased cooling loads. Also, there was a lifting of COVID-19 restrictions during the second quarter of 2021, which contributed to the increased loads, and customer growth. In addition, during the first quarter of 2021, weather was colder than the prior year, which increased heating loads. Compared to the first half of 2020, residential electric use per customer increased 3 percent and commercial use per customer increased 5 percent. Cooling degree days in Spokane were significantly above normal and first half of 2020. Heating degree days in Spokane were 8 percent below normal, and 3 percent below the first half of 2020. See "Heat Wave" in the Executive Level Summary above.



a $8.4 million decrease in wholesale electric revenues due to a decrease in sales volumes (decreased revenues $6.3 million), and a decrease in sales prices (decreased revenues $2.1 million). The fluctuation in volumes was primarily the result of differences in the available opportunities for us to optimize our generation assets as compared to the prior year.



a $19.4 million increase in sales of fuel as part of thermal generation resource optimization activities.



a $9.9 million decrease in electric decoupling revenue. This was mainly because the first half of 2020 had surcharges to non-residential customers, which had lower usage due to COVID-19 restrictions.



a $1.2 million increase in other primarily because in the first half of 2020, we accrued $1.4 million for customer refunds related to our 2015 Washington general rate case.

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

(1)

This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues.

Total natural gas operating revenues in the graph above include intracompany sales of $26.6 million and $24.1 million for the six months ended June 30, 2021 and 2020, respectively.

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	Natural Gas Decoupling Revenues
	2021		2020
Current year decoupling deferrals (a)	$	2,890	$	(899	)
Amortization of prior year decoupling deferrals (b)		1,773		(1,859	)
Total natural gas decoupling revenue	$	4,663	$	(2,758	)

(a)

(b)

Total natural gas revenues increased $16.4 million for the first half of 2021 as compared to the first half of 2020. The primary fluctuations that occurred during the period were as follows:



a $4.3 million increase in natural gas retail revenues (including industrial, which is included in other) due to an increase in volumes (increased revenues $3.6 million), and an increase in retail rates (increased revenues $0.7 million).

Retail natural gas sales volumes increased in the first half of 2021 as compared to the first half of 2020 primarily due to higher usage and customer growth. The slightly higher residential usage was primarily due to weather that was colder than the prior year, which increased heating loads in the first quarter, mostly offset by lower usage in the second quarter due to weather that was warmer than normal. Compared to the first half of 2020, residential use per customer was flat and commercial use per customer increased 2 percent. Heating degree days in Spokane were 8 percent below normal, and 3 percent below the first half of 2020. Heating degree days in Medford were 6 percent below normal, and 7 percent below the first half of 2020.

Retail rates increased due to general rate increases in Oregon, effective January 16, 2021 and Washington, effective April 1, 2020.



a $0.2 million increase in wholesale natural gas revenues due to an increase in prices (increased revenues $23.1 million), mostly offset by a decrease in volumes of excess gas sold in the wholesale market (decreased revenues $22.9 million). Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.



a $7.5 million increase in natural gas decoupling revenue primarily because in 2020, we were amortizing decoupling surcharges, whereas in 2021, we are amortizing decoupling rebates. In addition, there were increases to decoupling revenue in the second quarter of 2021 due to weather that was warmer than normal.



a $4.6 million increase in other because in the first half of 2020, we accrued $3.6 million for customer refunds related to our 2015 Washington general rate case.

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


	Electric Customers				Natural Gas Customers
	2021		2020		2021		2020
Residential		354,997		349,420		330,959		326,315
Commercial		44,037		43,344		36,473		36,172
Interruptible		—		—		40		41
Industrial		1,210		1,296		191		241
Public street and highway lighting		657		643		—		—
Total retail customers		400,900		394,703		367,663		362,768

Utility Resource Costs

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

Total electric resource costs in the graph above include intracompany resource costs of $26.6 million and $24.1 million for the six months ended June 30, 2021 and 2020, respectively.

Total electric resource costs increased $21.5 million for the first half of 2021 as compared to the first half of 2020. The primary fluctuations that occurred during the period were as follows:



an $11.4 million increase in power purchased due to an increase in wholesale prices (increased costs $6.6 million) and an increase in the volume of power purchases (increased costs $4.8 million). The fluctuation in volumes was primarily the result of differences in the available opportunities for us to optimize our generation assets as compared to the prior year. Additionally, during the second quarter of 2021, we had increased customer loads and lower than normal hydroelectric generation as a result of the heat wave experienced in the Pacific Northwest, which contributed to our need to purchase power. See "Heat Wave" in the Executive Level Summary above.



an $8.3 million increase in fuel for generation primarily related to higher natural gas prices during the first quarter as a result of cold weather throughout the country in February and supply constraints during that same time period. In addition, there was lower hydroelectric generation and increased sales volumes during the second quarter, which required increased thermal generation.



a $15.6 million increase in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was more economical to sell the fuel as

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

part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.



a $13.7 million decrease in other electric resource costs, primarily related to increased amortizations associated with the Washington ERM. In addition, there was the deferral of increased power supply costs above authorized in our Idaho jurisdiction.

Total natural gas resource costs in the graph above include intracompany resource costs of $12.5 million and $14.9 million for the six months ended June 30, 2021 and 2020, respectively.

Total natural gas resource costs increased $5.3 million for the first half of 2021 as compared to the first half of 2020 primarily due to the following:



a $10.6 million increase in natural gas purchased due to an increase in the price of natural gas (increased costs $34.8 million), partially offset by a decrease in volumes (decreased costs $24.2 million).



a $5.4 million decrease from net amortizations and deferrals of natural gas costs.

Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 16 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the six months ended June 30, 2021 and 2020 (dollars in thousands):


	Electric				Natural Gas				Intracompany						Total
	2021		2020		2021		2020		2021			2020			2021		2020
Operating revenues	$	485,599	$	459,993	$	240,866	$	224,505	$	(39,045	)	$	(38,953	)	$	687,420	$	645,545
Resource costs		149,156		127,623		113,244		107,955		(39,045	)		(38,953	)		223,355		196,625
Utility margin	$	336,443	$	332,370	$	127,622	$	116,550	$	—		$	—		$	464,065	$	448,920

Electric utility margin increased $4.1 million and natural gas utility margin increased $11.1 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 half 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 heat wave experienced in the second quarter of 2021 (see "Heat Wave" in the Executive Level Summary above). For the first half of 2021, we

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had a $3.3 million pre-tax expense under the ERM in Washington, compared to a $5.6 million pre-tax benefit for the first half of 2020. Refer to the second quarter utility margin section for discussion of the increased net power supply costs.

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.

Results of Operations - Alaska Electric Light and Power Company

Three months ended ~~March 31,~~June 30, 2021 compared to the three months ended ~~March 31,~~June 30, 2020 and six months ended June 30, 2021 compared to the six months ended June 30, 2020

Net income for AEL&P was ~~$3.5~~$1.3 million for the three months ended ~~March 31,~~June 30, 2021 ~~compared to $3.4 million~~and for the three months ended ~~March 31,~~June 30, 2020. Net income was $4.8 million for the six months ended June 30, 2021 compared to $4.7 million for the six months ended June 30, 2020.

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


	Three months ended June 30,				Six months ended June 30,
	2021		2020		2021		2020
Operating revenues	$	10,547	$	9,997	$	23,368	$	22,199
Resource costs		1,163		896		1,902		887
Utility margin	$	9,384	$	9,101	$	21,466	$	21,312

2021

2020

Operating revenues

$
12,821

$
12,202

Resource costs (benefit)

739

(10
)
Utility margin

$
12,082

$
12,212

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

AEL&P had normal levels of hydroelectric generation during the first ~~quarters~~half 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.

Results of Operations - Other Businesses

Our other businesses had net income of ~~$0.5~~$5.1 million for the three months ended ~~March 31,~~June 30, 2021 compared to a net loss of ~~$1.0~~$1.5 million for the three months ended ~~March 31,~~June 30, 2020. Net income was $5.5 million for the six months ended June 30, 2021 compared to a net loss of $2.4 million for the six months ended June 30, 2020.

The increase in net income primarily relates to net investment gains during the first six months of 2021. This is compared to the second quarter of 2020 that resulted in net investment losses. In addition, 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~~half 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.~~

Critical Accounting Policies and Estimates

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.

4755

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Liquidity and Capital Resources

Overall Liquidity

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

In April 2021, we repaid our $100 million credit agreement.

As of ~~April~~June 30, 2021, we had ~~$182.4~~$79.9 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.

Review of Cash Flow Statement

Operating Activities

Net cash provided by operating activities was ~~$145.1~~$190.1 million for the ~~three~~six months ended ~~March 31,~~June 30, 2021, compared to ~~$135.3~~$199.9 million for the ~~three~~six months ended ~~March 31,~~June 30, 2020. The ~~increase~~decrease is primarily due to an increase in power and natural gas cost deferrals, which decreased cash flows by $21.8 million, as compared to an increase to operating cash flows of $1.8 million in 2020. Additionally, during the first half of 2021 we contributed $28.0 million to the pension plan, compared to $14.6 million in the first half of 2020.

The above decreases were partially offset by an increase in net ~~income. As~~income and as compared to 2020, certain net assets and liabilities increased cash provided by operating activities by ~~$14.9~~$10.8 million.

The above increases in net cash provided by operating activities was partially offset by power and natural gas deferrals which increased during 2021 due to higher natural gas prices during the year, which decreased cash flows by $7.8 million, as compared to an increase to operating cash flows of $6.4 million in 2020. Additionally, during the first quarter of 2021 we contributed $14.0 million to the pension plan, compared to $7.3 million in the first quarter of 2020.

Investing Activities

Net cash used in investing activities was ~~$96.5~~$210.8 million for the ~~three~~six months ended ~~March 31,~~June 30, 2021, compared to ~~$95.1~~$191.8 million for the ~~three~~six months ended ~~March 31,~~June 30, 2020. During the ~~three~~six months ended ~~March 31,~~June 30, 2021, we paid ~~$97.2~~$213.8 million for utility capital expenditures compared to ~~$95.5~~$189.5 million for the ~~three~~six months ended ~~March 31,~~June 30, 2020.

Financing Activities

Net cash ~~used~~provided by financing activities was ~~$41.2~~$45.6 million for the ~~three~~six months ended ~~March 31,~~June 30, 2021, compared to cash ~~used~~provided of ~~$31.1~~$98.4 million for the ~~three~~six months ended ~~March 31,~~June 30, 2020. In the first ~~quarter~~half of 2021, our cash provided by short-term borrowings decreased ~~$10.0~~$42.2 million compared to ~~a decrease of $0.8 million in~~ the first ~~quarter~~half of 2020.

Capital Resources

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


	June 30, 2021					December 31, 2020
	Amount		Percent of total			Amount		Percent of total
Current portion of long-term debt and leases	$	257,274		5.7	%	$	7,184		0.2	%
Short-term borrowings		296,000		6.5	%		203,000		4.6	%
Long-term debt to affiliated trusts		51,547		1.1	%		51,547		1.2	%
Long-term debt and leases		1,875,053		41.2	%		2,125,065		48.0	%
Total debt		2,479,874		54.5	%		2,386,796		54.0	%
Total Avista Corporation shareholders’ equity		2,069,966		45.5	%		2,029,726		46.0	%
Total	$	4,549,840		100.0	%	$	4,416,522		100.0	%

March 31, 2021

December 31, 2020

Amount

Percent
of total

Amount

Percent
of total

Current portion of long-term debt and leases

$
7,229

0.2
%

$
7,184

0.2
%
Short-term borrowings

193,000

4.3
%

203,000

4.6
%
Long-term debt to affiliated trusts

51,547

1.2
%

51,547

1.2
%
Long-term debt and leases

2,125,061

47.8
%

2,125,065

48.0
%
Total debt

2,376,837

53.5
%

2,386,796

54.0
%
Total Avista Corporation shareholders’ equity

2,068,590

46.5
%

2,029,726

46.0
%
Total

$
4,445,427

100.0
%

$
4,416,522

100.0
%

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~~AVISTA CORPORATION~~

Our shareholders’ equity increased ~~$38.9~~$40.2 million during the first ~~three~~six months of 2021 primarily due to net income and the issuance of common stock, which was partially offset by dividends.

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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.

Committed Lines of Credit

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,~~June 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,~~June 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,~~June 30, 2021, AEL&P was in compliance with this covenant with a ratio of ~~52.0~~51.5 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~~six months ended ~~March 31~~June 30 (dollars in thousands):


	2021			2020
Borrowings outstanding at end of period	$	296,000		$	221,000
Letters of credit outstanding at end of period	$	24,118		$	19,373
Maximum borrowings outstanding during the period	$	296,000		$	221,000
Average borrowings outstanding during the period	$	143,498		$	181,373
Average interest rate on borrowings during the period		1.18	%		1.77	%
Average interest rate on borrowings at end of period		1.08	%		1.22	%

2021

2020

Borrowings outstanding at end of period

$
93,000

$
185,000

Letters of credit outstanding at end of period

$
16,618

$
32,983

Maximum borrowings outstanding during the period

$
106,000

$
193,000

Average borrowings outstanding during the period

$
83,956

$
173,684

Average interest rate on borrowings during the period

1.19
%

2.33
%
Average interest rate on borrowings at end of period

1.17
%

1.66
%

As of ~~March 31,~~June 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.

Liquidity Expectations

During 2021, we expect to issue approximately ~~$120~~$140 million of long-term debt and ~~$75~~$90 million of ~~equity. We intend to use~~common stock (including $15.7 million of common stock issued during the ~~proceeds from our debt and equity issuances to refinance maturing~~six months ended June 30, 2021). The increase in long-term debt and common stock is to fund ~~planned~~increased 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.

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Capital Expenditures

We are making capital investments to enhance service and system reliability for our customers and replace aging infrastructure. ~~Our estimates~~We have revised our estimate for Avista Utilities capital expenditures to $450 million in 2021 ~~through~~from our original estimate of $415 million. The additional capital expenditures are related to increased customer growth and storms. In addition, we expect our capital

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expenditures to total about $445 million for 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.

Off-Balance Sheet Arrangements

As of ~~March 31,~~June 30, 2021, we had ~~$16.6~~$24.1 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.

Pension Plan

Avista Utilities

In the ~~three~~six months ended ~~March 31,~~June 30, 2021 we contributed ~~$14~~$28 million to the pension plan and we expect to contribute a total of $42 million in 2021. We expect to contribute a total of $150 million to the pension plan in the period 2021 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.

Contractual Obligations

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



In June 2021, we amended our committed line of credit agreement to extend the expiration date until June 2026.

•

~~In April 2021, we repaid the balance on our~~ ~~$100.0 million credit agreement.~~

See the 2020 Form 10-K for our contractual obligations.

Environmental Issues and Contingencies

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

Clean Energy Commitment

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.

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~~AVISTA CORPORATION~~

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.

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Climate Change

Federal Regulatory Actions

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.”

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

Other

TSA Security Directive

In July 2021, the Department of Homeland Security (DHS), 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

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).

Arbitration

As a result of the 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~~The Ownership and Operating Agreement contains an arbitration clause that dictates a dispute resolution process to address and resolve these disagreements, ~~the owners have commenced~~which calls for an arbitration proceeding ~~as provided for~~in Spokane, Washington, before a single arbitrator. At least one owner, Talen Montana, has challenged the validity of the arbitration clause contained in the Ownership and Operating ~~Agreement.~~Agreement on the basis that it is not consistent with recently-enacted amendments to Montana Code Section 27-5-323, which purport to invalidate such clauses, as they relate to electrical generation facilities such as Colstrip, if they do not expressly require arbitration in Montana before three arbitrators. Majority in interest of the owners of Colstrip, including us, have initiated legal proceedings in Washington to compel arbitration in accordance with the Ownership and Operating Agreement, as well as legal proceedings in Montana to challenge the constitutionality of such amendments to Montana Code. See “Note 15 of the Notes to Condensed Consolidated Financial Statements” for further discussion surrounding the arbitration proceeding.

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Montana Legislation Relating to Colstrip

In addition to amending Montana Code Section 27-5-323, during the course of the 2021 legislative session the Montana legislature passed Senate Bill 266, which amended Montana’s Consumer Protection Act (MC 30-14-103 et seq.) to make (i) the failure or refusal of an owner of Colstrip to fund its share of operating costs, or (ii) conduct by one or more of the owners of Colstrip to bring about permanent closure of a generating unit of Colstrip without seeking and obtaining the unanimous consent of the owners, an unfair or deceptive act or practice in the conduct of trade or commerce under the Montana Consumer Protection Act. Majority in interest of the owners of Colstrip, including us, have initiated legal proceedings to challenge the constitutionality of Senate Bill 266. See “Note 15 of the Notes to Condensed Consolidated Financial Statements” for further discussion surrounding Montana legislation.

WUTC Investigation Request

In response 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~~On June 8, 2021, the WUTC ~~deny the request~~issued an Order declining to initiate such a proceeding. ~~At this time, we cannot predict whether the WUTC will initiate an investigation.~~

~~Montana Legislation Relating to Colstrip~~

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.

See the 2020 Form 10-K for further discussion of Colstrip.

Enterprise Risk Management

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~~six months ended ~~March 31,~~June 30, 2021. See the 2020 Form 10-K.

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Financial Risk

Our financial risks have not materially changed during the ~~three~~six months ended ~~March 31, 2021, other than the changes noted due to COVID-19.~~June 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.

Interest Rate Risk

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,~~June 30, 2021 and December 31, 2020 and the amount of additional collateral we would have to post in certain circumstances.

Credit Risk

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,~~June 30, 2021, we had interest rate swap derivatives outstanding with a notional amount totaling $185.0 million and we had cash deposited as collateral in the amount of ~~$3.9~~$5.9 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,~~June 30, 2021, we would potentially be required to post the following additional collateral (in thousands):


	March 31, 2021		June 30, 2021
Additional collateral taking into account contractual thresholds	$	5,380	$	12,920
Additional collateral without contractual thresholds		11,046		29,001

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Energy Commodity Risk

Our energy commodity risks have not materially changed during the ~~three~~six months ended ~~March 31,~~June 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,~~June 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.


	Purchases									Sales
	Electric Derivatives					Gas Derivatives				Electric Derivatives						Gas Derivatives
Year	Physical (1)			Financial (1)		Physical (1)		Financial (1)		Physical (1)			Financial (1)			Physical (1)			Financial (1)
Remainder 2021	$	(79	)	$	3,664	$	2,538	$	19,161	$	(970	)	$	(17,522	)	$	(677	)	$	(14,671	)
2022		—			—		646		9,855		—			(1,071	)		(1,472	)		(3,940	)
2023		—			—		—		1,375		—			—			(1,290	)		(49	)
2024		—			—		—		49		—			—			(1,501	)		—
2025		—			—		—		—		—			—			(1,107	)		—

Purchases

Sales

Electric Derivatives

Gas Derivatives

Electric Derivatives

Gas Derivatives

Year

Physical (1)

Financial (1)

Physical (1)

Financial (1)

Physical (1)

Financial (1)

Physical (1)

Financial (1)

Remainder 2021

$
(1
)

$
1,366

$
337

$
10,926

$
(1
)

$
(5,924
)

$
(680
)

$
(9,975
)
2022

—

—

320

4,127

—

—

(1,314
)

(2,140
)
2023

—

—

—

429

—

—

(1,461
)

(133
)
2024

—

—

—

—

—

—

(1,548
)

—

2025

—

—

—

—

—

—

(1,203
)

—

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~~AVISTA CORPORATION~~

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.


	Purchases											Sales
	Electric Derivatives					Gas Derivatives						Electric Derivatives					Gas Derivatives
Year	Physical (1)		Financial (1)			Physical (1)			Financial (1)			Physical (1)			Financial (1)		Physical (1)			Financial (1)
2021	$	2	$	(414	)	$	(87	)	$	10,549		$	(15	)	$	716	$	(2,152	)	$	(10,672	)
2022		—		—			247			1,920			—			—		(1,697	)		(1,536	)
2023		—		—			—			(122	)		—			—		(1,599	)		(42	)
2024		—		—			—			—			—			—		(1,673	)		—
2025		—		—			—			—			—			—		(1,219	)		—

Purchases

Sales

Electric Derivatives

Gas Derivatives

Electric Derivatives

Gas Derivatives

Year

Physical (1)

Financial (1)

Physical (1)

Financial (1)

Physical (1)

Financial (1)

Physical (1)

Financial (1)

2021

$
2

$
(414
)

$
(87
)

$
10,549

$
(15
)

$
716

$
(2,152
)

$
(10,672
)
2022

—

—

247

1,920

—

—

(1,697
)

(1,536
)
2023

—

—

—

(122
)

—

—

(1,599
)

(42
)
2024

—

—

—

—

—

—

(1,673
)

—

2025

—

—

—

—

—

—

(1,219
)

—

(1)

Physical transactions represent commodity transactions in which we 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)~~

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.

Future Resource Needs

2021 Electric Integrated Resource Plan

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:

•

We have adequate resources between owned and contractually controlled generation, when combined with conservation and market purchases, to meet customer demand through 2025. Our first long-term capacity deficit, net of energy efficiency, is in 2026 and is 12 MW. The deficit increases to 301 MW in 2027.



We have adequate resources between owned and contractually controlled generation, when combined with conservation and market purchases, to meet customer demand through October 2026. Our first long-term capacity deficit, net of energy efficiency, begins in October 2026 and is 247 MW by January 2027.

•

~~New renewable energy, energy storage, demand response, energy efficiency, and upgrades to existing hydropower and biomass plants are integral to our plan.~~



New renewable energy, energy storage, demand response, energy efficiency, and upgrades to existing hydropower and biomass plants are integral to our plan.

•



Retail sales and residential use per customer forecasts are slightly higher as compared to ~~the 2020 IRP projections. We anticipate customer load growth of 0.3 percent per year.~~

•

~~Assumes Colstrip no longer included in the portfolio in 2025, consistent with our 2020 IRP.~~

•

~~New natural gas-fired peakers required for the 2026 capacity need because long-term energy storage is not yet available or as cost effective as initially estimated in the 2020 IRP.~~

•

~~Demand response programs begin in 2024 and grow to 71 MW by 2045.~~

•

Notwithstanding the 2020 Renewable Request for Proposal process, the first new renewable resource identified in the IRP is in 2023 as a wind project located in Montana. Additional Montana wind is identified in 2024 and 2028.

•

~~The resource strategy moves us closer to achieving our corporate clean electricity goal to provide customers with 100 percent net clean electricity by 2027. Net clean energy is defined as either~~ ~~100 percent non-carbon emitting resources or investing in or acquiring carbon offsets to net-out emissions created from carbon emitting resources.~~

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

IRP projections. We anticipate customer load growth of 0.3 percent per year.

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

Assumes Colstrip will exit the portfolio as determined by an economic analysis of the plant compared to alternative resources and the Washington CETA requirement to exit the plant by 2025; although an exit strategy for the plant has not been developed at this time.



New natural gas-fired peakers are most economic to meet the capacity shortfall in 2027 as long-term energy storage is not yet available or as cost effective as initially estimated in the 2020 IRP.



Demand response programs begin in 2025 and grow to 72 MW by 2045.



Our first new renewable resource identified in the IRP is in 2025, as a wind project located in Montana. Actual resource selection will be determined by a future RFP.



The resource strategy moves us closer to achieving our corporate clean electricity goal to provide customers with 100 percent net clean electricity by 2027. Net clean energy is defined as either 100 percent non-carbon emitting resources or investing in or acquiring carbon offsets to net-out emissions created from carbon emitting resources.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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.

Item 4. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) (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,~~June 30, 2021.

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

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PART II. Other Information

Item 1. Legal Proceedings

See “Note 15 of Notes to Condensed Consolidated Financial Statements” in “Part I. Financial Information Item 1. Condensed Consolidated Financial Statements.”

Item 1A. Risk Factors

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:~~10-K.

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.

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Item 6. Exhibits


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.

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SIGNATURE

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


		AVISTA CORPORATION
		(Registrant)




Date:	~~May 4,~~August 3, 2021	/s/ Mark T. Thies
		Mark T. Thies
		Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)

5665


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 Six Months Ended ~~March 31,~~June 30, 2021 and 2020	5
	Condensed Consolidated Statements of Comprehensive Income - Three and Six Months Ended ~~March 31,~~June 30, 2021 and 2020	6
	Condensed Consolidated Balance Sheets - ~~March 31,~~June 30, 2021 and December 31, 2020	7
	Condensed Consolidated Statements of Cash Flows - ~~Three~~Six Months Ended ~~March 31,~~June 30, 2021 and 2020	8
	Condensed Consolidated Statements of Equity - Three and Six Months Ended ~~March 31,~~June 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	23
	Note 8. Committed Lines of Credit	23
	Note 9. Credit Agreement	24
	Note 10. Long-Term Debt to Affiliated Trusts	24
	Note 11. Fair Value	24
	Note 12. Common Stock	28
	Note 13. Accumulated Other Comprehensive Loss	28
	Note 14. Earnings per Common Share	29
	Note 15. Commitments and Contingencies	29
	Note 16. 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 - Avista Utilities	4042


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	-	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


	2021			2020			2021			2020
Operating Activities:
Net income	$	68,017		$	48,424		$	82,091		$	65,877
Non-cash items included in net income:
Depreciation and amortization		55,348			51,421			111,487			115,752
Deferred income tax provision and investment tax credits		5,966			(6,765	)		11,085			(8,400	)
Power and natural gas cost amortizations (deferrals), net		(7,811	)		6,380			(21,826	)		1,815
Amortization of debt expense		823			653			1,571			1,365
Stock-based compensation expense		626			872			2,280			2,826
Equity-related AFUDC		(1,754	)		(1,599	)		(3,346	)		(3,271	)
Pension and other postretirement benefit expense		7,556			7,952			14,793			16,481
Other regulatory assets and liabilities and deferred debits and credits		1,762			11,902			4,008			4,391
Change in decoupling regulatory deferral		(682	)		4,155			2,203			(454	)
Gain on sale of investments		(155	)		(3,242	)		(1,764	)		(3,231	)
Other		(2,828	)		5,112			(7,653	)		9,043
Contributions to defined benefit pension plan		(14,000	)		(7,300	)		(28,000	)		(14,600	)
Changes in certain current assets and liabilities:
Accounts and notes receivable		6,728			6,078			26,284			43,701
Materials and supplies, fuel stock and stored natural gas		4,291			9,901			(15,328	)		(751	)
Collateral posted for derivative instruments		1,497			(14,283	)		(24,102	)		(7,209	)
Income taxes receivable		5,442			10,500			23,869			9,106
Income taxes payable		557			4,901
Other current assets		(260	)		(2,166	)		2,505			(5,704	)
Accounts payable		(2,590	)		(19,527	)		8,111			(29,860	)
Other current liabilities		16,557			21,905			1,795			3,011
Net cash provided by operating activities		145,090			135,274			190,063			199,888

Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(97,203	)		(95,525	)		(213,827	)		(189,480	)
Issuance of notes receivable		(75	)		(2,779	)		(75	)		(4,343	)
Equity and property investments		(2,340	)		(1,313	)		(5,650	)		(2,097	)
Proceeds from sale of investments		801			5,148			6,806			5,144
Other		2,356			(662	)		1,907			(988	)
Net cash used in investing activities		(96,461	)		(95,131	)		(210,839	)		(191,764	)


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

	FOR THE QUARTERLY PERIOD ENDED ~~March 31,~~ June 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	☐

	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	)