•

the ability to comply with the terms of the licenses and permits for our hydroelectric or thermal generating facilities at cost-effective ~~levels;~~

2levels.

~~AVISTA CORPORATION~~

~~Technology Risk~~

cyber attacks on us or our vendors or other potential lapses that result in unauthorized disclosure of private information, which could result in liabilities against us, costs to investigate, remediate and defend, and damage to our reputation;

~~disruption to or breakdowns of information systems, automated controls and other technologies that we rely on for our operations, communications and customer service;~~

~~changes in costs that impede our ability to effectively implement new information technology systems or to operate and maintain current production technology;~~

~~changes in technologies, possibly making some of the current technology we utilize obsolete or the introduction of new technology that may create new cyber security risk;~~

~~insufficient technology skills, which could lead to the inability to develop, modify or maintain our information systems;~~

~~Strategic Risk~~

growth or decline of our customer base and the extent to which new uses for our services may materialize or existing uses may decline, including, but not limited to, the effect of the trend toward distributed generation at customer sites;

~~the potential effects of negative publicity regarding business practices, whether true or not, which could result in litigation or a decline in our common stock price;~~

changes in our strategic business plans, which may be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses and the extent of our business development efforts where potential future business is uncertain;

~~non-regulated activities may increase earnings volatility;~~

failure to complete the proposed acquisition could negatively impact the market price of Avista Corp.'s common stock or result in termination fees that could have a material adverse effect on our results of operations, financial condition, and cash flows;

the proposed acquisition of the Company by Hydro One has resulted in multiple shareholder class action lawsuits against the Company and its board of directors that could have a material adverse effect on our results of operations, financial condition, and cash flows and could delay or preclude consummation of the transaction;

~~External Mandates Risk~~

~~changes in environmental laws, regulations, decisions and policies, including present and potential environmental remediation costs and our compliance with these matters;~~

the potential effects of initiatives, legislation or administrative rulemaking at the federal, state or local levels, including possible effects on our generating resources of restrictions on greenhouse gas emissions to mitigate concerns over global climate changes;

political pressures or regulatory practices that could constrain or place additional cost burdens on our distribution systems through accelerated adoption of distributed generation or electric-powered transportation or on our energy supply sources, such as campaigns to halt coal-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities;

wholesale and retail competition including alternative energy sources, growth in customer-owned power resource technologies that displace utility-supplied energy or that may be sold back to the utility, and alternative energy suppliers and delivery arrangements;

~~failure to identify changes in legislation, taxation and regulatory issues which are detrimental or beneficial to our overall business;~~

policy and/or legislative changes resulting from the new presidential administration in various regulated areas, including, but not limited to, potential tax reform, environmental regulation and healthcare regulations; and

~~the risk of municipalization in any of our service territories.~~

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

~~Table of Contents~~

~~AVISTA CORPORATION~~

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.

Available Information

~~Our~~

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

Table of Contents

PART I. Financial Information

Item 1. Condensed Consolidated Financial Statements

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

~~Avista Corporation~~

Avista Corporation

For the Three and Six Months Ended June 30

Dollars in thousands, except per share amounts

(Unaudited)

Three months ended September 30, Nine months ended September 30,
2017 2016 2017 2016
Operating Revenues:
Utility revenues $ 291,640
$ 296,989
$ 1,030,906
$ 1,022,670
Non-utility revenues 5,456
6,360
17,161
17,690
Total operating revenues 297,096
303,349
1,048,067
1,040,360
Operating Expenses:
Utility operating expenses:
Resource costs 108,568
118,737
376,905
390,271
Other operating expenses 77,784
75,160
232,959
229,605
Acquisition costs 6,730
—
8,004
—
Depreciation and amortization 42,968
40,240
127,596
119,110
Taxes other than income taxes 23,269
22,669
79,733
74,669
Non-utility operating expenses:
Other operating expenses 6,598
6,756
19,863
18,862
Depreciation and amortization 137
193
482
573
Total operating expenses 266,054
263,755
845,542
833,090
Income from operations 31,042
39,594
202,525
207,270
Interest expense 23,955
21,632
71,170
64,223
Interest expense to affiliated trusts 216
164
601
456
Capitalized interest (899 ) (507 ) (2,513 ) (2,258 )
Other income-net (1,841 ) (1,562 ) (6,598 ) (7,025 )
Income before income taxes 9,611
19,867
139,865
151,874
Income tax expense 5,153
7,606
51,548
54,661
Net income 4,458
12,261
88,317
97,213
Net loss (income) attributable to noncontrolling interests (7 ) (27 ) 21
(76 )
Net income attributable to Avista Corp. shareholders $ 4,451
$ 12,234
$ 88,338
$ 97,137
Weighted-average common shares outstanding (thousands), basic 64,412
63,857
64,392
63,282
Weighted-average common shares outstanding (thousands), diluted 64,892
64,325
64,638
63,687

Earnings per common share attributable to Avista Corp. shareholders:
Basic $ 0.07
$ 0.19
$ 1.37
$ 1.53
Diluted $ 0.07
$ 0.19
$ 1.37
$ 1.53
Dividends declared per common share $ 0.3575
$ 0.3425
$ 1.0725
$ 1.0275


	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
Operating Revenues:
Utility revenues:
Utility revenues, exclusive of alternative revenue programs	$	374,285		$	384,214		$	867,828		$	862,917
Alternative revenue programs		5,513			(5,793	)		(13,525	)		(22,570	)
Total utility revenues		379,798			378,421			854,303			840,347
Non-utility revenues		139			145			265			265
Total operating revenues		379,937			378,566			854,568			840,612
Operating Expenses:
Utility operating expenses:
Resource costs		141,244			157,397			334,172			344,265
Other operating expenses		103,071			104,482			208,049			199,009
Depreciation and amortization		66,148			62,806			131,336			125,383
Taxes other than income taxes		24,917			26,658			58,811			60,775
Non-utility operating expenses		749			2,940			1,791			3,928
Total operating expenses		336,129			354,283			734,159			733,360
Income from operations		43,808			24,283			120,409			107,252
Interest expense		35,018			28,518			70,102			56,585
Interest expense to affiliated trusts		608			177			1,179			294
Capitalized interest		(866	)		(932	)		(1,708	)		(2,025	)
Other income-net		(2,626	)		(13,934	)		(9,055	)		(18,785	)
Income before income taxes		11,674			10,454			59,891			71,183
Income tax benefit		(5,810	)		(999	)		(12,438	)		(11,835	)
Net income	$	17,484		$	11,453		$	72,329		$	83,018
Weighted-average common shares outstanding (thousands), basic		75,983			72,624			75,576			72,205
Weighted-average common shares outstanding (thousands), diluted		76,131			72,658			75,703			72,294

Earnings per common share:
Basic	$	0.23		$	0.16		$	0.96		$	1.15
Diluted	$	0.23		$	0.16		$	0.96		$	1.15

The Accompanying Notes are an Integral Part of These Statements.

Table of Contents

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

~~Avista Corporation~~

Avista Corporation

For the Three and Six Months Ended June 30

Dollars in thousands

(Unaudited)

Three months ended September 30, Nine months ended September 30,
2017 2016 2017 2016
Net income $ 4,458
$ 12,261
$ 88,317
$ 97,213
Other Comprehensive Income (Loss):
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $98, $75, $295 and $(512) respectively 182
140
548
(949 )
Total other comprehensive income (loss) 182
140
548
(949 )
Comprehensive income 4,640
12,401
88,865
96,264
Comprehensive loss (income) attributable to noncontrolling interests (7 ) (27 ) 21
(76 )
Comprehensive income attributable to Avista Corporation shareholders $ 4,633
$ 12,374
$ 88,886
$ 96,188


	Three months ended June 30,					Six Months Ended June 30,
	2023			2022		2023			2022
Net income	$	17,484		$	11,453	$	72,329		$	83,018
Other Comprehensive Income (Loss):
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of ($5), $73, ($10) and $146, respectively		(19	)		273		(37	)		549
Total other comprehensive income (loss)		(19	)		273		(37	)		549
Comprehensive income	$	17,465		$	11,726	$	72,292		$	83,567

The Accompanying Notes are an Integral Part of These Statements.

Table of Contents

CONDENSED CONSOLIDATED BALANCE SHEETS

~~Avista Corporation~~

Avista Corporation

Dollars in thousands

(Unaudited)

September 30, December 31,
2017 2016
Assets:
Current Assets:
Cash and cash equivalents $ 14,716
$ 8,507
Accounts and notes receivable-less allowances of $4,838 and $5,026, respectively 125,595
180,265
Regulatory asset for energy commodity derivatives 22,005
11,365
Materials and supplies, fuel stock and stored natural gas 65,961
53,314
Income taxes receivable 42,111
48,265
Other current assets 46,246
49,625
Total current assets 316,634
351,341
Net Utility Property:
Utility plant in service 5,686,633
5,506,499
Construction work in progress 194,679
150,474
Total 5,881,312
5,656,973
Less: Accumulated depreciation and amortization 1,578,148
1,509,473
Total net utility property 4,303,164
4,147,500
Other Non-current Assets:
Investment in affiliated trusts 11,547
11,547
Goodwill 57,672
57,672
Other property and investments-net and other non-current assets 80,022
72,224
Total other non-current assets 149,241
141,443
Deferred Charges:
Regulatory assets for deferred income tax 123,449
109,853
Regulatory assets for pensions and other postretirement benefits 230,988
240,114
Other regulatory assets 129,112
135,751
Regulatory asset for interest rate swaps 170,079
161,508
Non-current regulatory asset for energy commodity derivatives 16,371
16,919
Other deferred charges 13,194
5,326
Total deferred charges 683,193
669,471
Total assets $ 5,452,232
$ 5,309,755


	June 30,			December 31,
	2023			2022
Assets:
Current Assets:
Cash and cash equivalents	$	15,704		$	13,428
Accounts and notes receivable-less allowances of $4,871 and $6,473, respectively		141,643			255,746
Inventory		115,805			107,674
Regulatory assets		163,906			193,787
Other current assets		89,881			151,167
Total current assets		526,939			721,802
Net utility property		5,548,651			5,444,709
Goodwill		52,426			52,426
Non-current regulatory assets		861,491			833,328
Other property and investments-net and other non-current assets		381,808			365,085
Total assets	$	7,371,315		$	7,417,350
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	103,587		$	202,954
Current portion of long-term debt		7,000			13,500
Short-term borrowings		203,000			463,000
Regulatory liabilities		79,093			95,665
Other current liabilities		148,483			189,415
Total current liabilities		541,163			964,534
Long-term debt		2,530,001			2,281,013
Long-term debt to affiliated trusts		51,547			51,547
Pensions and other postretirement benefits		92,741			93,901
Deferred income taxes		703,683			674,995
Non-current regulatory liabilities		845,022			840,837
Other non-current liabilities and deferred credits		206,737			175,855
Total liabilities		4,970,894			5,082,682
Commitments and Contingencies (See Notes to Condensed Consolidated Financial Statements)
Equity:
Shareholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 76,524,184 and 74,945,948 shares issued and outstanding, respectively		1,588,503			1,525,185
Accumulated other comprehensive loss		(2,095	)		(2,058	)
Retained earnings		814,013			811,541
Total shareholders’ equity		2,400,421			2,334,668
Total liabilities and equity	$	7,371,315		$	7,417,350

The Accompanying Notes are an Integral Part of These Statements.

Table of Contents

CONDENSED CONSOLIDATED ~~BALANCE SHEETS (continued)~~

~~Avista Corporation~~

STATEMENTS OF CASH FLOWS

Avista Corporation

For the Six Months Ended June 30

Dollars in thousands

(Unaudited)

September 30, December 31,
2017 2016
Liabilities and Equity:
Current Liabilities:
Accounts payable $ 72,777
$ 115,545
Current portion of long-term debt and capital leases 277,626
3,287
Short-term borrowings 106,298
120,000
Energy commodity derivative liabilities 11,054
7,035
Accrued interest 29,077
15,869
Accrued taxes other than income taxes 34,520
33,374
Deferred natural gas costs 34,399
30,820
Current portion of pensions and other postretirement benefits 11,544
10,994
Current interest rate swap derivative liabilities 34,520
6,025
Other current liabilities 61,436
64,579
Total current liabilities 673,251
407,528
Long-term debt and capital leases 1,491,789
1,678,717
Long-term debt to affiliated trusts 51,547
51,547
Regulatory liability for utility plant retirement costs 284,263
273,983
Pensions and other postretirement benefits 216,464
226,552
Deferred income taxes 903,943
840,928
Non-current interest rate swap derivative liabilities 1,330
28,705
Other non-current liabilities, regulatory liabilities and deferred credits 158,699
153,319
Total liabilities 3,781,286
3,661,279
Commitments and Contingencies (See Notes to Condensed Consolidated Financial Statements)

Equity:
Avista Corporation Shareholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 64,414,572 and 64,187,934 shares issued and outstanding as of September 30, 2017 and December 31, 2016, respectively 1,077,215
1,075,281
Accumulated other comprehensive loss (7,020 ) (7,568 )
Retained earnings 600,132
581,014
Total Avista Corporation shareholders’ equity 1,670,327
1,648,727
Noncontrolling Interests 619
(251 )
Total equity 1,670,946
1,648,476
Total liabilities and equity $ 5,452,232
$ 5,309,755


	2023			2022
Operating Activities:
Net income	$	72,329		$	83,018
Non-cash items included in net income:
Depreciation and amortization		131,367			125,445
Deferred income tax provision and investment tax credits		(20,565	)		(12,930	)
Power and natural gas cost deferrals, net		(31,559	)		(19,326	)
Amortization of debt expense		1,980			1,042
Stock-based compensation expense		5,460			3,646
Equity-related AFUDC		(3,172	)		(3,614	)
Pension and other postretirement benefit expense		6,693			10,557
Other regulatory assets and liabilities		(31,997	)		9,291
Other deferred debits and credits		32,351			(3,732	)
Change in decoupling regulatory deferral		14,383			22,550
Realized and unrealized loss (gain) on assets and investments		2,752			(13,144	)
Other		(2,436	)		4,749
Contributions to defined benefit pension plan		(6,666	)		(28,000	)
Cash paid for settlement of interest rate swap agreements		(409	)		(17,035	)
Cash received for settlement of interest rate swap agreements		7,869			—
Changes in certain current assets and liabilities:
Accounts and notes receivable		111,428			33,206
Inventory		(8,131	)		(21,058	)
Collateral posted for derivative instruments		116,602			18,131
Income taxes receivable		7,476			(168	)
Other current assets		(20,228	)		(1,294	)
Accounts payable		(96,080	)		(13,530	)
Other current liabilities		(19,886	)		28,137
Net cash provided by operating activities		269,561			205,941

Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(226,746	)		(210,646	)
Issuance of notes receivable		(1,500	)		(1,772	)
Equity and property investments		(6,481	)		(7,765	)
Other		652			764
Net cash used in investing activities		(234,075	)		(219,419	)

The Accompanying Notes are an Integral Part of These Statements.

Table of Contents

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

~~Avista Corporation~~

(continued)

Avista Corporation

For the ~~Nine~~Six Months Ended ~~September~~June 30

Dollars in thousands

(Unaudited)

2017 2016
Operating Activities:
Net income $ 88,317
$ 97,213
Non-cash items included in net income:
Depreciation and amortization 130,803
122,414
Deferred income tax provision and investment tax credits 58,242
87,246
Power and natural gas cost amortizations, net 8,416
11,422
Amortization of debt expense 2,440
2,595
Amortization of investment in exchange power 1,838
1,838
Stock-based compensation expense 5,809
6,261
Equity-related Allowance for Funds Used During Construction (AFUDC) (5,012 ) (6,306 )
Pension and other postretirement benefit expense 27,816
29,076
Amortization of Spokane Energy contract —
10,904
Other regulatory assets and liabilities and deferred debits and credits (12,683 ) (20,215 )
Change in decoupling regulatory deferral 20,193
(24,693 )
Other (190 ) 5,052
Contributions to defined benefit pension plan (22,000 ) (12,000 )
Cash paid for settlement of interest rate swap agreements (11,302 ) (53,966 )
Cash received for settlement of interest rate swap agreements 2,479
—
Changes in certain current assets and liabilities:
Accounts and notes receivable 52,534
53,726
Materials and supplies, fuel stock and stored natural gas (12,653 ) (3,932 )
Collateral posted for derivative instruments (1,896 ) (19,754 )
Income taxes receivable (4,254 ) (25,222 )
Other current assets (16 ) (8,486 )
Accounts payable (29,992 ) (17,206 )
Other current liabilities 8,624
18,151
Net cash provided by operating activities 307,513
254,118

Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC) (287,853 ) (288,072 )
Issuance of notes receivable at subsidiaries (2,800 ) (9,718 )
Equity and property investments made by subsidiaries (10,899 ) (8,741 )
Distributions received from investments 1,915
—
Other (2,714 ) (8,422 )
Net cash used in investing activities (302,351 ) (314,953 )


	2023			2022
Financing Activities:
Net decrease in short-term borrowings	$	(260,000	)	$	(126,000	)
Proceeds from issuance of long-term debt		250,000			399,856
Maturity of long-term debt and finance leases		(8,118	)		(251,543	)
Issuance of common stock, net of issuance costs		59,525			60,765
Cash dividends paid		(69,942	)		(64,077	)
Other		(4,675	)		(6,072	)
Net cash provided by (used in) financing activities		(33,210	)		12,929

Net increase (decrease) in cash and cash equivalents		2,276			(549	)

Cash and cash equivalents at beginning of period		13,428			22,168

Cash and cash equivalents at end of period	$	15,704		$	21,619

The Accompanying Notes are an Integral Part of These Statements.

Table of Contents

CONDENSED CONSOLIDATED STATEMENTS OF ~~CASH FLOWS (continued)~~

~~Avista Corporation~~

EQUITY

Avista Corporation

For the ~~Nine~~Three and Six Months Ended ~~September~~June 30

Dollars in thousands

(Unaudited)

2017 2016
Financing Activities:
Net increase in short-term borrowings $ 75,000
$ 82,000
Proceeds from issuance of long-term debt —
70,000
Maturity of long-term debt and capital leases (2,465 ) (92,375 )
Issuance of common stock, net of issuance costs 1,490
66,756
Cash dividends paid (69,220 ) (65,172 )
Other (3,758 ) (3,774 )
Net cash provided by financing activities 1,047
57,435

Net increase (decrease) in cash and cash equivalents 6,209
(3,400 )

Cash and cash equivalents at beginning of period 8,507
10,484

Cash and cash equivalents at end of period $ 14,716
$ 7,084


	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
Common Stock, Shares:
Shares outstanding at beginning of period		75,762,598			72,438,447			74,945,948			71,497,523
Shares issued		761,586			537,635			1,578,236			1,478,559
Shares outstanding at end of period		76,524,184			72,976,082			76,524,184			72,976,082
Common Stock, Amount:
Balance at beginning of period	$	1,555,651		$	1,418,421		$	1,525,185		$	1,380,152
Equity compensation expense		3,239			1,802			5,460			3,647
Issuance of common stock, net of issuance costs		29,613			22,879			59,525			60,765
Payment of minimum tax withholdings for share-based payment awards		—			—			(1,667	)		(1,462	)
Balance at end of period		1,588,503			1,443,102			1,588,503			1,443,102
Accumulated Other Comprehensive Loss:
Balance at beginning of period		(2,076	)		(10,763	)		(2,058	)		(11,039	)
Other comprehensive income (loss)		(19	)		273			(37	)		549
Balance at end of period		(2,095	)		(10,490	)		(2,095	)		(10,490	)
Retained Earnings:
Balance at beginning of period		831,736			825,642			811,541			785,631
Net income		17,484			11,453			72,329			83,018
Dividends on common stock		(35,207	)		(32,213	)		(69,857	)		(63,767	)
Balance at end of period		814,013			804,882			814,013			804,882
Total equity	$	2,400,421		$	2,237,494		$	2,400,421		$	2,237,494
Dividends declared per common share	$	0.46		$	0.44		$	0.92		$	0.88

The Accompanying Notes are an Integral Part of These Statements.

Table of Contents

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~OF EQUITY~~

~~Avista Corporation~~

~~For the~~ ~~Nine Months Ended September 30~~

~~Dollars in thousands~~

(Unaudited)

2017 2016
Common Stock, Shares:
Shares outstanding at beginning of period 64,187,934
62,312,651
Shares issued 226,638
1,869,836
Shares outstanding at end of period 64,414,572
64,182,487
Common Stock, Amount:
Balance at beginning of period $ 1,075,281
$ 1,004,336
Equity compensation expense 5,055
5,462
Issuance of common stock, net of issuance costs 1,490
66,756
Payment of minimum tax withholdings for share-based payment awards (3,420 ) (3,073 )
Purchase of subsidiary noncontrolling interests (1,191 ) —
Balance at end of period 1,077,215
1,073,481
Accumulated Other Comprehensive Loss:
Balance at beginning of period (7,568 ) (6,650 )
Other comprehensive income (loss) 548
(949 )
Balance at end of period (7,020 ) (7,599 )
Retained Earnings:
Balance at beginning of period 581,014
530,940
Net income attributable to Avista Corporation shareholders 88,338
97,137
Cash dividends paid on common stock (69,220 ) (65,172 )
Balance at end of period 600,132
562,905
Total Avista Corporation shareholders’ equity 1,670,327
1,628,787
Noncontrolling Interests:
Balance at beginning of period (251 ) (339 )
Net income (loss) attributable to noncontrolling interests (21 ) 76
Purchase of subsidiary noncontrolling interests 891
—
Balance at end of period 619
(263 )
Total equity $ 1,670,946
$ 1,628,524

~~The Accompanying Notes are an Integral Part of These Statements.~~

~~Table of Contents~~

~~AVISTA CORPORATION~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)~~

The accompanying condensed consolidated financial statements of Avista ~~Corporation (Avista~~ Corp. ~~or the Company)~~ as of and for the interim periods ended ~~September~~June 30, ~~2017~~2023 and ~~September~~June 30, ~~2016~~2022 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 ~~accounting principles generally accepted in the United States of America (GAAP)~~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, ~~2016~~ (~~2016~~2022 (2022 Form 10-K). ~~Please refer to the section “Acronyms and Terms” in the~~ ~~2016~~ ~~Form 10-K for definitions of certain terms not defined herein. The acronyms and terms are an integral part of these condensed consolidated financial statements.~~

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 ~~the~~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 Avista Utilities' Noxon Rapids generating facility.~~

~~Alaska Energy and Resources Company (AERC)~~Montana.

AERC is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is ~~Alaska Electric Light and Power Company (AEL&P),~~AEL&P, which comprises Avista Corp.'s regulated utility operations in Alaska.

Avista Capital, ~~Inc. (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.

On July 19, 2017, Avista Corp. entered into an Agreement and Plan of Merger (Merger Agreement) to become a wholly-owned subsidiary of Hydro One Limited (Hydro One). Consummation of the pending acquisition is subject to a number of approvals and the satisfaction or waiver of other specified conditions. The transaction is expected to close in the second half of 2018. See Note 1317 for ~~additional~~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.

~~Taxes Other Than Income Taxes~~

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.

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

Three months ended September 30, Nine months ended September 30,
2017 2016 2017 2016
Utility-related taxes $ 12,663
$ 12,095
$ 47,799
$ 43,033
Property taxes 9,991
10,047
29,829
29,757
Other taxes 615
527
2,105
1,879
Total $ 23,269
$ 22,669
$ 79,733
$ 74,669

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~~AVISTA CORPORATION~~

~~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 net realizable value for our non-regulated operations and consisted of the following as of ~~September 30, 2017~~ ~~and~~ ~~December 31, 2016~~ ~~(dollars in thousands):~~

September 30, December 31,
2017 2016
Materials and supplies $ 41,518
$ 40,700
Fuel stock 5,064
4,585
Stored natural gas 19,379
8,029
Total $ 65,961
$ 53,314

Derivative Assets and Liabilities

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

The ~~Washington Utilities and Transportation Commission (UTC)~~WUTC and the ~~Idaho Public Utilities Commission (IPUC)~~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 ~~purchased gas cost adjustments,~~PGAs, the ~~Energy Recovery Mechanism (ERM)~~ERM in Washington, the ~~Power Cost Adjustment (PCA)~~PCA mechanism in Idaho, and periodic general rate cases. The resulting regulatory assets ~~have been concluded to be~~associated with energy commodity derivative instruments are probable of recovery through future rates.

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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.

~~As of September 30, 2017, the~~

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, some equity investments, 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 812 for the Company’s fair value disclosures.

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~~AVISTA CORPORATION~~

~~Accumulated Other Comprehensive Loss~~

~~Accumulated other comprehensive loss, net of tax, consisted of the following as of September 30, 2017 and December 31, 2016 (dollars in thousands):~~

September 30, December 31,
2017 2016
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $3,780 and $4,075, respectively $ 7,020
$ 7,568

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

Amounts Reclassified from Accumulated Other Comprehensive Loss
Three months ended September 30, Nine months ended September 30,
Details about Accumulated Other Comprehensive Loss Components 2017 2016 2017 2016 Affected Line Item in Statement of Income
Amortization of defined benefit pension items
Amortization of net prior service cost $ (300 ) $ (312 ) $ (898 ) $ (934 ) (a)
Amortization of net loss 3,637
3,642
$ 10,913
$ 10,926
(a)
Adjustment due to effects of regulation (3,057 ) (3,115 ) (9,172 ) (11,453 ) (a) (b)
280
215
843
(1,461 ) Total before tax
(98 ) (75 ) (295 ) 512
Tax benefit (expense)
$ 182
$ 140
$ 548
$ (949 ) Net of tax


~~(a)~~	~~These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 4 for additional details).~~


~~(b)~~	The adjustment for the effects of regulation during the nine months ended September 30, 2016 includes approximately $2.1 million related to the reclassification of a pension regulatory asset associated with one of our jurisdictions into accumulated other comprehensive loss.

~~Effective Income Tax Rate~~

For the three months ended September 30, 2017 and 2016, the Company's effective tax rate was 53.6 percent and 38.3 percent, respectively. For the nine months ended September 30, 2017 and 2016, the Company's effective tax rate was 36.9 percent and 36.0 percent, respectively. The effective tax rate increased during 2017 because the majority of acquisition costs, which reduce income before income taxes, are not deductible for tax purposes and thus do not reduce income tax expense.

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. ~~As of~~ ~~September 30, 2017, the Company has not recorded any significant amounts related to unresolved contingencies.~~ See Note 1116 for further discussion of the Company's commitments and contingencies.

NOTE 2. NEW ACCOUNTING STANDARDS

ASU ~~No. 2014-09, “Revenue from Contracts with Customers (Topic 606)”~~

2022-03 "Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions"

In ~~May 2014,~~June 2022, the FASB issued ASU ~~No. 2014-09,~~2022-03, Fair Value Measurement (Topic 820): Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions. The purpose of this guidance is to clarify that a contractual restriction on the ability to sell an equity security is not considered part of the unit of account of the equity security, and therefore should not be considered when measuring the equity security's fair value. Additionally, an entity cannot separately recognize and measure a contractual sale restriction. This guidance also adds specific disclosures related to equity securities subject to contractual sale restrictions, including (i) the fair value of equity securities subject to contractual sale restrictions reflected in the balance sheet and (ii) the nature and remaining duration of the restrictions, and (iii) the circumstances that could cause a lapse in the restrictions. The amendments are effective on January 1, 2024, with early adoption permitted. The amendments must be applied using a prospective approach with any adjustments

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from the adoption of the amendments recognized in earnings and disclosed upon adoption. The Company does not expect the impact of these amendments to be material.

NOTE 3. BALANCE SHEET COMPONENTS

Inventory

Inventories of materials and supplies, emission allowances, fuel stock and stored natural gas are recorded at average cost and consisted of the following as of June 30, 2023 and December 31, 2022 (dollars in thousands):


	June 30,		December 31,
	2023		2022
Materials and supplies	$	80,569	$	75,766
Emission allowances		14,558		—
Stored natural gas		14,952		26,788
Fuel stock		5,726		5,120
Total	$	115,805	$	107,674

Other Current Assets

Other current assets consisted of the following as of June 30, 2023 and December 31, 2022 (dollars in thousands):


	June 30,		December 31,
	2023		2022
Prepayments	$	48,039	$	30,201
Income taxes receivable		23,264		30,740
Derivative assets net of collateral		121		18,198
Collateral posted for derivative instruments after netting with outstanding derivatives		9,770		66,142
Other		8,687		5,886
Total	$	89,881	$	151,167

Net Utility Property

Net utility property, which ~~outlines a single comprehensive model for entities to use~~is recorded at original cost, net of accumulated depreciation, consisted of the following as of June 30, 2023 and December 31, 2022 (dollars in ~~accounting for revenue arising from contracts with customers~~thousands):


	June 30,		December 31,
	2023		2022
Utility plant in service	$	7,619,473	$	7,561,688
Construction work in progress		175,010		164,147
Total		7,794,483		7,725,835
Less: Accumulated depreciation and amortization		2,245,832		2,281,126
Total	$	5,548,651	$	5,444,709

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Other Property and ~~supersedes most~~Investments-Net and Other Non-Current Assets

Other property and investments-net and other non-current assets consisted of the following as of June 30, 2023 and December 31, 2022 (dollars in thousands):


	June 30,		December 31,
	2023		2022
Equity investments	$	149,675	$	147,809
Operating lease ROU assets		68,594		68,238
Finance lease ROU assets		38,235		40,056
Non-utility property		30,995		25,401
Notes receivable		18,466		17,954
Long-term prepaid license fees		17,771		17,936
Pension assets		19,137		13,382
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		7,428		7,541
Held for sale		3,259		—
Other		16,701		15,221
Total	$	381,808	$	365,085

Other Current Liabilities

Other current ~~revenue recognition guidance, including industry-specific guidance.~~ liabilities consisted of the following as of June 30, 2023 and December 31, 2022 (dollars in thousands):


	June 30, 2023		December 31, 2022
Accrued taxes other than income taxes	$	30,838	$	38,568
Derivative liabilities		8,585		26,910
Employee paid time off accruals		33,022		29,279
Accrued interest		27,107		20,863
Deferred wholesale revenue		—		8,481
Pensions and other postretirement benefits		13,255		15,625
Other		35,676		49,689
Total	$	148,483	$	189,415

Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of June 30, 2023 and December 31, 2022 (dollars in thousands):


	June 30, 2023		December 31, 2022
Operating lease liabilities	$	66,537	$	64,284
Finance lease liabilities		40,795		42,495
Deferred investment tax credits		28,509		28,784
Climate Commitment Act obligations		32,994		—
Asset retirement obligations		15,946		15,783
Derivative liabilities		6,044		7,892
Other		15,912		16,617
Total	$	206,737	$	175,855

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Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of June 30, 2023 and December 31, 2022 (dollars in thousands):


	June 30, 2023				December 31, 2022
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	41,198	$	18,370	$	112,090	$	18,185
Decoupling surcharge		4,105		3,129		6,250		5,449
Deferred natural gas costs		88,897		—		52,091		—
Deferred power costs		29,706		20,527		23,356		24,043
Deferred income taxes		—		240,143		—		240,325
Pension and other postretirement benefit plans		—		132,530		—		135,337
Interest rate swaps		—		182,793		—		185,919
AFUDC above FERC allowed rate		—		50,365		—		51,649
Settlement with Coeur d'Alene Tribe		—		37,251		—		37,809
Advanced meter infrastructure		—		30,863		—		32,381
Utility plant abandoned		—		30,563		—		24,389
Deferred Climate Commitment Act costs		—		32,008		—		—
COVID-19 deferrals		—		9,230		—		9,793
Unamortized debt repurchase costs		—		5,934		—		6,177
Demand side management programs		—		485		—		3,683
Other regulatory assets		—		67,300		—		58,189
Total regulatory assets	$	163,906	$	861,491	$	193,787	$	833,328
Regulatory Liabilities
Income tax related liabilities	$	48,879	$	365,954	$	73,267	$	390,734
Deferred natural gas costs		4,924		—		—		—
Decoupling rebate		13,066		26,798		9,469		20,476
Utility plant retirement costs		—		403,291		—		376,817
Interest rate swaps		—		23,402		—		24,204
COVID-19 deferrals		—		11,069		—		11,874
Other regulatory liabilities		12,224		14,508		12,929		16,732
Total regulatory liabilities	$	79,093	$	845,022	$	95,665	$	840,837

NOTE 4. REVENUE

The core principle of the revenue recognition accounting model is that an entity should 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. ~~This ASU is effective for periods beginning after December 15, 2017.~~

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Utility Revenues

Revenue from Contracts with Customers

General

The Company has a revenue recognition standard implementation team that is working through the implementation process. The Company has evaluated this standard and is planning to adopt this standard in 2018 upon its effective date. The Company is expecting to use a modified retrospective method of adoption, which would require a cumulative adjustment to opening retained earnings, as opposed to a full retrospective application. Based on work performed to date, the Company has not identified any material cumulative adjustments necessary.

~~Since 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."

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Non-Derivative Wholesale Contracts

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

Alternative Revenue Programs (Decoupling)

ASC 606 retained existing GAAP associated with alternative revenue programs, which specified alternative revenue programs are contracts between an entity and a regulator of utilities, not ~~expect~~ a ~~significant change in operating~~contract between an entity and a customer. GAAP requires an entity to present revenue arising from alternative revenue programs separately from revenues ~~or net income. The Company has reviewed and analyzed certain~~arising from contracts with customers ~~(most~~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 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 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.

The Company records alternative program revenues under the gross method, which is to amortize the decoupling regulatory asset/liability to the alternative revenue program line item on the Condensed Consolidated Statements of Income as it is collected from or refunded to customers. The cash passing between the Company and the customers is presented in revenue from contracts with customers since it is a portion of the overall tariff paid by customers. This method results in a gross-up to both revenue from contracts with customers and revenue from alternative revenue programs, but has a net zero impact on total revenue. Depending on whether the previous deferral balance being amortized was a regulatory asset or regulatory liability, and depending on the size and direction of the current year deferral of surcharges and/or rebates to customers, it could result in negative alternative revenue program revenue during the year.

Derivative Revenue

Most wholesale electric and natural gas transactions (including both physical and financial transactions), and the sale of fuel are considered derivatives, which are ~~related to wholesale~~specifically excluded from revenue from contracts with customers and therefore disclosed separately. The revenue or loss is recognized for these items upon the settlement/expiration of the derivative contract. Derivative revenue includes those transactions entered into and settled within the same month.

Other Utility Revenue

Other utility revenue includes rent, sales of ~~power~~materials, late fees and ~~natural gas) and~~other charges that do not represent contracts with customers.Other utility revenue also includes the provision for earnings sharing. This revenue is excluded from revenue from contracts with customers, as this revenue does not represent items where a customer is a party that has ~~not yet identified any significant differences in revenue recognition between current GAAP and ASU No. 2014-09.~~

~~During the implementation process,~~contracted with the Company ~~has identified several issues,~~to obtain goods or services that are an output of the ~~most significant~~Company’s ordinary activities in exchange for consideration. As such, these revenues are presented separately from revenue from contracts with customers.

Other Considerations for Utility Revenues

Gross Versus Net Presentation

Revenues and resource costs from Avista Utilities’ settled energy contracts “booked out” (not physically delivered) are reported on a net basis as part of ~~which are as follows based on our current assessment:~~

~~Contributions in Aid~~derivative revenues.

Table of ~~Construction~~ – There was the potential that contributions in aid of construction (CIACs) could be recognized as revenue upon the adoption of ASU No. 2014-09. Under current GAAP, CIACs are accounted for as an offset to the cost of utility plant in service. Current implementation guidance indicates that CIACs will continue to be accounted for as an offset to utility plant in service.

AVISTA CORPORATION

Utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) are imposed on ~~a gross basis. Under current GAAP,~~Avista Utilities as opposed to being imposed on its customers; therefore, Avista Utilities is the ~~Company is allowed to record~~taxpayer and records these ~~utility-related taxes~~transactions on a gross basis in revenue ~~when billed to~~from contracts with customers ~~with an offset included in taxes~~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.

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


	Three months ended June 30,				Six months ended June 30,
	2023		2022		2023		2022
Utility-related taxes	$	16,133	$	14,908	$	41,872	$	37,042

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 ~~evaluated whether this gross presentation is appropriate under ASU 2014-09~~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 ~~Company's assessment indicates that there~~customers. The Company has one capacity agreement where the customer makes payments throughout the year. As of June 30, 2023, the Company estimates it had unsatisfied capacity performance obligations of $10.2 million, which will be ~~no material changes~~recognized as revenue in future periods as the capacity is provided to ~~current presentation.~~

the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.

~~Renewable Energy Credits~~ ~~- Current utility industry implementation guidance indicates that~~

Disaggregation of Total Operating Revenue

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


	Three months ended June 30,					Six months ended June 30,
	2023		2022			2023			2022
Avista Utilities
Revenue from contracts with customers	$	294,129	$	287,922		$	772,904		$	693,259
Derivative revenues		66,580		84,403			63,518			141,776
Alternative revenue programs		5,513		(5,793	)		(13,525	)		(22,570	)
Deferrals and amortizations for rate refunds to customers		228		(500	)		645			(131	)
Other utility revenues		2,154		2,483			5,204			5,053
Total Avista Utilities		368,604		368,515			828,746			817,387
AEL&P
Revenue from contracts with customers		11,023		10,266			25,234			23,221
Deferrals and amortizations for rate refunds to customers		—		(517	)		—			(565	)
Other utility revenues		171		157			323			304
Total AEL&P		11,194		9,906			25,557			22,960

Other non-utility revenues		139		145			265			265
Total operating revenues	$	379,937	$	378,566		$	854,568		$	840,612

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Utility Revenue from Contracts with Customers by Type and Service

The following table disaggregates revenue from contracts with customers associated with the ~~sale of self-generated renewable energy credits (REC) will be recognized at~~Company's electric operations for the ~~time of generation~~three and ~~sale of the credits as opposed to when the RECs are certified~~six months ended June 30 (dollars in ~~the Western Renewable Energy Generation Information System (WREGIS), which generally occurs during a period subsequent to the sale. This represents a change~~thousands):


	2023						2022
	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	$	86,499	$	4,418	$	90,917	$	84,108	$	4,156	$	88,264
Commercial		81,346		6,544		87,890		80,713		6,051		86,764
Industrial		27,956		—		27,956		27,253		—		27,253
Public street and highway lighting		1,980		61		2,041		1,912		59		1,971
Total retail revenue		197,781		11,023		208,804		193,986		10,266		204,252
Transmission		8,475		—		8,475		8,417		—		8,417
Other revenue from contracts with customers		6,934		—		6,934		7,409		—		7,409
Total electric revenue from contracts with customers	$	213,190	$	11,023	$	224,213	$	209,812	$	10,266	$	220,078
Six months ended June 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	209,322	$	11,299	$	220,621	$	205,111	$	10,617	$	215,728
Commercial		162,572		13,810		176,382		164,283		12,485		176,768
Industrial		53,123		—		53,123		52,145		—		52,145
Public street and highway lighting		3,935		125		4,060		3,776		119		3,895
Total retail revenue		428,952		25,234		454,186		425,315		23,221		448,536
Transmission		16,422		—		16,422		13,102		—		13,102
Other revenue from contracts with customers		24,227		—		24,227		16,171		—		16,171
Total electric revenue from contracts with customers	$	469,601	$	25,234	$	494,835	$	454,588	$	23,221	$	477,809

The following table disaggregates revenue from ~~the Company's current practice, which is to defer revenue recognition until the time of certification. Revenue~~contracts with customers associated with the ~~sale~~Company's natural gas operations for the three and six months ended June 30 (dollars in thousands):


	Three months ended June 30,				Six months ended June 30,
	2023		2022		2023		2022
	Avista Utilities		Avista Utilities		Avista Utilities		Avista Utilities
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	48,004	$	48,480	$	188,840	$	151,695
Commercial		25,477		23,736		97,802		74,357
Industrial and interruptible		4,128		2,346		9,656		5,308
Total retail revenue		77,609		74,562		296,298		231,360
Transportation		1,923		2,142		4,192		4,499
Other revenue from contracts with customers		1,407		1,406		2,813		2,812
Total natural gas revenue from contracts with customers	$	80,939	$	78,110	$	303,303	$	238,671

As of June 30, 2023, there were no expected deliveries of energy commodity derivatives after 2026.

AVISTA CORPORATION

The following table presents the underlying energy commodity derivative volumes as of December 31, ~~2016 that are~~2022 expected to be delivered or mature in ~~each~~the respective ~~year~~years shown (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
2023		5		—		19,140		79,253		136		1,011		4,145		29,473
2024		—		—		533		30,658		—		—		1,370		9,668
2025		—		—		450		4,895		—		—		1,115		1,125

As of December 31, 2022, there were no expected deliveries of energy commodity derivatives after 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.

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
2017 510
907
15,475
110,380
316
1,552
4,165
73,110
2018 397
—
—
52,755
286
1,244
1,360
15,113
2019 235
—
610
29,475
158
982
1,345
4,020
2020 —
—
910
2,725
—
—
1,430
—
2021 —
—
—
—
—
—
1,060
—
Thereafter —
—
—
—
—
—
—
—


~~(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.

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

The following table summarizes the foreign currency exchange derivatives ~~that Avista Corp. has~~ outstanding as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016~~2022 (dollars in thousands):


	June 30,		December 31,
	2023		2022
Number of contracts		17		19
Notional amount (in United States dollars)	$	8,479	$	8,563
Notional amount (in Canadian dollars)		11,255		11,659

September 30, December 31,
2017 2016
Number of contracts 19
21
Notional amount (in United States dollars) $ 3,198
$ 2,819
Notional amount (in Canadian dollars) 3,925
3,754

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.~~derivatives. 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.

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The following table summarizes the unsettled interest rate swap derivatives ~~that Avista Corp. has~~ outstanding as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016~~2022 (dollars in thousands):


Balance Sheet Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date
June 30, 2023		2	$	20,000	2024
December 31, 2022		4	$	40,000	2023
		1		10,000	2024

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Balance Sheet Date Number of Contracts Notional Amount Mandatory Cash Settlement Date
September 30, 2017 14 $ 275,000
2018
6 70,000
2019
3 30,000
2020
1 15,000
2021
5 60,000
2022
December 31, 2016 6 $ 75,000
2017
14 275,000
2018
6 70,000
2019
2 20,000
2020
5 60,000
2022

~~During~~

See Note 10 for discussion of the ~~third quarter 2017,~~issuance of first mortgage bonds and the related settlement of interest rate swaps in connection with the pricing of ~~$90.0 million of Avista Corp. first mortgage~~the bonds ~~that are expected to be issued~~ in December 2017 (see Note 6), the Company cash-settled five interest rate swap derivatives (notional aggregate amount of $60.0 million) and paid a net amount of $8.8 million. Upon settlement of interest rate swap derivatives, the cash payments made or received are recorded as a regulatory asset or liability and are subsequently amortized as a component of interest expense over the life of the associated debt. The settled interest rate swap derivatives are also included as a part of the Company's cost of debt calculation for ratemaking purposes.

March 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. Upon settlement of interest rate swaps, the cash payments made or received are recorded as a regulatory asset or liability and are amortized as a component of interest expense over the life of the associated debt. The settled interest rate swaps are also included as a part of the Company's cost of debt calculation for ratemaking purposes.

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Summary of Outstanding Derivative Instruments

The amounts recorded on the Condensed Consolidated Balance Sheet as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016~~2022 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of ~~September~~June 30, ~~2017~~2023 (in thousands):

Fair Value as of September 30, 2017
Derivative and Balance Sheet Location
Gross
Asset

Gross
Liability

Collateral
Netted

Net Asset
(Liability)
on Balance
Sheet
Foreign currency exchange derivatives
Other current liabilities $ —
$ (51 ) $ —
$ (51 )
Interest rate swap derivatives
Other current assets 2,637
(249 ) —
2,388
Other property and investments-net and other non-current assets 5,346
(1,896 ) —
3,450
Current interest rate swap derivative liabilities —
(63,074 ) 28,554
(34,520 )
Non-current interest rate swap derivative liabilities —
(7,136 ) 5,806
(1,330 )
Energy commodity derivatives
Other current assets 197
(70 ) —
127
Current energy commodity derivative liabilities 23,904
(46,036 ) 11,078
(11,054 )
Other non-current liabilities, regulatory liabilities and deferred credits 13,891
(30,262 ) 4,569
(11,802 )
Total derivative instruments recorded on the balance sheet $ 45,975
$ (148,774 ) $ 50,007
$ (52,792 )


	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	$	16	$	—		$	—	$	16
Interest rate swap derivatives
Other property and investments-net and other non-current assets		2,883		—			—		2,883
Energy commodity derivatives
Other current assets		715		(610	)		—		105
Other property and investments-net and other non-current assets		447		(282	)		—		165
Other current liabilities		27,571		(68,874	)		32,718		(8,585	)
Other non-current liabilities and deferred credits		4,552		(23,087	)		12,491		(6,044	)
Total derivative instruments recorded on the balance sheet	$	36,184	$	(92,853	)	$	45,209	$	(11,460	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, ~~2016~~2022 (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	$	43	$	—		$	—	$	43
Other current liabilities		—		(3	)		—		(3	)
Interest rate swap derivatives
Other current assets		8,536		—			—		8,536
Other property and investments-net and other non-current assets		2,648		—			—		2,648
Other current liabilities		—		(52	)		—		(52	)
Energy commodity derivatives
Other current assets		32,257		(22,638	)		—		9,619
Other property and investments-net and other non-current assets		312		(16	)		—		296
Other current liabilities		107,902		(229,607	)		94,850		(26,855	)
Other non-current liabilities and deferred credits		6,049		(24,530	)		10,589		(7,892	)
Total derivative instruments recorded on the balance sheet	$	157,747	$	(276,846	)	$	105,439	$	(13,660	)

Fair Value as of December 31, 2016
Derivative and Balance Sheet Location
Gross
Asset

Gross
Liability
Collateral
Netted Net Asset
(Liability)
on Balance
Sheet
Foreign currency exchange derivatives
Other current liabilities $ 5
$ (28 ) $ —
$ (23 )
Interest rate swap derivatives
Other current assets 3,393
—
—
3,393
Other property and investments-net and other non-current assets 5,754
(397 ) —
5,357
Current interest rate swap derivative liabilities —
(15,756 ) 9,731
(6,025 )
Non-current interest rate swap derivative liabilities 3,951
(57,825 ) 25,169
(28,705 )
Energy commodity derivatives
Other current assets 18,682
(16,787 ) —
1,895
Current energy commodity derivative liabilities 16,335
(29,598 ) 6,228
(7,035 )
Other non-current liabilities, regulatory liabilities and deferred credits 13,071
(29,990 ) 3,630
(13,289 )
Total derivative instruments recorded on the balance sheet $ 61,191
$ (150,381 ) $ 44,758
$ (44,432 )

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

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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

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facilities and cash. Avista Corp. actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements.

The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016~~2022 (in thousands):

September 30, December 31,
2017 2016
Energy commodity derivatives
Cash collateral posted $ 19,570
$ 17,134
Letters of credit outstanding 31,500
24,400
Balance sheet offsetting (cash collateral against net derivative positions) 15,647
9,858

Interest rate swap derivatives
Cash collateral posted 34,360
34,900
Letters of credit outstanding 6,000
3,600
Balance sheet offsetting (cash collateral against net derivative positions) 34,360
34,900


	June 30,		December 31,
	2023		2022
Energy commodity derivatives
Cash collateral posted	$	54,978	$	171,581
Letters of credit outstanding		16,000		49,425
Balance sheet offsetting		45,209		105,439

No letters of credit or cash collateral were outstanding related to interest rate swap derivatives as of June 30, 2023 and December 31, 2022.

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 ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016~~2022 (in thousands):


	June 30,		December 31,
	2023		2022
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features	$	—	$	52
Additional collateral to post		—		52

September 30, December 31,
2017 2016
Energy commodity derivatives
Liabilities with credit-risk-related contingent features $ 670
$ 1,124
Additional collateral to post 670
1,046

Interest rate swap derivatives
Liabilities with credit-risk-related contingent features 72,355
73,978
Additional collateral to post 12,730
21,100

NOTE 4.7. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Avista Utilities

Avista Utilities’ pension and other postretirement plans have not changed during the nine months ended September 30, 2017. 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 ~~$22.0~~$6.7 million in cash to the pension plan for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023, and ~~does not expect any further contributions during 2017. The Company contributed $12.0~~expects to contribute $10.0 million in ~~cash to the pension plan in~~ ~~2016~~.

2023.

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~~AVISTA CORPORATION~~

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


	Pension Benefits						Other Postretirement Benefits
	2023			2022			2023			2022
Three months ended June 30:
Service cost	$	3,100		$	6,229		$	532		$	1,097
Interest cost		8,521			6,520			1,909			1,384
Expected return on plan assets		(10,922	)		(10,950	)		(891	)		(700	)
Amortization of prior service cost		123		��	75			(263	)		(275	)
Net loss recognition		1,185			939			(8	)		870
Net periodic benefit cost	$	2,007		$	2,813		$	1,279		$	2,376
Six months ended June 30:
Service cost	$	7,994		$	12,000		$	1,350		$	2,160
Interest cost		15,753			13,427			2,953			2,824
Expected return on plan assets		(21,844	)		(21,901	)		(1,782	)		(1,400	)
Amortization of prior service cost		246			150			(526	)		(550	)
Net loss recognition		2,024			2,087			525			1,760
Net periodic benefit cost	$	4,173		$	5,763		$	2,520		$	4,794

Pension Benefits Other Post-retirement Benefits
2017 2016 2017 2016
Three months ended September 30:
Service cost $ 5,092
$ 4,567
$ 799
$ 806
Interest cost 6,976
6,895
1,374
1,530
Expected return on plan assets (7,900 ) (6,887 ) (475 ) (465 )
Amortization of prior service cost —
1
(274 ) (300 )
Net loss recognition 2,517
2,161
1,168
1,453
Net periodic benefit cost $ 6,685
$ 6,737
$ 2,592
$ 3,024
Nine months ended September 30:
Service cost $ 15,226
$ 13,655
$ 2,422
$ 2,389
Interest cost 20,903
20,695
4,147
4,623
Expected return on plan assets (23,700 ) (20,512 ) (1,425 ) (1,415 )
Amortization of prior service cost —
1
(898 ) (924 )
Net loss recognition 7,380
6,252
3,761
4,312
Net periodic benefit cost $ 19,809
$ 20,091
$ 8,007
$ 8,985

Total ~~net periodic benefit~~service costs in the table above are ~~recorded to~~recognized in the same accounts as the associated 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 8. 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.

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


	Three months ended June 30,										Six months ended June 30,
	2023					2022					2023					2022
Federal income taxes at statutory rates	$	2,452		21.0	%	$	2,195		21.0	%	$	12,577		21.0	%	$	14,948		21.0	%
Increase (decrease) in tax resulting from:
Flow through related to deduction of meters and mixed service costs (1)		(5,689	)	(48.7	)		(2,401	)	(23.0	)		(19,212	)	(32.1	)		(19,835	)	(27.9	)
Tax effect of regulatory treatment of utility plant differences		(1,525	)	(13.1	)		(976	)	(9.3	)		(5,212	)	(8.7	)		(7,298	)	(10.3	)
State income tax expense		232		2.0			78		0.7			798		1.3			901		1.3
Tax credits		(1,135	)	(9.7	)		—		—			(1,135	)	(1.9	)		—		—
Other		(145	)	(1.3	)		105		1.0			(254	)	(0.4	)		(551	)	(0.7	)
Total income tax benefit	$	(5,810	)	(49.8	)%	$	(999	)	(9.6	)%	$	(12,438	)	(20.8	)%	$	(11,835	)	(16.6	)%

(1)

The Company's general rate cases included approval of base rate increases, offset by tax customer credits. As the tax customer credits are returned to customers, this results in a decrease to income tax expense as a result of flowing through the benefits related to meters and mixed service costs. The decrease in income tax expense offsets the increases in base rates granted to the Company in these general rate cases.

NOTE ~~5. COMMITTED LINES OF CREDIT~~

9. SHORT-TERM BORROWINGS

Avista Corp.

Lines of Credit

Avista Corp. has a committed line of credit ~~with various financial institutions~~ in the total amount of $~~400.0~~500 million, ~~that expires in~~ ~~April 2021~~ with an expiration date of June 2028 and the option to extend for two additional one year periods (subject to customary conditions). In June 2023, the then-existing agreement was amended to increase the capacity of the committed line of credit from $400 million to $500 million, extend the expiration date and replace the London Interbank Offered Rate (LIBOR) provisions with SOFR provisions. The committed line of credit is secured by non-transferable first mortgage bonds of ~~the Company~~Avista Corp. issued to the agent bank that would only ~~become due and~~be payable in the event, and then only to the extent, ~~that the Company~~Avista Corp. defaults on its obligations under the committed line of credit.

The bonds would bear interest at a rate of 12 percent.

~~Borrowings~~

Balances outstanding and interest rates ofon borrowings (excluding letters of credit) under ~~the Company’s~~Avista Corp.’s revolving committed line of credit were as follows as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016~~2022 (dollars in thousands):


	June 30,			December 31,
	2023			2022
Borrowings outstanding at end of period	$	203,000		$	313,000
Letters of credit outstanding at end of period		4,638			35,563
Average interest rate on borrowings at end of period		6.24	%		5.31	%

September 30, December 31,
2017 2016
Borrowings outstanding at end of period (1) $ 195,000
$ 120,000
Letters of credit outstanding at end of period $ 43,853
$ 34,353
Average interest rates at end of period 1.99 % 1.50 %

~~(1)~~

As of September 30, 2017, there was $195.0 million outstanding under the committed line of credit; however, $105.9 million was classified as short-term borrowings and the remaining $89.1 million was classified as long-term debt on the Condensed Consolidated Balance Sheet due to the Company's intention to refinance such amount on a long-term basis through the issuance and sale of first mortgage bonds in December 2017 pursuant to a bond purchase agreement entered into in September 2017. See Note 7 for further discussion of the bond purchase agreement and the refinancing of short-term debt on a long-term basis. In addition, there were short-term borrowings outstanding as of September 30, 2017 on the Condensed Consolidated Balance Sheet related to a short-term note payable by a subsidiary for the acquisition of land that is expected to be repaid in early 2018.

In December 2022, Avista Corp. entered into a revolving credit agreement in the amount of $100 million. As of December 31, 2022, Avista Corp. did not have any outstanding borrowings under this agreement. The agreement was terminated in June 2023.

The borrowings outstanding under Avista Corp.'s committed lines of credit were classified as short-term borrowings on the Condensed Consolidated Balance Sheets.

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2022 Term Loan

In December 2022, Avista Corp. entered into a term loan agreement in the amount of $150 million with a maturity date of March 30, 2023. Avista Corp. borrowed the entire $150 million available under the agreement in 2022, and repaid the entire outstanding balance in March 2023.

2022 Letter of Credit Facility

In December 2022, Avista Corp. entered into a letter of credit agreement in the aggregate amount of $50 million. Either party may terminate the agreement at any time.

Avista Corp. had $16.0 million and $18.5 million in letters of credit outstanding under this agreement as of June 30, 2023 and December 31, 2022, respectively. Letters of credit are not reflected on the Condensed Consolidated Balance Sheets. If a letter of credit were drawn upon by the holder, we would have an immediate obligation to reimburse the bank that issued the letter.

Covenants and Default Provisions

The short-term borrowing agreements contain customary covenants and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and, in the case of the letter of credit agreement, other obligations. The committed line of credit agreement also includes a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time. As of June 30, 2023, the Company was in compliance with this covenant.

AEL&P

AEL&P has a committed line of credit in the amount of $25.0 million that expires in ~~November 2019~~June 2028. ~~As of~~ ~~September 30, 2017~~ ~~and December 31, 2016, there~~There were no borrowings or letters of credit outstanding under this ~~committed line~~agreement as of ~~credit.~~June 30, 2023 and December 31, 2022. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would

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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 6.10. LONG-TERM DEBT ~~AND CAPITAL LEASES~~

~~The following details long-term debt outstanding~~

In March 2023, the Company issued and sold $250.0 million of 5.66 percent first mortgage bonds due in 2053 with institutional investors in the private placement market. In connection with the pricing of the first mortgage bonds in March 2023, the Company cash-settled four interest rate swap derivatives (notional aggregate amount of $40.0 million) and received a net amount of $7.5 million, which will be amortized as a component of ~~September 30, 2017 and December 31, 2016 (dollars in thousands):~~

Maturity
Year
Description
Interest
Rate
September 30,
2017 December 31,
2016
Avista Corp. Secured Long-Term Debt
2018 First Mortgage Bonds 5.95% $ 250,000
$ 250,000
2018 Secured Medium-Term Notes 7.39%-7.45% 22,500
22,500
2019 First Mortgage Bonds 5.45% 90,000
90,000
2020 First Mortgage Bonds 3.89% 52,000
52,000
2022 First Mortgage Bonds 5.13% 250,000
250,000
2023 Secured Medium-Term Notes 7.18%-7.54% 13,500
13,500
2028 Secured Medium-Term Notes 6.37% 25,000
25,000
2032 Secured Pollution Control Bonds (1) (1) 66,700
66,700
2034 Secured Pollution Control Bonds (1) (1) 17,000
17,000
2035 First Mortgage Bonds 6.25% 150,000
150,000
2037 First Mortgage Bonds 5.70% 150,000
150,000
2040 First Mortgage Bonds 5.55% 35,000
35,000
2041 First Mortgage Bonds 4.45% 85,000
85,000
2044 First Mortgage Bonds 4.11% 60,000
60,000
2045 First Mortgage Bonds 4.37% 100,000
100,000
2047 First Mortgage Bonds 4.23% 80,000
80,000
2051 First Mortgage Bonds 3.54% 175,000
175,000
Total Avista Corp. secured long-term debt 1,621,700
1,621,700
Alaska Electric Light and Power Company Secured Long-Term Debt
2044 First Mortgage Bonds 4.54% 75,000
75,000
Total secured long-term debt 1,696,700
1,696,700
Alaska Energy and Resources Company Unsecured Long-Term Debt
2019 Unsecured Term Loan 3.85% 15,000
15,000
Total secured and unsecured long-term debt 1,711,700
1,711,700
Other Long-Term Debt Components
Capital lease obligations 62,969
65,435
Unamortized debt discount (668 ) (792 )
Unamortized long-term debt issuance costs (9,986 ) (10,639 )
Committed line of credit to be refinanced on a long-term basis (2) 89,100
—
Total 1,853,115
1,765,704
Secured Pollution Control Bonds held by Avista Corporation (1) (83,700 ) (83,700 )
Current portion of long-term debt and capital leases (277,626 ) (3,287 )
Total long-term debt and capital leases $ 1,491,789
$ 1,678,717

~~(1)~~

In December 2010, $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due in 2032 and 2034, respectively, which had been held by Avista Corp. since 2008 and 2009, respectively, were refunded by new variable rate bond issues (Series 2010A and Series 2010B). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, these bonds may be remarketed to

~~Table~~interest expense over the life of ~~Contents~~

~~AVISTA CORPORATION~~

~~unaffiliated investors. So long as Avista Corp. is~~ the ~~holder~~debt. See Note 6 for a discussion of interest rate swap derivatives.

A portion of the net proceeds from the sale of these bonds will be used for the ~~bonds will not be reflected as an asset~~construction or improvement of utility facilities, and a ~~liability on~~portion was used to refinance existing indebtedness, including the repayment of Avista Corp.'s ~~Consolidated Balance Sheets.~~$150 million term loan.

~~(2)~~

In September 2017, the Company entered into a bond purchase agreement with four institutional investors in the private placement market for the issuance and sale of $90.0 million of Avista Corp. first mortgage bonds in December 2017. The first mortgage bonds will bear a coupon rate of 3.91 percent and mature in December 2047. The Company intends to use the $90.0 million of bond proceeds, less issuance costs, to refinance on a long-term basis $89.1 million outstanding under the Company's committed line of credit. As such, $89.1 million has been excluded from current liabilities and is recorded as long-term debt on the Condensed Consolidated Balance Sheets as of September 30, 2017. In connection with the pricing of the first mortgage bonds, the Company cash-settled five interest rate swap derivatives (notional aggregate amount of $60.0 million) and paid a net amount of $8.8 million.

NOTE 7.11. 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.

Effective July 3, 2023, the reference to LIBOR in the formulation for the distribution rate on these securities was replaced with three-month CME Term SOFR, as calculated and published by CME Group Benchmark Administration, Ltd. (a successor administrator), plus a tenor

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spread adjustment of 0.26 percent. Accordingly, the distribution rate on the Preferred Trust Securities will now be the three-month CME Term SOFR plus 1.137 percent calculated and reset quarterly.

The distribution rates ~~paid~~ were as follows during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and the year ended December 31, ~~2016:~~2022:


	June 30,			December 31,
	2023			2022
Low distribution rate		5.64	%		1.05	%
High distribution rate		6.37	%		5.64	%
Distribution rate at the end of the period		6.37	%		5.64	%

September 30, December 31,
2017 2016
Low distribution rate 1.81 % 1.29 %
High distribution rate 2.19 % 1.81 %
Distribution rate at the end of the period 2.19 % 1.81 %

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. ~~These debt securities~~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 condensed 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 8.12. FAIR VALUE

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

Sheets may be different from the estimated fair value. See below for the estimated fair value of long-term debt and long-term debt to affiliated trusts.

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

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

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

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

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~~AVISTA CORPORATION~~

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

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determination of the fair values incorporates various factors ~~that not only include~~including the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), ~~but also~~and the impact of Avista Corp.’s nonperformance risk on its liabilities.

The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016~~2022 (dollars in thousands):


	June 30, 2023				December 31, 2022
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	1,107,000	$	975,122	$	1,113,500	$	966,881
Long-term debt (Level 3)		1,450,000		1,137,437		1,200,000		881,480
Snettisham finance lease obligation (Level 3)		44,113		40,500		45,730		41,700
Long-term debt to affiliated trusts (Level 3)		51,547		42,284		51,547		42,836

September 30, 2017 December 31, 2016

Carrying
Value

Estimated
Fair Value

Carrying
Value

Estimated
Fair Value
Long-term debt (Level 2) $ 951,000
$ 1,072,557
$ 951,000
$ 1,048,661
Long-term debt (Level 3) 677,000
704,130
677,000
675,251
Snettisham capital lease obligation (Level 3) 60,349
62,000
62,160
62,800
Long-term debt to affiliated trusts (Level 3) 51,547
41,238
51,547
38,660

These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The price ranges obtained from the third party brokers consisted of ~~par values~~market prices of ~~80.00~~60.96 percent to ~~129.64,~~106.85 percent of the principal amount, where ~~a par value~~100.0 percent of ~~100.0~~the principal amount (adjusted for unamortized discount or premium) represents the carrying value recorded on the Condensed Consolidated Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices; however, due to their limited trading activity, they are classified as Level 2 because brokers must generate quotes and make estimates if there is no trading activity near a period end. Level 3 long-term debt consists of private placement bonds and debt to affiliated trusts, which typically have no secondary trading activity. Fair values in Level 3 are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for Avista Corp. bonds. Due to the unique nature of the Snettisham ~~capital~~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 ~~capital~~finance lease obligation was discounted to present value using the Morgan Markets A Ex-Fin discount rate as published on ~~September~~June 30, ~~2017.~~

2023 and December 31, 2022.

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~~AVISTA CORPORATION~~

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Condensed Consolidated Balance Sheets as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016~~2022 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, 2023
Assets:
Energy commodity derivatives	$	—	$	33,285	$	—	$	(33,015	)	$	270
Foreign currency exchange derivatives		—		16		—		—			16
Interest rate swap derivatives		—		2,883		—		—			2,883
Equity Investments		—		—		48,453		—			48,453
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		1,142		—		—		—			1,142
Equity securities (3)		6,140		—		—		—			6,140
Total	$	7,282	$	36,184	$	48,453	$	(33,015	)	$	58,904
Liabilities:
Energy commodity derivatives (2)	$	—	$	81,132	$	11,721	$	(78,224	)	$	14,629
Total	$	—	$	81,132	$	11,721	$	(78,224	)	$	14,629
December 31, 2022
Assets:
Energy commodity derivatives (2)	$	—	$	146,232	$	288	$	(136,605	)	$	9,915
Foreign currency exchange derivatives		—		43		—		—			43
Interest rate swap derivatives		—		11,184		—		—			11,184
Equity Investments		—		—		54,284		—			54,284
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		1,267		—		—		—			1,267
Equity securities (3)		6,132		—		—		—			6,132
Total	$	7,399	$	157,459	$	54,572	$	(136,605	)	$	82,825
Liabilities:
Energy commodity derivatives (2)	$	—	$	258,769	$	18,022	$	(242,044	)	$	34,747
Foreign currency exchange derivatives		—		3		—		—			3
Interest rate swap derivatives		—		52		—		—			52
Total	$	—	$	258,824	$	18,022	$	(242,044	)	$	34,802

(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.

Level 1 Level 2 Level 3 Counterparty
and Cash
Collateral
Netting (1) Total
September 30, 2017
Assets:
Energy commodity derivatives $ —
$ 37,902
$ —
$ (37,775 ) $ 127
Level 3 energy commodity derivatives:
Natural gas exchange agreement —
—
90
(90 ) —
Interest rate swap derivatives —
7,983
—
(2,145 ) 5,838
Deferred compensation assets:
Fixed income securities (2) 1,692
—
—
—
1,692
Equity securities (2) 6,276
—
—
—
6,276
Total $ 7,968
$ 45,885
$ 90
$ (40,010 ) $ 13,933
Liabilities:
Energy commodity derivatives $ —
$ 56,013
$ —
$ (53,422 ) $ 2,591
Level 3 energy commodity derivatives:
Natural gas exchange agreement —
—
3,689
(90 ) 3,599
Power exchange agreement —
—
16,654
—
16,654
Power option agreement —
—
12
—
12
Foreign currency exchange derivatives —
51
—
—
51
Interest rate swap derivatives —
72,355
—
(36,505 ) 35,850
Total $ —
$ 128,419
$ 20,355
$ (90,017 ) $ 58,757

(2)

The Level 3 energy commodity derivative balances are associated with natural gas exchange agreements.

(3)

26Included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.

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~~AVISTA CORPORATION~~

Level 1 Level 2 Level 3 Counterparty
and Cash
Collateral
Netting (1) Total
December 31, 2016
Assets:
Energy commodity derivatives $ —
$ 47,994
$ —
$ (46,099 ) $ 1,895
Level 3 energy commodity derivatives:
Natural gas exchange agreement —
—
69
(69 ) —
Power exchange agreement —
—
25
(25 ) —
Foreign currency exchange derivatives —
5
—
(5 ) —
Interest rate swap derivatives —
13,098
—
(4,348 ) 8,750
Deferred compensation assets:
Fixed income securities (2) 1,789
—
—
—
1,789
Equity securities (2) 5,481
—
—
—
5,481
Total $ 7,270
$ 61,097
$ 94
$ (50,546 ) $ 17,915
Liabilities:
Energy commodity derivatives $ —
$ 56,871
$ —
$ (55,957 ) $ 914
Level 3 energy commodity derivatives:
Natural gas exchange agreement —
—
5,954
(69 ) 5,885
Power exchange agreement —
—
13,474
(25 ) 13,449
Power option agreement —
—
76
—
76
Foreign currency exchange derivatives —
28
—
(5 ) 23
Interest rate swap derivatives —
73,978
—
(39,248 ) 34,730
Total $ —
$ 130,877
$ 19,504
$ (95,304 ) $ 55,077


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


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

AVISTA CORPORATION

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 36 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 ~~(NYMEX)~~ 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.

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~~AVISTA CORPORATION~~

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 million as of September 30, 2017 and $0.4 million as of December 31, 2016.~~

Level 3 Fair Value

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

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

Natural Gas Exchange Agreement

For the natural gas commodity exchange agreement, the Company uses the same Level 2 ~~brokered~~market quotes described above; however, the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions ~~have~~are not ~~been~~ highly correlated with market prices and market volatility.

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of ~~September~~June 30, ~~2017~~2023 (dollars in thousands):

Fair Value (Net) at
September 30, 2017 Valuation Technique
Unobservable
Input
Range
Power exchange agreement $ (16,654 )
Surrogate facility
pricing
O&M charges $38.87-$45.20/MWh (1)
Escalation factor 5% - 2018 to 2019
Transaction volumes 396,984 - 432,357 MWhs
Power option agreement

$ (12 )
Black-Scholes-
Merton
Strike price $34.85/MWh - 2019
$47.54/MWh - 2018
Delivery volumes 157,517 - 222,683 MWhs
Natural gas exchange
agreement
$ (3,599 ) Internally derived
weighted average
cost of gas
Forward purchase
prices
$1.70 - $2.24/mmBTU

Forward sales prices $1.63 - $3.20/mmBTU
Purchase volumes 115,000 - 310,000 mmBTUs
Sales volumes 60,000 - 310,000 mmBTUs

~~(1) The average O&M charges for the delivery year beginning in November 2017 are~~ ~~$41.95~~ per MWh. For ratemaking purposes the average O&M charges to be included for recovery in retail rates vary slightly between regulatory jurisdictions. The average O&M charges for the delivery year beginning in 2017 are $45.32 for Washington and $41.95 for Idaho.


	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	June 30, 2023			Technique	Input	Average Price
Natural gas exchange agreement	$	(11,721	)	Internally derived weighted average cost of gas	Forward purchase prices	$2.53 - $3.39/mmBTU $2.99 Weighted Average
					Forward sales prices	$2.92 - $9.53/mmBTU $6.79 Weighted Average
					Purchase volumes	140,000 - 310,000 mmBTUs
					Sales volumes	75,000 - 310,000 mmBTUs

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~~AVISTA CORPORATION~~

The valuation methods, significant inputs and resulting fair values described above were developed by the Company's management and are reviewed on at least a quarterly basis to ensure they provide a reasonable estimate of fair value each reporting period.

Equity Investments

The Company has two equity investments measured at fair value on a recurring basis. For one investment, fair value is determined using a market approach, starting with enterprise values from recent market transaction data for comparable companies with similar equity instruments. The market transaction data was used to estimate an enterprise value of the underlying investment and that value was allocated to the various classes of equity via an option pricing model and a waterfall approach. The selection of appropriate comparable companies and the expected time to a liquidation event requires management judgment. The significant assumptions in the analysis include the comparable market transactions and related enterprise values, time to liquidity event and the market discount for lack of liquidity. In the event there are relevant market transactions for the same or similar securities of the subject company or there is the reasonable possibility of a transaction occurring, those transactions are utilized as an input to the valuation with a probability weight applied to the valuation.

For the second investment, the fair value is determined using an income approach utilizing a discounted cash flow model. The model is based on income statement forecasts from the underlying company to determine cash flows for the period of ownership. The model then utilizes market multiples from publicly traded comparable companies in similar industries and projects to estimate the terminal fair value. The market multiples are reduced to reflect the difference in the life cycle between the publicly traded comparable companies and the start-up nature of the investment company. The selection of appropriate comparable companies, market multiples and the reduction to those market multiples requires management judgment. The significant assumptions in the model include the discount rate representing the risk associated with the investment, market multiples and the related reduction to those multiples, revenue forecasts, and the estimated terminal date for the investment. In the event there are relevant market transactions for the same or similar securities of the subject company or there is the reasonable possibility of a transaction occurring, those transactions are used to determine the fair value of Avista Corp.’s investment under a market approach instead of utilizing a discounted cash flow model. The market transactions are considered Level 3 inputs because they are not publicly available observable transactions.

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 equity investments as of June 30, 2023 (dollars in thousands):


	Fair Value at
	June 30, 2023		Valuation Technique	Unobservable Input	Range
Equity investments	$	48,453	Market approach	Comparable enterprise values	$130,000-$388,600 $246,000 Average
				Time to liquidity event	0 to 2 years
				Probability weighting	75%/25%
			Discounted cash flows	Revenue market multiples	1.39x to 7.10x Revenue 3.39x Average
				Market exit reduction	50%
				Discount rate	25%
				Annual revenues	$14,000 - $265,000
				Terminal date	2026

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


	Natural Gas Exchange Agreement (1)			Equity Investments			Total
Three Months Ended June 30, 2023:
Beginning balance	$	(11,062	)	$	51,014		$	39,952
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		(1,016	)		—			(1,016	)
Recognized in net income		—			(2,561	)		(2,561	)
Purchases and debt conversions		—			—			—
Settlements		357			—			357
Other		—			—			—
Ending balance as of June 30, 2023	$	(11,721	)	$	48,453		$	36,732
Three Months Ended June 30, 2022:
Beginning balance	$	(6,197	)	$	—		$	(6,197	)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		5,196			—			5,196
Settlements		(1,288	)		—			(1,288	)
Ending balance as of June 30, 2022	$	(2,289	)	$	—		$	(2,289	)
Six Months Ended June 30, 2023:
Beginning balance	$	(17,734	)	$	54,284		$	36,550
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		5,767			—			5,767
Recognized in net income		—			(5,198	)		(5,198	)
Purchases and debt conversions		—			2,367			2,367
Settlements		246			—			246
Other		—			(3,000	)		(3,000	)
Ending balance as of June 30, 2023	$	(11,721	)	$	48,453		$	36,732
Six Months Ended June 30, 2022:
Beginning balance	$	(7,771	)	$	—		$	(7,771	)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		7,695			—			7,695
Settlements		(2,213	)		—			(2,213	)
Ending balance as of June 30, 2022	$	(2,289	)	$	—		$	(2,289	)

(1)

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

Natural Gas Exchange Agreement Power Exchange Agreement Power Option Agreement Total
Three months ended September 30, 2017:
Balance as of July 1, 2017 $ (4,173 ) $ (13,784 ) $ (43 ) $ (18,000 )
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1) 617
(2,870 ) 31
(2,222 )
Settlements (43 ) —
—
(43 )
Ending balance as of September 30, 2017 (2) $ (3,599 ) $ (16,654 ) $ (12 ) $ (20,265 )
Three months ended September 30, 2016:
Balance as of July 1, 2016 $ (6,857 ) $ (14,614 ) $ (105 ) $ (21,576 )
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1) 336
(1,696 ) (692 ) (2,052 )
Settlements —
—
—
—
Ending balance as of September 30, 2016 (2) $ (6,521 ) $ (16,310 ) $ (797 ) $ (23,628 )
Nine months ended September 30, 2017:
Balance as of January 1, 2017 $ (5,885 ) $ (13,449 ) $ (76 ) $ (19,410 )
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1) 2,434
(8,035 ) 64
(5,537 )
Settlements (148 ) 4,830
—
4,682
Ending balance as of September 30, 2017 (2) $ (3,599 ) $ (16,654 ) $ (12 ) $ (20,265 )

Nine months ended September 30, 2016:
Balance as of January 1, 2016 $ (5,039 ) $ (21,961 ) $ (124 ) $ (27,124 )
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1) (2,960 ) 272
(673 ) (3,361 )
Settlements 1,478
5,379
—
6,857
Ending balance as of September 30, 2016 (2) $ (6,521 ) $ (16,310 ) $ (797 ) $ (23,628 )


~~(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 9.13. COMMON STOCK

The Company ~~has entered into four separate~~issued common stock for total net proceeds of $29.6 million and $59.5 million during the three and six months ended June 30, 2023, respectively. Most of these issuances came through the Company's sales agency agreements under which ~~Avista Corp.'s sales agents~~the Company may offer and sell ~~up to 3.8 million~~ new shares of ~~Avista Corp.'s~~ common stock ~~no par value,~~through its sales agents from time to time. ~~The~~Under these sales agency agreements, ~~expire on February 29, 2020. As of September 30, 2017, 1.6~~the Company issued 0.8 million and 1.5 million shares ~~have been issued under these agreements, leaving 2.2 million shares remaining~~during the three and six months ended June 30, 2023.

NOTE 14. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss, net of tax, consisted of the following as of June 30, 2023 and December 31, 2022 (dollars in thousands):


	June 30, 2023		December 31, 2022
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $557 and $547, respectively	$	2,095	$	2,058

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The following table details the reclassifications out of accumulated other comprehensive loss to ~~be issued. No shares were issued under these agreements~~net income by component for the three and six months ended 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)	2023			2022			2023			2022
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (1)	$	(140	)	$	(200	)	$	(280	)	$	(400	)
Amortization of net loss (1)		1,177			1,809			2,549			3,847
Adjustment due to effects of regulation (1)		(1,061	)		(1,263	)		(2,316	)		(2,752	)
Total before tax (2)		(24	)		346			(47	)		695
Tax expense (2)		5			(73	)		10			(146	)
Net of tax (2)	$	(19	)	$	273		$	(37	)	$	549

(1)

These accumulated other comprehensive loss components are included in the ~~nine months ended September 30, 2017.~~

~~In the nine months ended September 30, 2017, Avista Corp. issued 0.2 million shares~~computation of ~~common stock, most of which were under employee incentive plans. The Company also issued a small number of shares under the 401(k) employee investment plan. Total~~ net ~~proceeds~~periodic pension cost (see Note 7 for ~~all issuances were $1.5 million.~~

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additional details).

~~AVISTA CORPORATION~~

(2)

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

NOTE ~~10.~~15. EARNINGS PER COMMON SHARE ~~ATTRIBUTABLE TO AVISTA CORP. SHAREHOLDERS~~

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


	Three months ended June 30,				Six months ended June 30,
	2023		2022		2023		2022
Numerator:
Net income	$	17,484	$	11,453	$	72,329	$	83,018
Denominator:
Weighted-average number of common shares outstanding-basic		75,983		72,624		75,576		72,205
Effect of dilutive securities:
Performance and restricted stock awards		148		34		127		89
Weighted-average number of common shares outstanding-diluted		76,131		72,658		75,703		72,294
Earnings per common share:
Basic	$	0.23	$	0.16	$	0.96	$	1.15
Diluted	$	0.23	$	0.16	$	0.96	$	1.15

Three months ended September 30, Nine months ended September 30,
2017 2016 2017 2016
Numerator:
Net income attributable to Avista Corp. shareholders $ 4,451
$ 12,234
$ 88,338
$ 97,137
Denominator:
Weighted-average number of common shares outstanding-basic 64,412
63,857
64,392
63,282
Effect of dilutive securities:
Performance and restricted stock awards 480
468
246
405
Weighted-average number of common shares outstanding-diluted 64,892
64,325
64,638
63,687
Earnings per common share attributable to Avista Corp. shareholders:
Basic $ 0.07
$ 0.19
$ 1.37
$ 1.53
Diluted $ 0.07
$ 0.19
$ 1.37
$ 1.53

There were no shares excluded from the calculation because they were antidilutive.

NOTE ~~11.~~16. 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~~will 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~~affecting Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.

~~California Refund Proceeding~~

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

In ~~February 2016, APX,~~August 2019, the Company was served with a ~~market maker~~complaint, captioned “State of Washington Department of Natural Resources v. Avista Corporation,” seeking recovery of up to $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 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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Avista Corp. was negligent in failing to identify and remove the tree before it came into contact with the line. Avista Corp. 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 were subsequently 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 ~~California Refund Proceedings in whose markets Avista Energy participated~~Superior Court of Ferry County, Washington. The Company continues to vigorously defend itself in the summer of 2000, asserted that Avista Energy and its other customer/participants may be responsible for a share of the disgorgement penalty APX may be found to owe to the California Parties (as defined in the 2016 Form 10-K). The penalty arises as a result of the Federal Energy and Regulatory Commission's (FERC) finding that APX committed violations in the California market in the summer of 2000. APX is making these assertions despite Avista Energy having been dismissed in FERC Opinion No. 536 from the on-going administrative proceeding at the FERC regarding potential wrongdoing in the California markets in the summer of 2000. APX has identified Avista Energy’s share of APX’s exposure to be as much as $16.0 million even though no wrongdoing allegations are specifically attributable to Avista Energy. Avista Energy believes its 2014 settlement with the California Parties insulates it from any such liability and that as a dismissed party it cannot be drawn back into the litigation. ~~Avista Energy intends to vigorously dispute APX’s assertions of indirect liability, but cannot~~However, at this time the Company is unable to predict the ~~eventual outcome.~~

~~Cabinet Gorge Total Dissolved Gas Abatement Plan~~

~~Dissolved atmospheric gas levels (referred to as "Total Dissolved Gas" or "TDG") in the Clark Fork River exceed state~~likelihood of Idaho and federal water quality numeric standards downstream of Cabinet Gorge particularly during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement (CFSA) as incorporated in Avista Corp.’s FERC license for the Clark Fork Project, Avista Corp. has worked in consultation with agencies, tribes and other stakeholders to address this issue. Under the terms of a gas supersaturation mitigation plan, Avista is reducing TDG by constructing spill crest modifications on spill gates at the dam, and the Company expects to continue spill crest modifications over the next several years, in ongoing consultation with key stakeholders. Avista Corp. cannot at this time predict thean adverse outcome or estimate a range of ~~costs associated with this contingency; however, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue.~~

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~~Fish Passage at Cabinet Gorge and Noxon Rapids~~

In 1999, the United States Fish and Wildlife Service (USFWS) listed bull trout as threatened under the Endangered Species Act. In 2010, the USFWS issued a revised designation of critical habitat for bull trout, which includes the lower Clark Fork River. The USFWS issued a final recovery plan in October 2015.

~~The CFSA describes programs intended to help restore bull trout populations~~potential loss in the ~~project area. Using~~event of such an outcome.

Road 11 Fire

In April 2022, Avista Corp. received a notice of claim from property owners seeking damages of $5 million in connection with a fire that occurred in Douglas County, Washington, in July 2020. In June 2022, those claimants filed suit in the ~~concept~~Superior Court of ~~adaptive management~~Douglas County, Washington, seeking unspecified damages. The fire, which was designated as the “Road 11 Fire,” occurred in the vicinity of an Avista Corp. 115kv line, resulting in damage to three overhead transmission structures. The fire occurred during a high wind event and ~~working closely with the USFWS, the Company evaluated the feasibility of fish passage at Cabinet Gorge and Noxon Rapids. The results of these studies led, in part,~~grew to the decision to move forward with development of permanent facilities, among other bull trout enhancement efforts. Parties to the CFSA have agreed to finalize the design of a fishway and plan its construction. Final design and construction costs are expected in late 2017 or early 2018.10,000 acres before being contained. The Company ~~believes its ongoing efforts through~~disputes that it is liable for the ~~CFSA continue to effectively address issues related to bull trout. Avista Corp. cannot~~fire and will vigorously defend itself in the pending legal proceeding; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of ~~costs associated~~potential loss in the event of such an outcome.

Labor Day 2020 Windstorm

General

In September 2020, a severe windstorm occurred in eastern Washington and northern Idaho. The extreme weather event resulted in customer outages and multiple wildfires in the region.

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); the Mile Marker 49 fire (near Orofino, Idaho); and the Kewa Field Fire (near Colville, Washington). These wildfires covered, in total, more than 25,000 acres. The Company estimates approximately 230 residential, commercial and other structures were impacted. With respect to the Christensen Road Fire, the Mile Marker 49 Fire, and the Kewa Field Fire, the Company’s investigation determined 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 determined that the Company's facilities were not involved in the ignition of this fire.

The Company’s investigation has found no evidence of negligence with ~~this contingency; however,~~respect to any of the fires, and the Company will ~~continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to fish passage at Cabinet Gorge and Noxon Rapids.~~

~~Legal Proceedings Related~~vigorously defend itself against any claims for damages that may be asserted against it with respect to the ~~Pending Acquisition by Hydro One~~

~~See Note 13 for information regarding the proposed acquisition~~wildfires arising out of the extreme wind event; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.

Babb Road Fire

In May 2021 the Company learned the Washington Department of Natural Resources (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

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•

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

~~In connection with~~ •

the ~~proposed acquisition, as~~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 ~~date~~tree from porcupines, a small area of ~~this quarterly~~scarring where a lateral branch/leader (LBL) had broken off in the past, and some past signs of Gall Rust disease.

The DNR report ~~three~~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.”

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 negligent with respect to its maintenance, inspection or vegetation management practices.

Nine lawsuits seeking unspecified damages have been filed in connection with the ~~United States District~~Babb Road fire. Asplundh Tree Company and CNUC Utility Consulting, which both perform vegetation management services as independent contractors to the Company, have since been added as additional defendants in each of the lawsuits. The lawsuits include six subrogation actions filed by insurance companies seeking recovery for amounts paid to insureds; two actions on behalf of individual plaintiffs; and a class action lawsuit. All proceedings were consolidated for discovery and pre-trial proceedings, are pending in the Superior Court ~~for~~of Spokane County Washington under the ~~Eastern District of Washington, captioned as follows:~~

~~Jenβ v. Avista Corporation., et al.,No. 2:17-cv-00333 (E.D. Wash.) (filed September 25, 2017);~~

~~Samuel~~lead action Blakely v. Avista Corporation et al.al., ~~No. 2:17-cv-00334 (E.D. Wash.) (filed~~and variously assert causes of action for negligence, private nuisance, trespass and inverse condemnation (a theory of strict liability).

On September ~~26, 2017); and~~

~~Sharpenter v. Avista Corporation., et al., No. 2:17-cv-00336 (E.D. Wash.) (filed September 26, 2017)~~

~~In addition one lawsuit has been~~16, 2022, the Company filed a motion in the Superior Court ~~for the State~~ of ~~Washington in and for~~ Spokane County, ~~captioned~~Washington, seeking dismissal of the Plaintiffs' inverse condemnation claims as ~~follows:~~

~~Fink v. Morris, et al.,~~ ~~No. 17203616-6 (filed September 15, 2017, amended complaint filed~~a matter of law on the grounds that they are not legally cognizable under Washington law. On October ~~25, 2017).~~

~~These lawsuits were filed against Avista Corporation, Hydro One Limited, Olympus Holding Corp.~~14, 2022, the Superior Court heard oral argument on that motion. The Court concluded the Company's motion involved mixed questions of law and ~~Olympus Corp.~~fact, and, as a consequence, could not be granted at that stage of the proceedings; however, the Court indicated the Company could bring the issue before the Court again after discovery is completed.

The Company will vigorously defend itself in the legal proceedings; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.

Colstrip

Colstrip Owners Arbitration and Litigation

Colstrip Units 3 and 4 are owned by the Company, PacifiCorp, Portland General Electric (PGE), and Puget Sound Energy (PSE) (collectively, the "Western Co-Owners"), as well as ~~all members of the Company's Board of Directors, namely Erik Anderson, Kristianne Blake, Donald Burke, Rebecca Klein, Scott Maw, Scott Morris, Marc Racicot, Heidi Stanley, John Taylor~~NorthWestern and ~~Janet Widmann, except that~~Talen Montana, LLC (Talen), as tenants in ~~Fink,~~ ~~Avista Corporation is not named~~common under an Ownership and ~~Bank of America Merrill Lynch is named~~Operating Agreement, dated May 6, 1981, as ~~a defendant, and~~amended (O&O Agreement), in the ~~Jen~~βpercentages set forth below:


Co-Owner	Unit 3			Unit 4
Avista		15	%		15	%
PacifiCorp		10	%		10	%
PGE		20	%		20	%
PSE		25	%		25	%
NorthWestern		—			30	%
Talen		30	%		—

Colstrip Units 1 and ~~Samuelson cases Hydro One Limited, Olympus Holding Corp.,~~2, owned by PSE and ~~Olympus Corp.~~Talen, were shut down in 2020 and are ~~not named~~in the process of being decommissioned. The co-owners of Units 3 and 4 also own undivided interests in facilities common to both Units 3 and 4, as ~~defendants.~~

well as in certain facilities common to all four Colstrip units.

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The ~~complaints generally allege,~~Washington Clean Energy Transformation Act (CETA), among other things, ~~that~~imposes deadlines by which each electric utility must eliminate from its electricity rates in Washington the ~~members~~costs and benefits associated with coal-fired resources, such as Colstrip. The practical impact of CETA is electricity from such resources, including Colstrip, may no longer be delivered to Washington retail customers after 2025.

The co-owners of Colstrip Units 3 and 4 have differing needs for the generating capacity of these units. Accordingly, certain business disagreements have arisen among the co-owners, including, disagreements as to the requirements for shutting down these units. NorthWestern has initiated arbitration pursuant to the O&O Agreement to resolve these business disagreements, and two actions have been initiated to compel arbitration of those disputes: one by Talen in the Montana Thirteenth Judicial District Court for Yellowstone County, and one by the Western Co-Owners, which is pending in Montana Federal District Court. In light of the ~~Board breached their fiduciary duties by, among other things, conducting~~ownership transfer agreements discussed below, the Colstrip owners agreed to stay both the litigation and the arbitration through September 29, 2023, at which time the proceedings would resume absent further agreement between the owners.

Agreement Between Talen Energy and Puget Sound Energy

In September 2022, the Company received notice that PSE and Talen entered into an ~~allegedly inadequate sale process~~agreement through which PSE has agreed to transfer its 25 percent ownership in Colstrip Units 3 and ~~agreeing~~4 to Talen at the end of 2025. The terms and conditions of the agreement are similar in most respects to the ~~acquisition at a price that allegedly undervalues~~NorthWestern Transaction discussed below.

Agreement Between Avista ~~Corporation,~~ and ~~that Hydro One Limited, Olympus Holding Corp.,~~NorthWestern

On January 16, 2023, the Company entered into an agreement with NorthWestern under which the Company will transfer its 15 percent ownership in Colstrip Units 3 and ~~Olympus Corp. aided and abetted those purported breaches of duty. The aiding and abetting claims in~~ ~~Fink and Sharpenter~~ ~~were brought only against Hydro One Limited, Olympus Holding Corp. and Olympus Corp. The complaints also allege misstatements and omissions of material facts~~4 to NorthWestern. There is no monetary exchange included in the ~~Company's proxy soliciting materials~~transaction. The transaction is scheduled to close on December 31, 2025 or such other date as the parties mutually agree upon.

Under the agreement, the Company will remain obligated through the close of the transaction to pay its share of (i) operating expenses, (ii) capital expenditures, but not in excess of the portion allocable pro rata to the portion of useful life (through 2030) expired through the close of the transaction, and (iii) except for certain costs relating to post-closing activities, site remediation expenses. In addition, the ~~special meeting~~Company would enter into an agreement under which it would retain its voting rights with respect to decisions relating to remediation.

The Company will retain its Colstrip transmission system assets, which are excluded from the transaction.

Under the Colstrip O&O Agreement, each of ~~shareholders~~the other owners of Colstrip has a 90-day period in which to ~~be held November 21, 2017~~evaluate the transaction and determine whether to ~~approve~~exercise their respective rights of first refusal as to a portion of the ~~acquisition.~~ generation being turned over to NorthWestern. That period was extended, by agreement of the Owners, through September 29, 2023.

The ~~complaints seek various remedies,~~transaction is subject to the satisfaction of customary closing conditions including ~~an injunction~~the receipt of any required regulatory approvals, as well as NorthWestern's ability to enter into a new coal supply agreement by December 31, 2024.

The Company does not expect this transaction to have a material impact on its financial results.

Burnett et al. v. Talen et al.

Multiple property owners initiated a legal proceeding (titled Burnett et al. v. Talen et al.) in the Montana District Court for Rosebud County against ~~the acquisition~~Talen, PSE, Pacificorp, PGE, Avista Corp., NorthWestern, and ~~monetary damages, including attorneys’ fees and expenses.~~

~~All defendants deny any wrongdoing~~Westmoreland Rosebud Mining. The plaintiffs allege a failure to contain coal dust in connection with the ~~proposed acquisition~~operation of Colstrip, and ~~plan to~~seek unspecified damages. The Company will vigorously defend ~~against all pending claims; however,~~itself in the ~~Company cannot~~litigation, but at this time is unable to predict the ~~eventual outcome.~~

~~Interest Rate Swaps included~~outcome, nor an amount or range of potential impact in the ~~2017 Washington General Rate Cases~~

~~On October 27, 2017, UTC Staff~~event of an outcome adverse to the Company’s interests.

Westmoreland Mine Permits

Two lawsuits have been commenced by the Montana Environmental Information Center and ~~other parties~~others, challenging certain permits relating to Avista Corp.'s electric and natural gas general rate cases filed their testimony. These parties recommended lower revenue requirements than what was proposed in Avista Corp.'s original filings. Additionally, the ~~UTC Staff recommended the disallowance~~operation of the ~~Washington portion~~Westmoreland Rosebud Mine, which provides coal to Colstrip. In the first, the Montana District Court for Rosebud County issued an order vacating a permit for one area of the ~~Company's 2016 settled interest rate swaps. The total amount of~~mine. In the ~~2016 settled interest rate swaps was $54.0 million, with approximately 60 percent of this total being allocated to Washington.~~

~~In addition to~~second, the settled interest rate swaps from 2016, the Company has a net regulatory asset of $8.8 million for interest rate swaps settled during the third quarter of 2017, and a net regulatory asset of $64.4 million for unsettled interest rate swaps as of September 30, 2017 related to forecasted debt issuances. Of those amounts, approximately 60 percent relate to Washington. If recovery of the 2016 settled interest rate swap payments referenced above is disallowed by the UTC, this could change the Company's current conclusion that settlement payments related to the 2017 settled interest rate swaps and the unsettled interest

Montana Federal District Court

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~~rate swaps are probable~~

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vacated a decision by the federal Office of ~~recovery through rates. If~~Surface Mining Reclamation and Enforcement approving expansion of the mine into a new area, pending further analysis of potential environmental impact. Both decisions have been appealed. Avista Corp. is not a party to either of these proceedings, but is continuing to monitor the progress of both lawsuits and assess the impact, if any, of the proceedings on Westmoreland’s ability to meet its contractual coal supply obligations.

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

In March 2017, the Company ~~concluded that recovery~~accessed property managed by the National Park Service (NPS) to prevent the imminent failure of ~~these swap related payments were no longer probable,~~a power pole 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 ~~would be required~~that it might seek recovery for unspecified costs and damages allegedly caused during the incident pursuant to ~~derecognize~~ the ~~related regulatory assets~~System Unit Resource Protection Act (SURPA), 54 U.S.C. 100721 et seq. In January 2021, the United States Department of Justice (DOJ) requested the Company and ~~liabilities~~the DOJ renew discussions relating to the matter. In July 2021, the DOJ communicated that it may seek damages of approximately $2 million in connection with ~~an adjustment through~~ the ~~income statement,~~incident for alleged damage to “natural and ~~any subsequent gains~~cultural resources”. In addition, the DOJ indicated that it may seek treble damages under the SURPA and ~~losses would be recognized through~~state law, bringing its total potential claim to approximately $6 million.

The Company disputes the ~~income statement rather than recorded as a regulatory asset or liability.~~

Interest rate swaps are a tool used throughout multiple industries to manage interest rate risk. They also provide certainty for future cash flows associated with future borrowings. Interest rate swap settlements have been included as a component of Avista Corp.’s cost of debt that has been approvedposition taken by the ~~UTC in past general rate cases. Accordingly,~~DOJ with respect to the ~~Company still believes~~incident, as well as the ~~interest rate swap payments are recoverable~~nature and extent of the DOJ’s alleged damages, and will ~~continue~~vigorously defend itself in any litigation that may arise with respect to ~~work through~~ the ~~rate case process; however,~~matter. The Company and the DOJ have engaged in 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 ~~these rate cases~~the matter.

Rathdrum, Idaho Natural Gas Incident

In October 2021, there was an incident in Rathdrum, Idaho involving the Company’s natural gas infrastructure. The incident occurred after a third party damaged those facilities during excavation work. The incident resulted in a fire which destroyed one residence and ~~whether~~resulted in minor injuries to the occupants. On January 23, 2023, the Company was served with a ~~disallowance will occur.~~

lawsuit filed in the District Court of Kootenai County, Idaho by one property owner, seeking unspecified damages. The Company intends to vigorously defend itself in this action.

Climate Commitment Act (CCA) Obligations

Effective January 1, 2023, the CCA went into effect in the State of Washington, requiring the Company to secure enough carbon allowances to cover its carbon emissions over a certain amount each year. The state has issued carbon allowances to cover electric retail sales. In May 2023, a model was approved for use in calculating the allowances needed for compliance which assumes hydroelectric generation is first used for wholesale sales, therefore reducing allowances required for wholesale sales. The Company expects to recover any costs incurred for its Washington operations through the ratemaking process.

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 1922 of the Notes to Consolidated Financial Statements" in the ~~2016~~2022 Form 10-K for additional discussion regarding other contingencies.

NOTE ~~12.~~17. INFORMATION BY BUSINESS SEGMENTS

The business segment presentation reflects the basis used by the Company's management to analyze performance and determine the allocation of resources. The Company's management evaluates performance based on income (loss) from operations before income taxes as well as net income (loss) ~~attributable to Avista Corp. shareholders.~~. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. Avista Utilities' business is managed based on the total regulated utility operation; 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

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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.

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, 2023:
Operating revenues	$	368,604		$	11,194		$	379,798		$	139		$	—		$	379,937
Resource costs		140,017			1,227			141,244			—			—			141,244
Other operating expenses		99,276			3,795			103,071			749			—			103,820
Depreciation and amortization		63,419			2,729			66,148			—			—			66,148
Income (loss) from operations		41,257			3,161			44,418			(610	)		—			43,808
Interest expense (2)		34,044			1,452			35,496			448			(318	)		35,626
Income taxes		(5,556	)		473			(5,083	)		(727	)		—			(5,810	)
Net income (loss)		18,810			1,359			20,169			(2,685	)		—			17,484
Capital expenditures (3)		121,834			4,422			126,256			—			—			126,256
For the three months ended June 30, 2022:
Operating revenues	$	368,515		$	9,906		$	378,421		$	145		$	—		$	378,566
Resource costs		156,221			1,176			157,397			—			—			157,397
Other operating expenses		100,782			3,700			104,482			2,910			—			107,392
Depreciation and amortization		60,106			2,700			62,806			30			—			62,836
Income (loss) from operations		25,037			2,041			27,078			(2,795	)		—			24,283
Interest expense (2)		27,078			1,487			28,565			137			(7	)		28,695
Income taxes		(2,565	)		(211	)		(2,776	)		1,777			—			(999	)
Net income		3,950			771			4,721			6,732			—			11,453
Capital expenditures (3)		111,850			2,809			114,659			342			—			115,001
For the six months ended June 30 2023:
Operating revenues	$	828,746		$	25,557		$	854,303		$	265		$	—		$	854,568
Resource costs		332,154			2,018			334,172			—			—			334,172
Other operating expenses		200,665			7,384			208,049			1,760			—			209,809
Depreciation and amortization		125,883			5,453			131,336			31			—			131,367
Income (loss) from operations		111,816			10,119			121,935			(1,526	)		—			120,409
Interest expense (2)		68,118			2,904			71,022			795			(536	)		71,281
Income taxes		(13,504	)		2,012			(11,492	)		(946	)		—			(12,438	)
Net income (loss)		70,437			5,401			75,838			(3,509	)		—			72,329
Capital expenditures (3)		219,598			7,148			226,746			3			—			226,749
For the six months ended June 30 2022:
Operating revenues	$	817,387		$	22,960		$	840,347		$	265		$	—		$	840,612
Resource costs		342,645			1,620			344,265			—			—			344,265
Other operating expenses		191,766			7,243			199,009			3,866			—			202,875
Depreciation and amortization		119,985			5,398			125,383			62			—			125,445
Income (loss) from operations		102,816			8,099			110,915			(3,663	)		—			107,252
Interest expense (2)		53,650			2,974			56,624			265			(10	)		56,879
Income taxes		(14,925	)		1,049			(13,876	)		2,041			—			(11,835	)
Net income		71,228			4,064			75,292			7,726		��	—			83,018
Capital expenditures (3)		207,314			3,332			210,646			756			—			211,402
Total Assets:
As of June 30, 2023:	$	6,929,611		$	270,774		$	7,200,385		$	189,314		$	(18,384	)	$	7,371,315
As of December 31, 2022:	$	6,976,164		$	264,322		$	7,240,486		$	187,027		$	(10,163	)	$	7,417,350

(1)

Intersegment eliminations reported as interest expense represent intercompany interest.

Avista
Utilities
Alaska Electric Light and Power Company Total Utility Other
Intersegment
Eliminations
(1)
Total
For the three months ended September 30, 2017:
Operating revenues $ 280,776
$ 10,864
$ 291,640
$ 5,456
$ —
$ 297,096
Resource costs 104,516
4,052
108,568
—
—
108,568
Other operating expenses (2) 81,045
3,469
84,514
6,598
—
91,112
Depreciation and amortization 41,516
1,452
42,968
137
—
43,105
Income (loss) from operations 31,023
1,298
32,321
(1,279 ) —
31,042
Interest expense (3) 23,132
895
24,027
215
(71 ) 24,171
Income taxes 5,972
44
6,016
(863 ) —
5,153
Net income (loss) attributable to Avista Corp. shareholders 5,419
427
5,846
(1,395 ) —
4,451
Capital expenditures (4) 109,066
1,073
110,139
1,050
—
111,189
(2)

Including interest expense to affiliated trusts.

(3)

32The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows.

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~~AVISTA CORPORATION~~

Avista
Utilities
Alaska Electric Light and Power Company Total Utility Other
Intersegment
Eliminations
(1)
Total
For the three months ended September 30, 2016:
Operating revenues $ 287,193
$ 9,796
$ 296,989
$ 6,360
$ —
$ 303,349
Resource costs 115,228
3,509
118,737
—
—
118,737
Other operating expenses 72,318
2,842
75,160
6,756
—
81,916
Depreciation and amortization 38,909
1,331
40,240
193
—
40,433
Income (loss) from operations 38,554
1,629
40,183
(589 ) —
39,594
Interest expense (3) 20,772
894
21,666
149
(19 ) 21,796
Income taxes 7,983
339
8,322
(716 ) —
7,606
Net income (loss) attributable to Avista Corp. shareholders 12,673
866
13,539
(1,305 ) —
12,234
Capital expenditures (4) 101,558
3,699
105,257
105
—
105,362
For the nine months ended September 30, 2017:
Operating revenues $ 992,904
$ 38,002
$ 1,030,906
$ 17,161
$ —
$ 1,048,067
Resource costs 366,590
10,315
376,905
—
—
376,905
Other operating expenses (2) 231,727
9,236
240,963
19,863
—
260,826
Depreciation and amortization 123,249
4,347
127,596
482
—
128,078
Income (loss) from operations 193,629
12,080
205,709
(3,184 ) —
202,525
Interest expense (3) 68,641
2,684
71,325
558
(112 ) 71,771
Income taxes 49,881
3,582
53,463
(1,915 ) —
51,548
Net income (loss) attributable to Avista Corp. shareholders 85,623
5,961
91,584
(3,246 ) —
88,338
Capital expenditures (4) 283,081
4,772
287,853
1,219
—
289,072
For the nine months ended September 30, 2016:
Operating revenues $ 989,981
$ 32,689
$ 1,022,670
$ 17,690
$ —
$ 1,040,360
Resource costs 380,913
9,358
390,271
—
—
390,271
Other operating expenses 221,364
8,241
229,605
18,862
—
248,467
Depreciation and amortization 115,126
3,984
119,110
573
—
119,683
Income (loss) from operations 199,661
9,354
209,015
(1,745 ) —
207,270
Interest expense (3) 61,652
2,684
64,336
459
(116 ) 64,679
Income taxes 53,004
2,910
55,914
(1,253 ) —
54,661
Net income (loss) attributable to Avista Corp. shareholders 94,431
4,885
99,316
(2,179 ) —
97,137
Capital expenditures (4) 274,041
14,031
288,072
270
—
288,342
Total Assets:
As of September 30, 2017: $ 5,116,059
$ 276,426
$ 5,392,485
$ 59,747
$ —
$ 5,452,232
As of December 31, 2016: $ 4,975,555
$ 273,770
$ 5,249,325
$ 60,430
$ —
$ 5,309,755


~~(1)~~	~~Intersegment eliminations reported as interest expense represent intercompany interest.~~


~~(2)~~	Other operating expenses for Avista Utilities for the three and nine months ended September 30, 2017 include acquisition costs of $6.7 million and $8.0 million, respectively, which are separately disclosed on the Condensed Consolidated Statements of Income.


~~(3)~~	~~Including interest expense to affiliated trusts.~~


~~(4)~~	~~The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows.~~

~~NOTE 13. PENDING ACQUISITION BY HYDRO ONE~~

On July 19, 2017, Avista Corp. entered into a Merger Agreement, by and among Hydro One, Olympus Holding Corp., a wholly owned subsidiary of Hydro One (US parent), and Olympus Corp., a wholly owned subsidiary of US parent (Merger Sub). Subject to the terms and conditions of the Merger Agreement, Merger Sub will be merged with and into Avista Corp. (the

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~~AVISTA CORPORATION~~

~~"Merger"), with Avista Corp. surviving as an indirect, wholly-owned subsidiary of Hydro One. Hydro One, based in Toronto, is Ontario’s largest electricity transmission and distribution provider.~~

At the effective time of the Merger, each share of Avista Corp. Common Stock issued and outstanding, other than Dissenting Shareholder Shares (as defined in the Merger Agreement) and shares of Avista Corp. Common Stock that are owned by Hydro One, US Parent or Merger Sub or any of their respective subsidiaries, will be converted automatically into the right to receive an amount in cash equal to $53.00, without interest.

Consummation of the Merger is subject to the satisfaction or waiver, if permissible under applicable law, of specified closing conditions, including, but not limited to, (i) the approval of the Merger by the holders of a majority of the outstanding shares of Avista Corp. Common Stock, (ii) the receipt of regulatory approvals required to consummate the Merger, including approval from the FERC, the Committee on Foreign Investment in the United States (CFIUS), the Federal Communications Commission (FCC), the UTC, IPUC, Public Service Commission of the State of Montana (MPSC), OPUC, and the RCA, and (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

On September 14, 2017, Avista Corp. and Hydro One filed applications for approval of the acquisition with the FERC, the UTC, the IPUC, the OPUC, the MPSC and the RCA, requesting approval of the transaction on or before August 14, 2018. However, the OPUC has set a procedural schedule with an end date no later than September 14, 2018.

As part of the applications for approval, Hydro One and Avista Corp. have proposed to flow through to Avista Corp.'s Washington, Idaho and Oregon retail customers, a rate credit totaling $31.5 million among the three jurisdictions over a 10-year period beginning at the time the Merger closes. In addition, to the extent Avista Corp. and Hydro One in a future rate proceeding demonstrate that cost savings, or benefits, directly related to the proposed transaction are already being flowed through to customers through base retail rates, the rate credit to customers would be reduced by an amount up to the $22.0 million over the 10-year period. The portion of the total rate credit that is not allowable for offset effectively represents acceptance by Hydro One of a lower rate of return during the 10-year period.

On October 2, 2017, the Company distributed the definitive proxy statement associated with a special meeting of shareholders to be held on November 21, 2017 to vote on the transaction. The transaction is expected to close in the second half of 2018 subject to all of the above referenced approvals and the satisfaction or waiver of other specified conditions.

The Merger Agreement also contains customary representations, warranties and covenants of Avista Corp., Hydro One, US Parent and Merger Sub. These covenants include, among others, an obligation on behalf of Avista Corp. to operate its business in the ordinary course until the Merger is consummated, subject to certain exceptions. In addition, the parties are required to use reasonable best efforts to obtain any required regulatory approvals.

Avista Corp. has made certain additional customary covenants, including, among others, and subject to certain exceptions, a customary non-solicitation covenant prohibiting Avista Corp. from soliciting, providing non-public information or entering into discussions or negotiations concerning proposals relating to alternative business combination transactions, except as and to the extent permitted under the Merger Agreement with respect to an unsolicited written Takeover Proposal (as defined in the Merger Agreement) made prior to the approval of the Merger by Avista Corp.'s shareholders if, among other things, Avista Corp.'s board of directors determines in good faith that such Takeover Proposal is or could be reasonably expected to lead to a Superior Proposal (as defined in the Merger Agreement) and that failure to take such actions would reasonably be expected to be inconsistent with its fiduciary duties under applicable law.

The Merger Agreement may be terminated by Avista Corp. and Hydro One by mutual consent and by either Avista Corp. or Hydro One under certain circumstances, including if the Merger is not consummated by September 30, 2018 (subject to an extension of up to six months by either party if all of the conditions to closing, other than the conditions related to obtaining required regulatory approvals, the absence of a law or injunction preventing the consummation of the Merger and the absence of a Burdensome Condition (as defined in the Merger Agreement) in any required regulatory approval, have been satisfied). The Merger Agreement also provides for certain additional termination rights for each of Avista Corp. and Hydro One. Upon termination of the Merger Agreement under certain specified circumstances, including (i) termination by Avista Corp. in order to enter into a definitive agreement with respect to a Superior Proposal, or (ii) termination by Hydro One following a withdrawal by Avista Corp.'s board or directors of its recommendation of the Merger Agreement, Avista Corp. will be required to pay Hydro One a termination fee of $103.0 million (Company Termination Fee). Avista Corp. will also be required to pay Hydro One the Company Termination Fee in the event Avista Corp. signs or consummates any specified alternative transaction within twelve months following the termination of the Merger Agreement under certain circumstances. In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals, the imposition of a Burdensome Condition with respect to a required regulatory approval, or the breach by Hydro One, US Parent or Merger Sub of their obligations in respect of obtaining regulatory approvals, Hydro One will be required to pay Avista Corp. a termination fee of $103.0 million.

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~~AVISTA CORPORATION~~

See Note 11 for discussion of shareholder lawsuits filed against the Company, the Company’s directors, Hydro One Limited, Olympus Holding Corp., and Olympus Corp. in relation to the Merger Agreement and the proposed Merger. See also the Company's Current Report on Form 8-K, filed with the SEC on July 19, 2017, and its definitive proxy statement relating to the special meeting of shareholders to approve the proposed transaction, filed with the SEC on October 2, 2017. The Merger Agreement was filed as Exhibit 2.1 to such Current Report.

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AVISTA CORPORATION

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors ~~and Shareholders~~ 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”~~"Company") as of ~~September~~June 30, ~~2017, and~~2023, the related condensed consolidated statements of income, ~~and~~ comprehensive income, equity for the three-month and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022, and ~~the related condensed consolidated statements~~ of ~~equity and~~ cash flows for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016. These~~2022 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 ~~statements are~~information for it to be in conformity with accounting principles generally accepted in the ~~responsibility~~United States of ~~the Company’s management.~~

America.

We ~~conducted our reviews~~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, 2022, 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 21, 2023, 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, 2022, 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 ~~Public Company Accounting Oversight Board (United States),~~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.

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Avista Corporation and subsidiaries as of December 31, 2016, and the related consolidated statements of income, comprehensive income, equity and redeemable noncontrolling interests, and cash flows for the year then ended (not presented herein); and in our report dated February 21, 2017, 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, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

~~Seattle, Washington~~

~~October 31, 2017~~

Portland, Oregon

August 1, 2023

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~~AVISTA CORPORATION~~

AVISTA CORPORATION

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~~was prepared in accordance with ~~GAAP~~the SEC’s Regulation S-K for interim financial information and with the instructions to Form 10-Q. ~~The interim~~This Management’s Discussion and Analysis of Financial Condition and Results of Operations does not contain the full detail or analysis, ~~which~~or the full discussion of trends and uncertainties, that would ~~be included in~~accompany financial statements for a full fiscal ~~year Form 10-K;~~year; therefore, it should be read in conjunction with the Company's ~~2016~~2022 Form 10-K.

Business Segments

Our business segments have not changed during the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2023. See the ~~2016~~2022 Form 10-K as well as “Note 1217 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.

The following table presents net income (loss) ~~attributable to Avista Corp. shareholders~~ for each of our business segments (and the other businesses) for the three and ~~nine~~six months ended ~~September~~June 30 (dollars in thousands):

Three months ended September 30, Nine months ended September 30,
2017 2016 2017 2016
Avista Utilities $ 5,419
$ 12,673
$ 85,623
$ 94,431
AEL&P 427
866
5,961
4,885
Other (1,395 ) (1,305 ) (3,246 ) (2,179 )
Net income attributable to Avista Corp. shareholders $ 4,451
$ 12,234
$ 88,338
$ 97,137


	Three months ended June 30,					Six months ended June 30,
	2023			2022		2023			2022
Avista Utilities	$	18,810		$	3,950	$	70,437		$	71,228
AEL&P		1,359			771		5,401			4,064
Other		(2,685	)		6,732		(3,509	)		7,726
Net income	$	17,484		$	11,453	$	72,329		$	83,018

Executive ~~Level Summary~~

Overview

Overall Results

Net income ~~attributable to Avista Corp. shareholders was $4.5 million~~ for the three months ended ~~September~~June 30, ~~2017, a decrease from $12.2 million for~~2023 increased compared to the three months ended ~~September~~June 30, ~~2016. Net income attributable to Avista Corp. shareholders was $88.3 million for the nine months ended September 30, 2017, a decrease from $97.1 million for the nine months ended September 30, 2016.~~

The decrease in earnings for both the third quarter and first nine months of 2017 was due to a decrease in earnings at Avista Utilities and an increase in losses at our other businesses (primarily during the first half of the year). There was also a decrease in earnings at AEL&P for the third quarter, but an increase in earnings for the first nine months of 2017.

~~Avista Utilities' earnings decreased for both the third quarter and year-to-date 2017 due to an increase in other operating expenses,~~2022, primarily due to ~~an increase in generation~~Avista Utilities results, including increased utility margin and ~~distribution maintenance costs, compensation costs, depreciation~~increased income tax benefits. Utility margin increased due to customer growth and ~~amortization and interest expense. As discussed below, our 2016 requests for~~the effect of general rate ~~increases~~cases, as well as decreased net costs under the ERM, which resulted in ~~Washington were denied, as was our 2017 Washington power cost rate adjustment; therefore, we are not receiving regulatory recovery of the increase~~a $1.0 million pre-tax benefit compared to a $4.8 million pre-tax expense in ~~expenses. In addition, there were also acquisition costs incurred during~~ the second ~~and third quarters~~quarter of 2017, which are not being passed through to customers. Further, since a majority of these acquisition costs are not deductible for income tax purposes, earnings reflect the full amount of such costs. The increase in costs was2022. These increases were partially offset by an increase in ~~gross~~interest expense, resulting from increased borrowings outstanding during the period as well as increased interest rates compared to the second quarter of 2022, as well as investment losses recorded by our other businesses compared to gains recorded in 2022.

Net income for the six months ended June 30, 2023 decreased compared to the six months ended June 30, 2022 primarily due to increased interest expense resulting from increased borrowings outstanding during the period as well as increased interest rates compared to the second quarter of 2022, as well as increased operating costs. We also recorded investment losses for our other businesses compared to gains recorded in 2022. These were partially offset by an increase in utility margin, ~~(operating revenues less resource costs) as a result~~resulting from customer growth and the effects of general rate ~~increases in Idaho and Oregon, customer growth and lower electric resource costs. See "Results of Operations – Overall – Non-GAAP Financial Measures" for further discussion of gross margin.~~

AEL&P earnings decreased for the third quarter 2017, but increased for the year-to-date 2017. For both the third quarter and year-to-date, there was an increase in revenue due to an interim general rate increase, higher electric loads and a slight increase in residential and commercial customers. During the third quarter 2017, there was a customer refund charge related to a settlement agreement in AEL&P's electric general rate case which mostly offset the revenue increase for the third quarter. There was also an increase in operating expenses for both the third quarter and year-to-date and a decrease in AFUDC and capitalized interest due to the construction of an additional back-up generation plant completed in 2016.

~~The increase in losses at our other businesses for the year-to-date 2017 was primarily related to renovation expenses and increased compliance costs at one of our subsidiaries.~~

cases.

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

~~Pending Acquisition by Hydro One~~

~~On July 19, 2017, Avista Corp. entered into~~summary.

2023 Hydroelectric Generation

In May and June of 2023, our region experienced historically high temperatures, causing the snowpack to melt more rapidly than expected. The quick runoff had a ~~Merger Agreement that provides~~significant negative impact on our hydrogeneration resources, resulting in this being one of our worst years for ~~Avista Corp.~~hydroelectric generation. As a result, we increased thermal generation and purchased power to ~~become an indirect, wholly-owned subsidiary of Hydro One. Subject~~compensate for the decrease in available hydroelectric generation, and our ability to optimize our generation assets has been limited compared to the ~~satisfaction or waiver of specified closing conditions, including approval by~~

opportunities we had originally anticipated for the year. The decreased hydroelectric generation availability compared to our expectations has a significant impact on the ERM in Washington, as well as our financial results.

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~~AVISTA CORPORATION~~

~~regulatory agencies~~

AVISTA CORPORATION

Washington Climate Commitment Act (CCA)

Effective January 1, 2023, the CCA went into effect in the State of Washington, requiring us to secure enough carbon allowances to cover our carbon emissions over a certain amount each year. See "Environmental Issues and ~~Avista Corp. shareholders, the transaction is expected to close during the second half of 2018. At the effective time~~Contingencies" below for further discussion of the ~~Merger, each share~~CCA and expected impacts to our financial results.

Inflation

Although we continue to experience inflationary pressures in multiple areas of ~~Avista Corp. Common Stock issued~~our business, inflation has eased considerably compared to the same period last year. Nevertheless, inflation remains above the Federal Reserve's target and ~~outstanding other~~we cannot estimate how long inflation will remain at elevated levels. In addition, our interest costs increased due to higher interest rates than ~~Dissenting Shareholder Shares (as defined~~those approved in our most recent general rate cases, resulting in increased interest expense.

Regulatory Lag

Regulatory “lag” is inherent in utility ratemaking; a result of the delay between the investment in utility plant and/or the increase in costs and the receipt of an order of a public utility commission authorizing an increase in rates sufficient to recover such investment or costs. Regulatory lag can be mitigated to some extent by the incorporation of reasonably expected forward-looking information into an authorization of increased rates. However, there is no protection against unexpected inflation and increased interest rates, as experienced in 2022 and which are continuing into 2023. While we believe our recent general rate settlements are helpful, some increases in our operating expenses and interest costs will have to be addressed in future rate cases. See “Regulatory Matters” for additional discussion of the general rate cases.

Climate Change

There is a trend of increasing average temperatures that has had, and will likely continue to have, various direct and indirect impacts on our business. Direct impacts include, without limitation, variations in the ~~Merger Agreement)~~amount and ~~shares~~timing of ~~Avista Corp. Common Stock~~energy demand throughout the year, variations in the level and timing of precipitation throughout the year and the resulting impact on the availability of hydroelectric resources at times of peak demand. Indirect impacts include, without limitation, federal, state and local legislation or regulation (in effect and proposed) that ~~are owned by Hydro One, US Parent or Merger Sub or any~~limits (or eliminates) the use of ~~their respective subsidiaries, will be converted automatically into~~fossil-fuel for electric generation, as well as the ~~right~~use of natural gas for heating in residential and commercial buildings.

For additional information regarding climate change, effects of climate change on our operations and results of operations and legislation and regulation designed to ~~receive an amount in cash equal to $53.00, without interest. For further information,~~mitigate climate change, see ~~“Notes 11~~"Environmental Issuance and ~~13 of the Notes to Condensed Consolidated Financial Statements.”~~

Contingencies" and our 2022 Form 10-K.

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.

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 CORPORATION

Avista Utilities

Washington General Rate Cases

~~2015~~

2022 General Rate Cases

~~In January 2016, we received~~

On December 12, 2022, the WUTC issued an order ~~(Order 05) that concluded our electric~~approving the multi-party settlement agreement filed in June 2022. The parties to the settlement agreement included, in addition to us, the Staff of the WUTC, the Alliance of Western Energy Consumers, the NW Energy Coalition, The Energy Project, Walmart, Small Business Utility Advocates and ~~natural gas general rate cases that were originally filed with the UTC in February 2015. New electric and natural gas rates were effective on January 11, 2016.~~

Sierra Club. The UTC-approved rates were designed to provide a 1.6 percent, or $8.1 million decrease in electric base revenue, and a 7.4 percent, or $10.8 million increase in natural gas base revenue. The UTC also approved a rate of return (ROR) on rate base of 7.29 percent, with a common equity ratio of 48.5 percent and a 9.5 percent return on equity (ROE).

~~UTC Order Denying Industrial Customers of Northwest Utilities / Public Counsel Joint Motion for Clarification, UTC Staff Motion to Reconsider and UTC Staff Motion to Reopen Record~~

~~On January 19, 2016, the Industrial Customers of Northwest Utilities (ICNU) and the~~ Public Counsel Unit of the Washington ~~State~~Attorney General’s Office (Public Counsel), while a party to the rate cases, did not join in the settlement agreement. The settlement agreement was reached after negotiation of all issues but is “results-focused” -- that is, it represents agreement among all parties (except Public Counsel) as to our overall revenue requirement, without specifying the details of any component except the rate of return on rate base.

The approved rates were designed to increase annual base electric revenues by $38.0 million (or 6.9 percent), effective in December 2022, and $12.5 million (or 2.1 percent), effective in December 2023. The approved rates were also designed to increase annual base natural gas revenues by $7.5 million (or 6.5 percent), effective in December 2022, and $1.5 million (or 1.2 percent), effective in December 2023.

To mitigate the overall impact of the Attorney General (PC) filed a Joint Motion for Clarification with the UTC. In the Motion for Clarification, ICNU and PC requested that the UTC clarify the calculation of the electric attrition adjustment and the end-result revenue ~~decrease of $8.1 million. ICNU and PC provided their own calculations in their Motion, and suggested that the revenue decrease should have been $19.8 million based~~increases on ~~their reading of the UTC’s Order.~~

On January 19, 2016, the UTC Staff, which is a separate party in the general rate case proceedings from the UTC Advisory Staff, filed a Motion to Reconsider with the UTC. In its Motion to Reconsider, the Staff provided calculations and explanations that suggested that the electric revenue decrease should have been a revenue decrease of $27.4 million instead of $8.1 million, based on its reading of the UTC's Order. Further, on February 4, 2016, the UTC Staff filed a Motion to Reopen Record for the Limited Purpose of Receiving into Evidence Instruction on Use and Application of Staff’s Attrition Model, and sought to supplement the record “to incorporate all aspects of the Company’s Power Cost Update.” Within this Motion, UTC Staff updated its suggested electric revenue decrease to $19.6 million.

~~None of the parties in their Motions raised issues with the UTC’s decision on the natural gas revenue increase of $10.8 million.~~

~~On February 19, 2016, the UTC issued an order (Order 06) denying the Motions summarized above and affirming Order 05, including an $8.1 million decrease in electric base revenue.~~

~~PC Petition for Judicial Review~~

On March 18, 2016, PC filed in Thurston County Superior Court a Petition for Judicial Review of the UTC's Order 05 and Order 06 described above that concluded our 2015 electric and natural gas general rate cases. In its Petition for Judicial Review, PC seeks judicial review of five aspects of Order 05 and Order 06, alleging, among other things, that

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(1) the UTC exceeded its statutory authority by setting rates for our natural gas and electric services based on amounts for utility plant and facilities that are not "used and useful" in providing utility service to customers; (2) the UTC acted arbitrarily and capriciously in granting an attrition adjustment for our electric operations after finding that thecustomers, we did not meet the newly articulated standard regarding attrition adjustments; (3) the UTC erred in applying the "end results test" to set rates for our electric operations that are not supported by the record; (4) the UTC did not correct its calculation of our electric rates after significant errors were brought to its attention; and (5) the UTC's calculation of our electric rates lacks substantial evidence.

PC is requesting that the Court (1) vacate or set aside portions of the UTC’s orders; (2) identify the errors contained in the UTC’s orders; (3) find that the rates approved in Order 05 and reaffirmed in Order 06 are unlawful and not fair, just and reasonable; (4) remand the matter to the UTC for further proceedings consistent with these rulings, including a determination of our revenue requirement for electric and natural gas services; and (5) find the customers are entitled to a refund.

On April 18, 2016, PC filed an application with the Thurston County Superior Court to certify this matter for review directly by the Court of Appeals, an intermediate appellate court in the State of Washington. The matter was certified on April 29, 2016 and accepted by the Court of Appeals on July 29, 2016. The parties provide briefs to the Court, after which the Court will set the matter for argument. On July 7, 2017, ICNU filed a brief in support of PC and the UTC and Avista Corp. responded. Oral argument was held on October 24, 2017 before the court. A decision from the Court is not expected until late 2017, at the earliest.

In its brief to the Court, the UTC, while defending the use of its attrition adjustment nevertheless requested a partial remand back to the UTC to reevaluate the implementation of our power cost update asoffset part of the ~~general~~2022 base rate ~~case~~request with tax customer credits. The total estimated benefits of these credits, $27.6 million for electric customers and $12.5 million for natural gas customers, will be returned over a two-year period from December 2022 to December 2024.

In addition, the order approved a separate tracking mechanism and tariff for purposes of recovering existing and prospective Colstrip costs.

The WUTC approved an ROR on ~~appeal, doing so by means~~rate base of ~~a supplemental evidentiary hearing. The power~~7.03 percent, but the settlement does not specify an explicit ROE, cost ~~update at issue represents approximately $12.0 million~~ of ~~costs.~~

The new rates established by Order 05 will continue in effect while the Petition for Judicial Review is being considered. We believe the UTC's Order 05 and Order 06 finalizing the electric and natural gasdebt or capital structure.

These general rate cases ~~provide~~require a ~~reasonable end result for all parties. If the outcome~~subsequent review of ~~the judicial review were to result~~capital projects included in ~~an electric rate reduction greater than the decrease ordered by the UTC, it may result in~~rates and a refund ~~liability to customers~~ of ~~up to $9.5 million, which is net of an approximately $2.5 million refund for Washington electric customers~~revenues related to ~~the 2016 provision for earnings sharing that we have already accrued.~~

~~2016~~imprudent expenditures or those not used and useful.

2024 General Rate Cases

~~On December 15, 2016, the UTC issued an order related~~

The Company expects to ~~our~~file its next Washington electric and natural gas general rate cases that were originally filed with the UTC in February 2016. The UTC order denied the Company's proposed electric and natural gas rate increase requests of $38.6 million and $4.4 million, respectively. Accordingly, our current electric and natural gas retail rates remained unchanged in Washington State, following the order.

~~Our original requests were based on a proposed ROR of 7.64 percent with a common equity ratio of 48.5 percent and a 9.9 percent ROE.~~

We determined that an appeal of the UTC’s decision to the courts would involve a significant amount of uncertainty regarding the level of success of such an appeal, as well as the timing of any value that might come following a process that would take between one and two years. The Company believes greater long-term value can be achieved through focusing on new general rate cases than through appealing the UTC's decision in the ~~courts.~~

~~2017~~first quarter of 2024.

Idaho General Rate Cases

~~On May 26, 2017,~~

2023 General Rate Cases

In February 2023, we filed two requests with the UTC to recover costs related to power supply and operating costs as well as capital investments made since the last determination of our rate base in the 2015 Washington general rate cases.

~~The two filings are summarized as follows:~~

~~Power Cost Rate Adjustment~~

The first filing was an electric only power cost rate adjustment (PCRA) that was designed to update and reset power supply costs, effective September 1, 2017. We requested an overall increase in billed electric rates of 2.9 percent (designed to increase annual electric revenues by $15.0 million). On August 10, 2017, the PCRA filing was dismissed by the UTC.

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Our power supply costs, on a normalized basis, are much higher than those built into current base retail rates. The increased level of costs are included in our pending general rate case in Washington, which is scheduled to be concluded by April 26, 2018. The dismissal of the PCRA by the UTC does not impact our general rate requests discussed below.

~~General Rate Requests~~

The second request relates to electric and natural gas general rate cases. We filed three-year rate plans for electric and natural gas and have requested the following for each year (dollars in millions):

Electric Natural Gas
Effective Date Proposed Revenue
Increase Proposed Base
Rate Increase
Proposed Revenue
Increase

Proposed Base
Rate Increase
May 1, 2018 $ 61.4
12.5 % $ 8.3
9.3 %
May 1, 2019 (1) $ 14.0
2.5 % $ 4.2
4.4 %
May 1, 2020 (1) $ 14.4
2.5 % $ 4.4
4.4 %


~~(1)~~	As a part of the electric rate plan, we have proposed to update power supply costs through a Power Supply Update, the effects of which would also go into effect on May 1, 2019 and May 1, 2020. The requested revenue increases for 2019 and 2020 do not include any power supply adjustments.

~~Our request is based on a proposed ROR of 7.76 percent with a common equity ratio of 50.0 percent and a 9.9 percent ROE.~~

~~As a part of the three-year rate plan, if approved, we would not file another general rate case until June 1, 2020, with new rates effective no earlier than May 1, 2021.~~

The major drivers of these general rate case requests is to recover the costs associated with our capital investments to replace infrastructure that has reached the end of its useful life, as well as respond to the need for reliability and technology investments required to maintain our integrated energy services grid. Among the capital investments included in the filings are:

~~Major hydroelectric investments at the Little Falls and Nine Mile hydroelectric plants.~~

~~Generator maintenance at the Kettle Falls biomass plant that will ensure efficient generation and operations.~~

The ongoing project to systematically replace portions of natural gas distribution pipe in our service area that were installed prior to 1987, as well as replacement of other natural gas service equipment.

~~Transmission and distribution system and asset maintenance, such as wood pole replacements, feeder upgrades, and substation and transmission line rebuilds to maintain reliability for our customers.~~

~~Technology upgrades that support necessary business processes and operational efficiencies that allow us to effectively manage the utility and serve customers.~~

~~A refresh of the customer-facing website, providing relevant information, greater accessibility on mobile devices, easier navigation, and a streamlined payment experience.~~

~~The UTC has up to 11 months to review the general rate case filings and issue a decision, which is scheduled to be concluded by April 26, 2018.~~

~~On October 27, 2017, UTC Staff and other parties to our~~multiyear electric and natural gas general rate cases ~~filed their testimony. These parties recommended lower revenue requirements than what was proposed in our original filings. Additionally,~~with the UTC Staff recommended the disallowance of the Washington portion of our 2016 settled interest rate swaps. The total amount of the 2016 settled interest rate swaps was $54.0 million, with approximately 60 percent of this total being allocated to Washington.

IPUC.

In ~~addition to the settled interest rate swaps from 2016,~~June 2023, we have a net regulatory asset of $8.8 million for interest rate swaps settled during the third quarter of 2017, and a net regulatory asset of $64.4 million for unsettled interest rate swaps as of September 30, 2017 related to forecasted debt issuances. Of those amounts, approximately 60 percent relate to Washington. If recovery of the 2016 settled interest rate swap payments referenced above is disallowed by the UTC, this could change our current conclusion that settlement payments related to the 2017 settled interest rate swaps and the unsettled interest rate swaps are probable of recovery through rates. If we concluded that recovery of these swap related payments were no longer probable, we would be required to derecognize the related regulatory assets and liabilities

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~~with an adjustment through the income statement, and any subsequent gains and losses would be recognized through the income statement rather than recorded as a regulatory asset or liability.~~

~~Idaho General Rate Cases~~

~~2016 General Rate Case~~

~~In December 2016, the IPUC approved~~reached a settlement agreement ~~between us~~with the Staff of the IPUC, Clearwater Paper Corporation, Idaho Forest Group, LLC and ~~other parties in our electric general~~Walmart Inc. The remaining joint party, Idaho Conservation League / NW Energy Coalition, did not join the settlement, but takes issue only with one rate ~~case, concluding our Idaho electric general rate case originally filed in May 2016. New~~design component that does not impact the proposed revenue requirement.

The proposed rates ~~took effect on January 1, 2017~~ under the settlement ~~agreement. We did not file a natural gas general rate case in 2016.~~

~~The settlement~~ agreement ~~increased annual electric base rates by 2.6 percent (designed~~are designed to increase annual base electric revenues by ~~$6.3 million).~~ $22.1 million, or 8.0 percent, effective in September 2023, and $4.3 million, or 1.4 percent, effective in September 2024. The agreement is also designed to increase annual base natural gas revenues by $1.3 million, or 2.7 percent, effective September 2023, and a negligible increase effective September 2024.

The settlement ~~revenue increase is~~contemplates a return on equity of 9.4 percent, based on ~~a ROR of 7.58 percent with~~ a common equity ratio of 50 percent, and a ~~9.5 percent ROE.~~

~~In addition~~rate of return on rate base of 7.19 percent.

Ongoing capital infrastructure investment (including replacement of wood poles and natural gas distribution pipe, continued investment in the wildfire resiliency plan, and technology) is the main driver of the proposed increases.

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The IPUC has up to nine months from the ~~agreed upon increase in electric revenues~~date of the original filing to recover costs primarily driven by our increased capital investments in infrastructure to serve customers, the settlement agreement includes the continued recovery of approximately $4.1 million in costs related to the Palouse Wind Project through the Power Cost Adjustment (PCA) mechanism rather than through base rates.

~~2017~~review and issue a decision.

Oregon General Rate Cases

~~On October 20, 2017,~~

2023 General Rate Case

In March 2023, we ~~reached~~filed a ~~settlement agreement with multiple parties to our electric and~~ natural gas general rate ~~cases that has been submitted to~~case with the ~~IPUC for its consideration.~~OPUC. If approved, new rates would be effective on January 1, 2024.

In May 2023, we, along with the OPUC staff and the alliance of Western Energy Consumers reached a partial settlement agreement, agreeing to a ROR of 7.24 percent, an ROE of 9.5 percent, and a common equity ratio of 50 percent.

After incorporating the settlement agreement, the proposed increase in annual base natural gas revenues still subject to further regulatory process is $9.4 million (or 12.3 percent).

Ongoing capital infrastructure investment (including replacement and expansion of natural gas distribution pipe and technology) is the main driver of the proposed increase.

The OPUC has up to ten months from the date of the original filing to review and issue a decision.

AEL&P

Alaska General Rate Case

In July 2022, AEL&P filed an electric general rate case with the Regulatory Commission of Alaska (RCA). AEL&P received approval in August 2022 for an interim base rate increase of 4.5 percent (designed to increase annual electric revenues by $1.6 million), which took effect in September 2022. AEL&P also requested a permanent base rate increase of an additional 4.5 percent (designed to increase annual electric revenues by $1.6 million), which, if approved, could take effect ~~January 1, 2018 and January 1, 2019.~~

in October 2023. The settlement agreement is a two-year rate plan and if approved, will have the following electric and natural gas base rate changes each year, which are designed to result in the following increases in revenues (dollars in millions):

Electric Natural Gas
Effective Date Revenue
Increase Base
Rate Increase
Revenue
Increase

Base
Rate Increase
January 1, 2018 $ 12.9
5.2 % $ 1.2
2.9 %
January 1, 2019 $ 4.5
1.9 % $ 1.1
2.7 %

~~The settlement agreement~~proposed revenue increase request is based on a ~~ROR of 7.61~~13.45 percent ROE with a common equity ratio of ~~50.0~~60.7 percent and a ~~9.5 percent ROE.~~

~~As a part of the two-year rate plan, if approved, the Company would not file a new general rate case for a new rate plan to be effective prior to January 1, 2020.~~

~~The Company's original request was a two-year rate plan and requested the following electric and natural gas base rate changes each year (dollars in millions):~~

Electric Natural Gas
Effective Date Proposed Revenue
Increase Proposed Base
Rate Increase Proposed Revenue
Increase Proposed Base
Rate Increase
January 1, 2018 $ 18.6
7.5 % $ 3.5
8.8 %
January 1, 2019 $ 9.9
3.7 % $ 2.1
5.0 %

~~The original requests were based on a proposed~~ ROR of ~~7.81 percent with a common equity ratio of 50.0 percent and a 9.9 percent ROE.~~

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~~Oregon General Rate Cases~~

~~2015 General Rate Case~~

~~On February 29, 2016, the OPUC issued a preliminary order (and a final order~~10.0 percent.

The RCA must rule on ~~March~~permanent rate increases within 450 days (approximately 15 2016) concluding our natural gas general rate case, which was originally filed with the OPUC in May 2015. The OPUC order approved rates designed to increase overall billed natural gas rates by 4.9 percent (designed to increase annual natural gas revenues by $4.5 million). New rates went into effect on March 1, 2016. The final OPUC order incorporated two partial settlement agreements which were entered into during November 2015 and January 2016.

~~The OPUC order provides for an overall authorized ROR of 7.46 percent with a common equity ratio of 50 percent and a 9.4 percent ROE.~~

The November 2015 partial settlement agreement, approved by the OPUC, included a provision for the implementation of a decoupling mechanism, similar to the Washington and Idaho mechanisms described below. See further description and a summary of the balances recorded under this mechanism below.

~~2016 General Rate Case~~

~~On September 13, 2017, the OPUC approved an all-party settlement agreement that was filed with the OPUC in May 2017, which resolved all issues in the case.~~

The OPUC approved rates designed to increase annual base revenues by 5.9 percent or $3.5 million. A rate adjustment of $2.6 million became effective October 1, 2017, and a second adjustment of $0.9 million will be effective November 1, 2017 to cover specific capital projects identified in the settlement agreement, which were completed in October.

~~In addition, in the settlement agreement, we agreed to non-recovery of certain utility plant expenditures, which resulted in a write-off of approximately $0.8 million in the second quarter of 2017.~~

~~The settlement agreement reflects a 7.35 ROR with a common equity ratio of 50 percent and a 9.4 percent ROE.~~

~~AMI Project~~

In March 2016, the UTC granted our Petition for an Accounting Order to defer and include in a regulatory asset the undepreciated value of our existing Washington electric meters for the opportunity for later recovery. This accounting treatment is related to our plans to replace approximately 253,000 of our existing electric meters with new two-way digital meters and the related software and support services through our AMI project in Washington State. Replacement of the meters is expected to begin in the second half of 2018. As of September 30, 2017, the estimated undepreciated value for the existing meters is $20.1 million.

In May 2017, we filed a Petition with the UTC requesting deferred accounting treatment for the investment costs associated with the Washington AMI project, including components such as meter communication networks, information management systems and natural gas ERTs. The Petition requested the deferral and inclusion in a regulatory asset of all AMI investment costs over the multi-year implementation period, until the costs could be reviewed for prudence in a future regulatory proceeding and recovered in retail rates. Through discussions with UTC staff, we developed an alternative proposal to our original Petition and on September 14, 2017, the UTC approved our alternative proposal to defer the depreciation expense associated with AMI, along with a carrying charge, and to seek recovery of the deferral and carrying charge in a future general rate case. Cost savings, such as reduced meter reading costs, will occur during the implementation period which will offset a portion of the AMI costs not being deferred.

In May 2017, we filed Petitions with the IPUC and the OPUC requesting a depreciable life of 12.5 years for the meter data management system (MDM) related to the AMI project and both the IPUC and the OPUC approved the depreciable life. In addition, in connection with the recently filed Idaho electric general rate case settlement (discussed below), the settling parties agreed to cost recovery of Idaho's share of the MDM system, effective January 1, 2019. In connection with the approval of the Oregon general rate case settlement (discussed below), the OPUC approved cost recovery of Oregon's share of the MDM system, effective in base rates on November 1, 2017.

~~Alaska Electric Light and Power Company~~

~~Alaska General Rate Case~~

In October 2017, AEL&P filed an all-party settlement agreement with the RCA related to its electric general rate case, which was originally filed in September 2016. If approved by the RCA, the settlement agreement is designed to increase base electric revenue by 3.86 percent or $1.3 million.

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In September 2016, when AEL&P filed its original electric general rate case, it was granted a refundable interim base rate increase of 3.86 percent (designed to increase electric revenues by $1.3 million), which took effect in November 2016. If the settlement agreement is approved by the RCA, these rates will become permanent.

~~In addition, in the settlement agreement, AEL&P agreed to retain $0.9 million less revenue~~months) from the ~~Greens Creek Mine than what was included in the original general rate case request. As such, during the third quarter~~date of 2017, AEL&P recorded a refund liability to customers of $0.8 million, which will be refunded to customers during 2018. The amount of revenue from Greens Creek Mine that is retained by AEL&P is used to offset revenue requirements that would otherwise be required from retail customers.

~~The settlement agreement reflects an 8.91 ROR with a common equity ratio of 58.18 percent and an 11.95 percent ROE.~~

filing.

Avista Utilities

Purchased Gas Adjustments

PGAs are designed to pass through changes in natural gas costs to ~~Avista Utilities'~~ customers with no change in ~~gross~~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 ~~a liability~~assets of ~~$34.4~~$84.0 million and $52.1 million as of ~~September~~June 30, ~~2017~~2023 and ~~a liability of $30.8 million as of~~ December 31, ~~2016. These balances represent amounts due to customers.~~

2022, 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 the margin on wholesale sales of energy and sales of fuel, and the amount included in base retail rates for our Washington ~~customers and defer these differences (over the $4.0 million deadband and sharing bands) for future surcharge or rebate to~~ customers. See the ~~2016~~2022 Form 10-K for a full discussion of the mechanics of the ERM and the various customer/Company sharing bands. Total net deferred power costs under the ERM ~~was a liability~~were assets of ~~$21.9~~$33.3 million and $30.5 million as of ~~September~~June 30, ~~2017, compared to a liability of $21.3 million as of~~2023 and December 31, ~~2016.~~2022, respectively. These deferred power cost balances represent amounts due from 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.

~~Avista Utilities has~~ In June 2023, we received approval from the WUTC for a rate surcharge to customers over a two-year period, commencing July 1, 2023.

The 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 for future surcharge or rebate to~~ 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 ~~a liability~~assets of ~~$5.9~~$16.7 million and $16.3 million as of ~~September~~June 30, ~~2017~~2023 and ~~a liability of $2.2 million as of~~ December 31, ~~2016.~~2022, respectively. These deferred power cost balances represent amounts due tofrom customers.

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Decoupling ~~and Earnings Sharing~~ 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 ~~Avista Utilities'~~our jurisdictions, ~~each month 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 ~~the~~ residential and certain commercial customer classes are included in our decoupling ~~mechanisms described below.~~

~~Washington Decoupling and Earnings Sharing Mechanisms~~

~~In Washington,~~mechanisms. See the ~~UTC approved our decoupling mechanisms for electric and natural gas~~2022 Form 10-K for a five-year period beginning January 1, 2015. Electric and natural gas decoupling surcharge rate adjustments to customers are limited to a 3 percent increase on an annual basis, with any remaining surcharge balance carried forward for recovery in a future period. There is no limit on the level of rebate rate adjustments.

The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations are made for the calendar year just ended. These earnings tests reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. The operationdiscussion of the ~~Washington~~mechanisms in each jurisdiction.

Total net cumulative decoupling deferrals among all jurisdictions were regulatory liabilities of $32.6 million as of June 30, 2023 and earnings sharing mechanisms has not changed for the nine months ended September 30, 2017. These decoupling and earnings sharing mechanisms are more fully described in the 2016 Form 10-K. See below for a summary$18.2 million as of ~~cumulative balances under the decoupling and earnings sharing mechanisms.~~

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~~Idaho Fixed Cost Adjustment (FCA) and Earnings Sharing Mechanisms~~

In Idaho, the IPUC approved the implementation of FCAs for electric and natural gas (similar in operation and effect to the Washington decoupling mechanisms) for an initial term of three years, beginning January 1, 2016.

For the period 2013 through 2015, we had an after-the-fact earnings test such that if Avista Corp., on a consolidated basis for electric and natural gas operations in Idaho, earned more than a 9.8 percent ROE, we were required to share with customers 50 percent of any earnings above the 9.8 percent. This after-the-fact earnings test was discontinued, effective January 1, 2016, as part of the settlement of our 2015 Idaho electric and natural gas general rates cases. See below for a summary of cumulative balances under the decoupling and earnings sharing mechanisms.

~~Oregon Decoupling Mechanism~~

In February 2016, the OPUC approved the implementation of a decoupling mechanism for natural gas, similar to the Washington and Idaho mechanisms described above. The decoupling mechanism became effective on March 1, 2016. There will be an opportunity for interested parties to review the mechanism and recommend changes, if any, by September 2019. An earnings review is conducted on an annual basis, which is filed by us with the OPUC on or before June 1 of each year for the prior calendar year. In the annual earnings review, if we earn more than 100 basis points above our allowed return on equity, one-third of the earnings above the 100 basis points would be deferred and later returned to customers. See below for a summary of cumulative balances under the decoupling and earnings sharing mechanisms.

~~Cumulative Decoupling and Earnings Sharing Mechanism Balances~~

~~As of September 30, 2017 and~~ December 31, ~~2016, we had the following cumulative balances outstanding related~~2022. Decoupling regulatory liabilities represent amounts due to ~~decoupling and earnings sharing mechanisms in our various jurisdictions (dollars in thousands):~~

September 30, December 31,
2017 2016
Washington
Decoupling surcharge (1) $ 14,783
$ 30,408
Provision for earnings sharing rebate (1) (800 ) (5,113 )
Idaho
Decoupling surcharge $ 5,410
$ 8,292
Provision for earnings sharing rebate (3,064 ) (5,184 )
Oregon
Decoupling surcharge $ 335
$ 2,021


~~(1)~~	When we make our annual decoupling regulatory filing, typically during the third quarter, we apply the balance of the provision for earnings sharing rebate for the relevant time period to either offset the decoupling surcharge balance, or increase the decoupling rebate balance.

customers.

See "Results of Operations - Avista Utilities" for further discussion of the amounts recorded to operating revenues in ~~2017~~2023 and ~~2016~~2022 related to the decoupling ~~and earnings sharing~~ 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 ~~September~~June 30, ~~2017~~2023 compared to the three months ended ~~September~~June 30, ~~2016~~

2022

The following graph shows the total change in net income ~~attributable to Avista Corp. shareholders~~ for the ~~third~~second quarter of ~~2016~~2023 compared to the ~~third~~second quarter of ~~2017,~~2022, as well as the various factors that caused such change (dollars in millions):

Utility revenues ~~decreased due to a decrease at Avista Utilities, partially offset by an increase at AEL&P. Avista Utilities' revenues decreased primarily due to a decrease in electric~~were relatively consistent between the second quarters of 2023 and natural gas wholesale sales and a decrease in electric sales of fuel. These revenue decreases were partially offset by an electric general rate increase in Idaho, a natural gas general rate increase in Oregon and higher2022. While retail electric revenues. Retail electric revenues increased as a result of higher cooling loads due to weather that was warmer than the prior year and customer growth. There were net electric decoupling rebates during both the third quarter of 2017 and 2016 and net natural gas decoupling surcharges during both the third quarter of 2017 and 2016. The electric rebates were larger in 2017 compared to 2016 due to weather that was warmer than normal in 2017. AEL&P's revenues increased primarily due to ~~a general rate increase~~increased natural gas rates and ~~higher retail heating loads due to weather that was cooler than the prior year. There was also a slight increase in the number~~electric usage, these increases were offset by decreased sales of ~~customers at AEL&P.~~

fuel and natural gas wholesale activity.

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Utility resource costs decreased ~~due to a decrease~~ at Avista Utilities ~~partially offset by an increase at AEL&P. The decrease at Avista Utilities was primarily~~ due to ~~a decrease in purchased~~decreased natural gas prices and power resulting from a decrease in prices, partially offset by a slight increase in volumes. The increase at AEL&P was primarily due to a customer refund liability related to AEL&P's general rate case settlement.

The increase in utility other operating expenses was due to an increase at Avista Utilities and a slight increase at AEL&P. The increase at Avista Utilities was the result of an increase in generation and distribution maintenance costs and higher compensationsupply costs, partially offset by ~~decreases in pension, other postretirement benefit and medical expenses.~~

~~The acquisition~~increases associated with deferrals of net power supply costs ~~are~~below authorized levels.

Utility operating expenses slightly decreased when compared to the second quarter of 2022, primarily a result of the 2022 write-off of $4.0 million related to the ~~pending Hydro One acquisition and consist primarily~~Dry Ash Disposal System at Colstrip as part of ~~consulting, banking fees, legal fees and employee time and are not being passed through to customers.~~

the 2022 Washington general rate case. This was offset by inflationary pressures resulting in increased labor costs. See the "Executive Overview" for further discussion of inflation.

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

~~Income taxes decreased~~

Interest expense increased due to higher interest rates associated with inflation, as well as increased borrowings outstanding. Borrowings increased due to capital expenditures, higher energy commodity prices and additional requirements for cash collateral. See the "Executive Overview" for further discussion of inflation.

Income tax benefit increased primarily due to increased tax customer credits offsetting the bill impact of rate increases included in our 2022 Washington general rate cases, partially offset by the timing impact of spreading the increased credits over the year as a percentage of pre-tax income based on the estimated annual effective tax rate. See "Note 8 of the Notes to Condensed Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.

The decrease in ~~income before income taxes. Our effective tax rate was 53.6 percent for the third quarter of~~ ~~2017~~ ~~compared to 38.3 percent for the~~ ~~third quarter~~ of 2016. The effective tax rate increased during 2017 because the majority of acquisition costs, which reduce income before income taxes, are not deductible for tax purposes and thus do not reduce income tax expense.

~~Other~~other was primarily related to ~~an increase~~investment losses recognized in ~~interest expense, due to additional debt being outstanding during 2017 as~~2023, compared to ~~2016~~investment gains in 2022. This was partially offset by increased interest income and ~~partially due to an increase in the overall interest rate. Also, there was an increase in utility taxes~~decreased other ~~than income taxes primarily due to revenue-related taxes, which resulted from an increase in retail electric revenue.~~

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~~Nine~~non-utility operating expenses.

Six months ended ~~September~~June 30, ~~2017~~2023 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2016~~

2022

The following graph shows the total change in net income ~~attributable to Avista Corp. shareholders~~ for the ~~nine months ended September 30, 2016~~second quarter of 2023 compared to the ~~nine months ended September 30, 2017,~~second quarter of 2022, as well as the various factors that caused such change (dollars in millions):

Utility revenues increased ~~due to increases~~ at ~~both~~ Avista Utilities ~~and AEL&P. Avista Utilities' revenues increased~~when compared to the first half of 2022. This was primarily due to ~~an electric general rate increase in Idaho, a natural gas general rate increase in Oregon and higher retail electric and natural gas revenues. The higher electric and~~increased natural gas retail revenues ~~were from~~associated with increased ~~heating loads~~retail rates (primarily PGAs), particularly during the first quarter of 2023. This was partially offset by decreased natural gas wholesale revenues and financial losses on our derivative contracts, which are netted with utility revenues.

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Utility resource costs decreased at Avista Utilities due to ~~customer growth and weather~~financial gains related to our hedging activities that ~~was cooler than the prior year~~are netted with our expenses, as well as deferred costs in excess of authorized levels during the ~~heating season. Also, during the third~~first quarter ~~weather was warmer than the prior year, which increased electric cooling loads. The increased utility revenues~~of 2023. These decreases were partially offset by ~~decoupling rebates~~increases in purchased power prices during the ~~first nine months of 2017 due to weather that fluctuated from normal. This compares to decoupling surcharges~~period, as well as increased natural gas prices during the first ~~nine months~~quarter.

Utility operating expenses increased when compared to the first half of ~~2016. AEL&P's revenues increased~~2022, primarily due to ~~a general rate increase and higher retail heating loads due to weather that was cooler than the prior year. There was also a slight increase~~inflationary pressures resulting in ~~the number of customers at AEL&P.~~

Utility resource costs decreased due to a decrease at Avista Utilities, partially offset by an increase at AEL&P. The decrease at Avista Utilities was primarily due to a decrease in purchased power, resulting from a decrease in wholesale prices, partially offset by an increase in volumes, and a decrease in fuel for generation resulting from higher hydroelectric generation and lower thermal generation. The increase at AEL&P was primarily due to a customer refund liability related to AEL&P's general rate case settlement.

The increase in utility other operating expenses was due to an increase at Avista Utilities and a slight increase at AEL&P. The increase at Avista Utilities' was the result of an increase in generation and distribution maintenance costs, higher compensationincreased labor costs, as well as ~~a write-off in Oregon~~increased net amortizations of ~~utility plant associated with a general rate case settlement. The increased costs were partially offset by decreases in pension, other postretirement benefit and medical expenses.~~

~~The acquisition costs are related to~~previously deferred costs. See the ~~pending Hydro One acquisition and consist primarily~~"Executive Overview" for further discussion of ~~consulting, banking fees, legal fees and employee time and are not being passed through to customers.~~

inflation.

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

~~Income taxes decreased~~

Income tax benefit decreased primarily due the tax customer credits offsetting the bill impact of rate increases included in our 2021 Washington and Idaho general rate cases. These tax credits will be fully returned to customers by the end of the third quarter of 2023 and will no longer reduce both customer bills and income tax expense. Income tax is spread throughout the year as a ~~decrease in~~percentage of pre-tax income ~~before income taxes. Our~~based on the estimated annual effective tax rate, ~~was 36.9 percent for 2017,~~and as a result the benefit has decreased compared to ~~36.0 percent~~the prior year. See "Note 8 of the Notes to Condensed Consolidated Financial Statements" for ~~2016. The~~further details and a reconciliation of our effective tax ~~rate increased during 2017 because the majority of acquisition costs, which reduce income before income taxes, are not deductible for tax purposes and thus do not reduce income tax expense.~~

~~Other~~rate.

The decrease in other was primarily related to ~~an increase~~investment losses recognized in ~~interest expense, due to additional debt being outstanding during 2017 as~~2023, compared to ~~2016~~investment gains in 2022. This was partially offset by increased interest income and ~~partially due to an increase in the overall interest rate. Also, there was an increase in utility taxes~~decreased other ~~than income taxes primarily due to revenue-related taxes, which resulted from an increase in electric and natural gas retail revenue.~~

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non-utility operating expenses.

Non-GAAP Financial Measures

The following discussion for Avista Utilities includes two financial measures ~~that are~~ considered “non-GAAP financial ~~measures,”~~measures”: electric ~~gross~~utility margin and natural gas ~~gross~~utility margin. In the AEL&P section, we include a discussion of ~~electric gross~~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 17 of the Notes to Condensed Consolidated Financial Statements."

The presentation of electric ~~gross~~utility margin and natural gas ~~gross~~utility margin is intended to ~~supplement an~~enhance the understanding of operating performance. We use these measures internally and believe they provide useful information to ~~determine whether the appropriate amount~~investors in their analysis of ~~revenue is being collected from our customers to allow for the recovery of energy resource costs and operating costs, as well as to analyze~~ how changes in loads (due to weather, economic or other conditions), rates, supply costs and other factors impact our results of operations. ~~In addition, we~~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 ~~gross~~utility margin separately below for Avista Utilities since each business has different cost sources, cost recovery mechanisms and jurisdictions, ~~such that~~so we believe separate analysis is beneficial. These measures are not intended to replace ~~income from operations~~utility operating revenues as determined in accordance with GAAP as an indicator of operating performance. ~~The calculations~~Reconciliations of ~~electric and natural gas gross margins~~operating revenues to utility margin are ~~presented~~set forth below.

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Results of Operations - Avista Utilities

Three months ended ~~September~~June 30, ~~2017~~2023 compared to the three months ended ~~September~~June 30, ~~2016~~2022

Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three months ended June 30, 2023 and 2022 (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 $2.1 million and $4.2 million for the three months ended June 30, 2023 and 2022, respectively.

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


	Electric Decoupling Revenues
	2023		2022
Current year decoupling deferrals (a)	$	476	$	708
Amortization of prior year decoupling deferrals (b)		1,755		(3,062	)
Total electric decoupling revenue	$	2,231	$	(2,354	)

(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.

Total electric revenues increased $1.5 million for the second quarter of 2023 as compared to the second quarter of 2022. The primary changes that occurred during the period were as follows:

•

a $3.8 million increase in retail electric revenue due to an increase in MWhs sold (increased revenues by $4.4 million) partially offset by a decrease in retail rates (decreased revenues by $0.6 million).

•

a $28.3 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $14.2 million) and an increase in sales volumes (increased revenues $14.1 million). The fluctuation of volumes was due to increased thermal generation, which allowed for additional opportunities to optimize our generation assets.

•

a $35.9 million decrease in sales of fuel as part of increased thermal generation and decreased fuel resource optimization activities, including associated financial hedging activities.

•

a $4.6 million increase in electric decoupling revenue, resulting from amortization of prior year rebate balances in 2023, compared to amortization of surcharge balances in 2022.

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The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three months ended June 30, 2023 and 2022 (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 $6.0 million and $11.9 million for the three months ended June 30, 2023 and 2022, respectively.

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


	Natural Gas Decoupling Revenues
	2023			2022
Current year decoupling deferrals (a)	$	4,661		$	(3,235	)
Amortization of prior year decoupling deferrals (b)		(1,380	)		(204	)
Total natural gas decoupling revenue	$	3,281		$	(3,439	)

(a)

(b)

Total natural gas revenues decreased $9.4 million for the second quarter of 2023 as compared to the second quarter of 2022. The primary changes that occurred during the period were as follows:

•

a $3.0 million increase in natural gas retail revenues (including industrial, which is included in other) due to higher retail rates (increased revenues $22.3 million), partially offset by lower sales volumes (decreased revenues $19.3 million).

Retail rates increased mainly due to PGA rate increases in all jurisdictions (which do not impact utility margin).

Retail natural gas sales volumes decreased primarily due to lower residential and commercial usage, resulting from warmer weather (decreasing heating load). Compared to the second quarter of 2022, residential use per customer decreased 26 percent, and commercial firm use per customer decreased 20 percent. Heating degree days in Spokane were 40 percent below the prior year and 25 percent below our historical normal. Heating degree days in Medford were 30 percent below the prior year and 5 percent below our historical normal.

•

an $18.8 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $18.5 million), and a decrease in sales volumes of (decreased revenues $0.3 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 $6.7 million increase in natural gas decoupling revenue primarily due to surcharges to residential customers in the second quarter of 2023 due to lower than normal usage compared to rebates in 2022, partially offset by increased amortization of surcharge balances.

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the three months ended June 30, 2023 and 2022:


	Electric Customers				Natural Gas Customers
	2023		2022		2023		2022
Residential		365,537		360,765		340,506		336,947
Commercial		45,438		44,594		37,129		36,808
Interruptible		—		—		50		44
Industrial		1,193		1,196		186		189
Public street and highway lighting		689		685		—		—
Total retail customers		412,857		407,240		377,871		373,988

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Utility Resource Costs

The following graphs present Avista Utilities' resource costs for the three months ended June 30, 2023 and 2022 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of $6.0 million and $11.9 million for the three months ended June 30, 2023 and 2022, respectively.

Total electric resource costs decreased $12.2 million for the second quarter of 2023 as compared to the second quarter of 2022. The primary changes that occurred during the period were as follows:

•

a $10.4 million increase in power purchased due to an increase in the volume of power purchases (increased costs $8.7 million) and an increase in wholesale prices (increased costs $1.7 million). The change in volumes was primarily the result of fluctuations in customer loads and decreased hydroelectric generation.

•

a $2.4 million decrease in fuel for generation due to decreased natural gas fuel prices, partially offset by an increase in thermal generation volumes due in part to decreased hydroelectric generation.

•

a $28.1 million decrease in other fuel costs. These costs represent fuel and the related derivative instruments purchased for generation which were later sold when conditions indicated it was more economical to sell the fuel as part of the resource optimization process. When the fuel is sold either physically or through a derivative instrument, that revenue is included in sales of fuel.

•

a $7.9 million increase in other electric resource costs, primarily related to an increase in deferred benefits associated with net power supply costs below authorized levels.

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Total natural gas resource costs in the graph above include intracompany resource costs of $2.1 million and $4.2 million for the three months ended June 30, 2023 and 2022, respectively.

Total natural gas resource costs decreased $12.0 million for the second quarter of 2023 as compared to the second quarter of 2022 primarily due to the following:

•

a $36.3 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $31.1 million), and a decrease in volumes (decreased costs $5.2 million). The decrease in volumes is primarily due to decreased retail usage.

•

a $24.3 million increase from net amortizations and deferrals of natural gas costs, primarily related to an increase in deferred benefits associated with net power supply costs below authorized levels.

Utility Margin

The following table reconciles Avista Utilities' operating revenues, ~~resource costs and resulting gross~~as presented in "Note 17 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the three months ended ~~September~~June 30, 2023 and 2022 (dollars in thousands):

Electric Natural Gas Intracompany Total
2017 2016 2017 2016 2017 2016 2017 2016
Operating revenues $ 231,419
$ 237,768
$ 79,938
$ 83,335
$ (30,581 ) $ (33,910 ) $ 280,776
$ 287,193
Resource costs 79,598
90,445
55,499
58,693
(30,581 ) (33,910 ) 104,516
115,228
Gross margin $ 151,821
$ 147,323
$ 24,439
$ 24,642
$ —
$ —
$ 176,260
$ 171,965

~~The gross~~


	Electric				Natural Gas				Intracompany						Total
	2023		2022		2023		2022		2023			2022			2023		2022
Operating revenues	$	283,130	$	281,633	$	93,529	$	102,919	$	(8,055	)	$	(16,037	)	$	368,604	$	368,515
Resource costs		100,291		112,480		47,781		59,778		(8,055	)		(16,037	)		140,017		156,221
Utility margin	$	182,839	$	169,153	$	45,748	$	43,141	$	—		$	—		$	228,587	$	212,294

Electric utility margin ~~on electric sales~~ increased ~~$4.5~~$13.7 million and ~~the gross margin on~~ natural gas ~~sales decreased $0.2 million in the third quarter of 2017 compared to the third quarter of 2016. The increase in electric gross~~utility margin ~~was~~increased $2.6 million.

Electric utility margin increased primarily due to ~~a general rate increase in Idaho,~~impacts of the ERM, customer growth and ~~lower resource costs. For~~ the ~~third~~effects of general rate cases.

In the second quarter of ~~2017~~,2023, we had a $1.0 million pre-tax ~~expense~~benefit under the ERM in Washington, compared to a ~~$1.6~~$4.8 million pre-tax expense for the ~~third~~second quarter of ~~2016. For the full year of 2017, we expect to be in a benefit position under the ERM within the $4 million deadband,~~2022.

Natural gas utility margin increased primarily due to ~~above normal hydroelectric generation for~~customer growth and the ~~year, which allowed us to engage in additional optimization activities.~~

effects of general rate cases.

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

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results for Avista Utilities and in the condensed consolidated financial statements but are included in the separate results for electric and natural gas presented ~~below.~~

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above.

Six months ended June 30, 2023 compared to the six months ended June 30, 2022

Utility Operating Revenues

The following graphs present Avista Utilities' ~~utility~~ electric operating revenues and megawatt-hour (MWh) sales for the ~~three~~six months ended ~~September~~June 30, 2023 and 2022 (dollars in millions and MWhs in thousands):


~~(1)~~	~~This balance includes public street and highway lighting, which is considered part of retail electric revenues and it also includes revenues and rebates from decoupling.~~

(1)

48This 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 $3.3 million and $4.4 million for the six months ended June 30, 2023 and 2022, respectively.

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AVISTA CORPORATION

The following table presents ~~Avista Utilities'~~the current year deferrals and the amortization of prior year decoupling ~~and customer earnings sharing mechanisms by jurisdiction that are~~balances reflected in utility electric operating revenues for the ~~three~~six months ended ~~September~~June 30 (dollars in thousands):


	Electric Decoupling Revenues
	2023			2022
Current year decoupling deferrals (a)	$	(2,046	)	$	(8,096	)
Amortization of prior year decoupling deferrals (b)		4,478			(5,885	)
Total electric decoupling revenue	$	2,432		$	(13,981	)

(a)

Electric Operating
Revenues
2017 2016
Washington
Decoupling surcharge (rebate) $ (4,092 ) $ 266
Provision for earnings sharing —
355
Idaho
Decoupling rebate $ (918 ) $ (515 )
(b)

Total electric revenues decreased ~~$6.3~~$9.1 million for the ~~third quarter~~first half of ~~2017~~2023 as compared to the ~~third quarter~~first half of ~~2016 primarily reflecting~~2022. The primary changes that occurred during the ~~following:~~

period were as follows:

•

an ~~$11.5~~a $3.6 million increase in retail electric revenue due to an increase in ~~total~~retail rates (increased revenues by $2.2 million), and an increase in MWhs sold (increased revenues ~~$8.3~~by $1.4 million) ~~and an~~.

•

a $47.5 million increase ~~in revenue per MWh (increased revenues $3.2 million).~~

◦

The increase in total retail MWhs sold was the result of weather that was warmer than the prior year (which increased electric cooling loads), as well as customer growth. Compared to the third quarter of 2016, residential electric use per customer increased 8 percent and commercial use per customer increased 2 percent. Cooling degree days in Spokane were 39 percent above normal and 79 percent above the third quarter of 2016.


◦	~~The increase in revenue per MWh was primarily due to a general rate increase in Idaho and a greater portion of retail revenues from residential customers in the third quarter of 2017.~~

a ~~$7.2 million~~ ~~decrease~~ in wholesale electric revenues due to ~~a decrease~~an increase in sales prices ~~(decreased~~(increased revenues ~~$8.0~~$41.0 million)~~, partially offset by~~ and an increase in sales volumes (increased revenues ~~$0.8~~$6.5 million). The fluctuation inof volumes ~~and prices~~ was ~~primarily the result of our~~due to resource optimization activities.

•

a ~~$5.0~~an $80.3 million decrease in sales of ~~fuel due to a decrease in sales of natural gas~~ fuel as part of thermal generation resource optimization ~~activities. For the third quarter of 2017, $13.6~~activities, including associated financial hedging activities, which includes net losses on derivative instruments.

•

a $16.4 million of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For the third quarter of 2016, $13.8 million of these sales were made to our natural gas operations.

a ~~$4.8 million~~ ~~decrease~~increase in electric decoupling revenue, resulting from decreasing rebates in 2023 resulting from lower usage from residential customers compared to the prior year, as well as amortization of prior year rebate balances in 2023, compared to amortization of surcharge balances in 2022.

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•

a $3.8 million increase in other revenue, primarily due to decoupling. Weather was significantly warmer than normal in the third quarter of 2017, which resulted in large decoupling rebates. Weather was close to normal in third quarter of 2016, which resulted in immaterial decoupling adjustments. Decoupling mechanisms are not impacted by fluctuations in weather compared to prior year, they are only impacted by weather fluctuations as compared to normal weather.increased transmission revenue.

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The following graphs present ~~our utility~~Avista Utilities' natural gas operating revenues and therms delivered for the ~~three~~six months ended ~~September~~June 30, 2023 and 2022 (dollars in millions and therms in thousands):


~~(1)~~	~~This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues and it also includes revenues and rebates from decoupling.~~

(1)

50This 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 $12.3 million and $21.2 million for the six months ended June 30, 2023 and 2022, respectively.

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AVISTA CORPORATION

The following table presents ~~Avista Utilities'~~the current year deferrals and the amortization of prior year decoupling ~~and customer earnings sharing mechanisms by jurisdiction that are~~balances reflected in utility natural gas operating revenues for the ~~three~~six months ended ~~September~~June 30 (dollars in thousands):


	Natural Gas Decoupling Revenues
	2023			2022
Current year decoupling deferrals (a)	$	(10,501	)	$	(7,905	)
Amortization of prior year decoupling deferrals (b)		(5,457	)		(684	)
Total natural gas decoupling revenue	$	(15,958	)	$	(8,589	)

(a)

Natural Gas Operating
Revenues
2017 2016
Washington
Decoupling surcharge (rebate) $ (45 ) $ 376
Provision for earnings sharing (rebate) (207 ) 177
Idaho
Decoupling rebate $ (30 ) $ (82 )
Oregon
Decoupling surcharge $ 350
$ 486
(b)

Total natural gas revenues ~~decreased $3.4~~increased $10.5 million for the ~~third quarter~~first half of ~~2017~~2023 as compared to the ~~third quarter~~first half of ~~2016 primarily reflecting~~2022. The primary changes that occurred during the ~~following:~~

period were as follows:

•

a ~~$1.7~~$64.9 million ~~decrease~~ increase in natural gas retail revenues (including industrial, which is included in other) due to ~~lower~~higher retail rates ~~(decreased~~(increased revenues ~~$1.9~~$68.3 million), partially offset by lower sales volumes (decreased revenues $3.4 million).

Retail rates increased mainly due to PGA rate increases in all jurisdictions (which do not impact utility margin).

Retail natural gas sales volumes decreased primarily due to decreased residential and commercial usage, due to warmer weather (decreasing heating load). Compared to the first half of 2022, residential use per customer decreased 5 percent, and commercial use per customer decreased 2 percent. Heating degree days in Spokane were 11 percent below the prior year and 6 percent below our historical norm. Heating degree days in Medford were consistent with the prior year and 8 percent above normal.

•

a ~~slight increase in volumes (increased revenues $0.2 million).~~


◦	~~We sold slightly more retail natural gas in the~~ ~~third quarter~~ of ~~2017~~ ~~as compared to the~~ ~~third quarter~~ of ~~2016. Retail natural gas loads and changes in customer usage during the third quarter are typically not significant to the full year.~~


◦	~~Lower retail rates were due to PGAs, partially offset by a general rate increase in Oregon.~~

a ~~$1.1~~$46.8 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $43.8 million), and a decrease in sales volumes (decreased revenues ~~$5.1~~$3.0 million)~~, partially offset by an increase~~. The decrease in prices ~~(increased revenues $4.0 million). In~~includes the ~~third quarter~~impact of ~~2017~~, ~~$17.0 million~~ ~~of these sales were made to~~financial losses associated with our ~~electric generation operations and are included as intracompany revenues and resource costs. In the~~ ~~third quarter~~ of ~~2016~~, ~~$20.1 million~~ ~~of these sales were made to~~hedging activities, which nets with our ~~electric generation operations.~~wholesale revenues. 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 ~~$0.5~~$7.4 million decrease in natural gas decoupling revenue primarily due to ~~decoupling. Retail natural gas loads, changes~~higher rebates to residential customers in ~~customer~~the first quarter of 2023 due to higher than normal usage, ~~and resulting decoupling surcharges or rebates during the third quarter are typically not significant to the full year.~~as well as higher amortization of surcharge balances.

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

Electric
Customers

Natural Gas
Customers
2017 2016 2017 2016
Residential 334,274
330,435
306,706
300,168
Commercial 42,241
41,830
35,087
34,792
Interruptible —
—
37
35
Industrial 1,336
1,340
253
256
Public street and highway lighting 577
559
—
—
Total retail customers 378,428
374,164
342,083
335,251

2023 and 2022:


	Electric Customers				Natural Gas Customers
	2023		2022		2023		2022
Residential		365,040		360,483		340,073		336,261
Commercial		45,224		44,497		37,101		36,748
Interruptible		—		—		50		44
Industrial		1,189		1,197		186		189
Public street and highway lighting		688		676		—		—
Total retail customers		412,141		406,853		377,410		373,242

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AVISTA CORPORATION

Utility Resource Costs

The following graphs present ~~our utility~~Avista Utilities' resource costs for the ~~three~~six months ended ~~September~~June 30, 2023 and 2022 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of ~~$17.0~~$12.3 million and ~~$20.1~~$21.2 million for the ~~three~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~September 30, 2016,~~2022, respectively.

Total electric resource costs decreased $22.5 million for the first half of 2023 as compared to the first half of 2022. The primary changes that occurred during the period were as follows:

•

a $26.4 million increase in power purchased due to an increase in wholesale prices (increased costs $19.5 million), and an increase in the volume of power purchases (increased costs $6.9 million). The change in volumes was primarily the result of fluctuations in customer loads and decreased hydroelectric generation.

•

a $9.4 million decrease in fuel for generation primarily due to financial gains associated with our hedging activities, which net with our physical purchases, as well as decreased natural gas prices. This was partially offset by an increase in thermal generation volumes due in part to decreased hydroelectric generation.

•

a $36.4 million decrease in other fuel costs, resulting from financial gains associated with our hedging activities. These costs represent fuel and the related derivative instruments purchased for generation but were later sold when conditions indicated it was more economical to sell the fuel as part of the resource optimization process. When the fuel is sold either physically or through a derivative instrument, that revenue is included in sales of fuel.

•

a $3.1 million decrease in other electric resource costs, primarily related to an increase in deferred costs associated with net power supply costs above authorized levels during the first quarter of 2023.

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Total natural gas resource costs in the graph above include intracompany resource costs of ~~$13.6~~$3.3 million and ~~$13.8~~$4.4 million for the ~~three~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~September 30, 2016,~~2022, respectively.

Total ~~electric~~natural gas resource costs ~~decreased $10.8~~increased $2.0 million for the ~~third quarter~~first half of ~~2017~~2023 as compared to the ~~third quarter~~first half of ~~2016~~2022 primarily ~~reflecting the following:~~

~~an $8.4 million decrease in purchased power~~ due to the following:

•

a ~~decrease~~$9.6 million increase in ~~wholesale prices (decreased~~natural gas purchased due to an increase in the price of natural gas (increased costs ~~$8.5~~$22.9 million), partially offset by a ~~slight increase in the volume of power purchases (increased costs $0.1 million). The fluctuation~~decrease in volumes ~~and prices was primarily the result of our optimization activities during the quarter.~~(decreased costs $13.3 million).

•

a $0.8 million decrease 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 $2.1~~$7.6 million decrease from ~~amortizations and deferrals of power costs. This change was primarily the result of lower~~ net ~~power supply costs.~~

~~a $0.4 million net increase from other regulatory amortizations and other electric resource costs.~~

~~Total natural gas resource costs decreased~~ ~~$3.2 million~~ ~~for the third quarter of 2017 as compared to the third quarter of 2016 primarily reflecting the following:~~

a $5.3 million decrease in natural gas purchased due to a decrease in total therms purchased (decreased costs $4.8 million) and a decrease in the price of natural gas (decreased costs $0.5 million). Total therms purchased decreased due to a decrease in wholesale sales.

~~a $0.2 million decrease in other regulatory amortizations.~~

~~a $2.1 million increase from~~ amortizations and deferrals of natural gas costs. ~~This reflects lower~~In the first quarter of 2023, we had significant deferred natural gas ~~prices compared to our~~costs in excess of authorized ~~PGA rates and the deferral of these lower costs, which occurred in the current quarter for future rebate to customers.~~

~~Nine months ended September 30, 2017 compared~~levels due to the ~~nine months ended September 30, 2016~~high price of natural gas.

Utility Margin

The following table ~~presents our~~reconciles Avista Utilities' operating revenues, ~~resource costs and resulting gross~~as presented in "Note 17 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the ~~nine~~six months ended ~~September~~June 30, 2023 and 2022 (dollars in thousands):

Electric Natural Gas Intracompany Total
2017 2016 2017 2016 2017 2016 2017 2016
Operating revenues $ 725,695
$ 735,361
$ 330,580
$ 319,700
$ (63,371 ) $ (65,080 ) $ 992,904
$ 989,981
Resource costs 239,900
258,147
190,061
187,846
(63,371 ) (65,080 ) 366,590
380,913
Gross margin $ 485,795
$ 477,214
$ 140,519
$ 131,854
$ —
$ —
$ 626,314
$ 609,068

~~The gross~~


	Electric				Natural Gas				Intracompany						Total
	2023		2022		2023		2022		2023			2022			2023		2022
Operating revenues	$	540,427	$	549,558	$	303,919	$	293,431	$	(15,600	)	$	(25,602	)	$	828,746	$	817,387
Resource costs		185,035		207,519		162,719		160,728		(15,600	)		(25,602	)		332,154		342,645
Utility margin	$	355,392	$	342,039	$	141,200	$	132,703	$	—		$	—		$	496,592	$	474,742

Electric utility margin ~~on electric sales~~ increased ~~$8.6~~$13.4 million and ~~the gross margin on~~ natural gas ~~sales~~utility margin increased ~~$8.7~~$8.5 million. ~~The increase in electric gross~~

Electric utility margin ~~was~~increased primarily due to ~~a general rate increase in Idaho,~~ customer growth and ~~lower resource costs,~~the effects of general rate cases, partially offset by the impacts of the ERM in Washington.

In the first half of 2023, we had a ~~change in the provision for earnings sharing. During 2016, there was a provision for earnings sharing, which increased electric gross margin by $3.2~~$6.5 million ~~compared to a rebate during 2017 of $0.1 million. For the nine months ended September 30, 2017, we recognized a~~ pre-tax ~~benefit of $3.6 million~~expense under the ERM in Washington, compared to a ~~benefit of $2.7~~$2.8 million pre-tax expense for the ~~nine months ended September 30, 2016. For the full year~~first half of ~~2017, we expect to be in a benefit position under the ERM within the $4 million deadband,~~2022.

Natural gas utility margin increased primarily due to ~~above normal hydroelectric generation for~~customer growth and the ~~year, which allowed us to engage in additional optimization activities.~~

~~The increase in natural gas gross margin was primarily due to a~~effects of general rate ~~increase in Oregon and customer growth.~~

cases.

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results for Avista Utilities and in the condensed consolidated financial statements but are included in the separate results for electric and natural gas presented ~~below.~~

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~~The following graphs present our utility electric operating revenues and megawatt-hour (MWh) sales for the nine months ended September 30 (dollars in millions and MWhs in thousands):~~

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The following table presents Avista Utilities' decoupling and customer earnings sharing mechanisms by jurisdiction that are reflected in utility electric operating revenues for the nine months ended September 30 (dollars in thousands):

Electric Operating
Revenues
2017 2016
Washington
Decoupling surcharge (rebate) $ (5,552 ) $ 8,900
Provision for earnings sharing (1) (130 ) 2,524
Idaho
Decoupling surcharge (rebate) $ (2,015 ) $ 4,516
Provision for earnings sharing (2) n/a
711

~~(1)~~

The provision for earnings sharing in Washington for the nine months ended September 30, 2017 represents an adjustment of the 2016 provision for earnings sharing. We are not expecting a provision for earnings sharing in Washington relating to 2017 earnings. The provision for earnings sharing in Washington for the nine months ended September 30, 2016 resulted from a $2.5 million reduction in the 2015 provision for earnings sharing (which increased 2016 revenues).


~~(2)~~	The provision for earnings sharing in Idaho for the nine months ended September 30, 2016 resulted from a reduction in the 2015 provision for earnings sharing (which increased 2016 revenues). Beginning in 2016 there is no longer an earnings sharing mechanism in Idaho.


~~(n/a)~~	~~This mechanism did not exist during this time period.~~

~~Total electric revenues decreased $9.7 million for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 primarily reflecting the following:~~

~~a $42.2 million increase in retail electric revenue due to an increase in total MWhs sold (increased revenues $30.5 million) and an increase in revenue per MWh (increased revenues $11.7 million).~~

◦

The increase in total retail MWhs sold was the result of weather that was cooler than the prior year during the heating season (which increased electric heating loads) and warmer than the prior year during the cooling season (which increased electric cooling loads), as well as customer growth. Compared to the nine months ended September 30, 2016, residential electric use per customer increased 9.8 percent and commercial use per customer increased 0.6 percent. Heating degree days in Spokane were 5 percent above normal and 26 percent above the first nine months of 2016. Year-to-date 2016 cooling degree days were 41 percent above normal and 57 percent above the prior year.


◦	~~The increase in revenue per MWh was primarily due to a general rate increase in Idaho and a greater portion of retail revenues from residential customers in 2017.~~

a $26.6 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $20.7 million) and a decrease in sales volumes (decreased revenues $5.9 million). The fluctuation in volumes and prices was primarily the result of our optimization activities.

a $4.2 million decrease in sales of fuel due to a decrease in sales of natural gas fuel as part of thermal generation resource optimization activities. For the nine months ended September 30, 2017, $26.9 million of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For the nine months ended September 30, 2016, $30.1 million of these sales were made to our natural gas operations.

a $21.0 million decrease in electric revenue due to decoupling. Weather was cooler than normal during the heating season and warmer than normal during the cooling season in 2017, which resulted in decoupling rebates for the first nine months of 2017. Weather was warmer than normal during the heating season in 2016, which resulted in significant decoupling surcharges. Decoupling mechanisms are not impacted by fluctuations in weather compared to prior year, they are only impacted by weather fluctuations as compared to normal weather.

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~~The following graphs present our utility natural gas operating revenues and therms delivered for the nine months ended September 30 (dollars in millions and therms in thousands):~~

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The following table presents Avista Utilities' decoupling and customer earnings sharing mechanisms by jurisdiction that are reflected in utility natural gas operating revenues for the nine months ended September 30 (dollars in thousands):

Natural Gas Operating
Revenues
2017 2016
Washington
Decoupling surcharge (rebate) $ (5,265 ) $ 7,142
Provision for earnings sharing (824 ) (359 )
Idaho
Decoupling surcharge (rebate) $ (914 ) $ 2,044
Oregon
Decoupling surcharge (rebate) $ (1,700 ) $ 2,344

~~Total natural gas revenues increased $10.9 million for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 primarily reflecting the following:~~

~~a $31.8 million increase in natural gas retail revenues due to an increase in volumes (increased revenues $44.5 million), partially offset by lower retail rates (decreased revenues $12.7 million).~~

◦

We sold more retail natural gas in the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 due to cooler weather and customer growth. Compared to the first nine months of 2016, residential natural gas use per customer increased 24 percent and commercial use per customer increased 24 percent. Heating degree days in Spokane were 5 percent above normal and 26 percent above the first nine months of 2016. Heating degree days in Medford were 2 percent below normal, but 26 percent above the first nine months of 2016.


◦	~~Lower retail rates were due to PGAs, partially offset by a general rate increase in Oregon.~~

a $2.1 million decrease in wholesale natural gas revenues due to a decrease in volumes (decreased revenues $27.2 million), mostly offset by an increase in prices (increased revenues $25.1 million). In the nine months ended September 30, 2017, $36.5 million of these sales were made to our electric generation operations and are included as intracompany revenues and resource costs. In the nine months ended September 30, 2016, $35.0 million of these sales were made to our electric generation operations. 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 $19.4 million decrease in natural gas revenue due to decoupling. Weather was overall cooler than normal during the heating season in 2017, which resulted in decoupling rebates. Weather was warmer than normal during the heating season in 2016, which resulted in decoupling surcharges. Decoupling mechanisms are not impacted by fluctuations in weather compared to prior year, they are only impacted by weather fluctuations as compared to normal weather.

~~The following table presents our average number of electric and natural gas retail customers for the nine months ended September 30:~~

Electric
Customers

Natural Gas
Customers
2017 2016 2017 2016
Residential 334,015
330,018
306,389
300,033
Commercial 42,127
41,742
35,174
34,847
Interruptible —
—
37
37
Industrial (1) 1,330
1,345
252
256
Public street and highway lighting 567
556
—
—
Total retail customers 378,039
373,661
341,852
335,173


~~(1)~~	~~The decrease in electric industrial customers as compared to the first nine months of 2016 is primarily related to a decrease in Washington irrigation customers.~~

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~~The following graphs present our utility resource costs for the nine months ended September 30 (dollars in millions):~~

Total electric resource costs in the graph above include intracompany resource costs of $36.5 million and $35.0 million for the nine months ended September 30, 2017 and September 30, 2016, respectively.

Total natural gas resource costs in the graph above include intracompany resource costs of $26.9 million and $30.1 million for the nine months ended September 30, 2017 and September 30, 2016, respectively.

~~Total electric resource costs decreased $18.2 million for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 primarily reflecting the following:~~

a $15.4 million decrease in purchased power due to a decrease in wholesale prices (decreased costs $16.1 million), partially offset by a slight increase in the volume of power purchases (increased costs $0.7 million). The fluctuation in volumes and prices was primarily the result of higher than normal hydroelectric generation during the year, as well as our optimization activities during the period.

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~~an $11.4 million decrease in fuel for generation primarily due to a decrease in thermal generation (due in part to increased hydroelectric generation).~~

~~a $1.5 million increase in other fuel costs.~~

~~a $6.1 million increase from amortizations and deferrals of power costs. This change was primarily the result of lower net power supply costs.~~

~~a $1.0 million increase in other regulatory amortizations and other electric resource costs.~~

~~Total natural gas resource costs increased $2.2 million for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 primarily reflecting the following:~~

an $8.5 million increase in natural gas purchased due to an increase in the price of natural gas (increased costs $23.8 million), partially offset by a decrease in total therms purchased (decreased costs $15.3 million). Total therms purchased decreased due to a decrease in wholesale sales, partially offset by an increase in retail sales.

~~a $9.6 million decrease from amortizations and deferrals of natural gas costs.~~

~~a $3.4 million increase in other regulatory amortizations.~~

above.

Results of Operations - Alaska Electric Light and Power Company

~~Three months ended September 30, 2017 compared to the three months ended September 30, 2016 and nine months ended September 30, 2017 compared to the nine months ended September 30, 2016~~

Net income for AEL&P was $0.4 million for the three months ended September 30, 2017 compared to $0.9 million for the three months ended September 30, 2016. Net income was $6.0 million for the nine months ended September 30, 2017 compared to $4.9 million for the nine months ended September 30, 2016.

For both the third quarter and year-to-date there was an increase in electric gross margin which was $6.8 million for the third quarter of 2017, compared to $6.3 million for the third quarter of 2016. For the year-to-date, electric gross margin was $27.7 million for the nine months ended September 30, 2017, compared to $23.3 million for the nine months ended September 30, 2016. An increase in resource costs of $0.8 million related to a settlement agreement for AEL&P's 2016 electric general rate case is included in electric gross margin for the third quarter of 2017. See "Regulatory Matters" for further discussion of the settlement agreement. The increase in electric gross margin was partially offset by an increase in operating expenses and a decrease in equity-related AFUDC due to the construction of an additional back-up generation plant completed in 2016.

The increase in electric gross margin was primarily related to an interim general rate increase, effective in November 2016, and increases in electric heating loads due to weather that was cooler than the prior year. There were also slight increases in residential and commercial customers. This was partially offset by an increase in resource costs primarily due to purchased power and the general rate case settlement.

While the cooler weather did have some effect on AEL&P revenues during 2017, AEL&P has a relatively stable load profile as it does not have a large population of customers in its service territory with electric heating and cooling requirements; therefore, its revenues are not as sensitive to weather fluctuations as Avista Utilities. However, AEL&P does have higher winter rates for its customers during the peak period of November through May of each year, which drives higher revenues during those periods.

~~Operating expenses increased primarily due to supplies expense for the new back-up generation plant, which went into service in the fourth quarter of 2016.~~

~~Results of Operations - Other Businesses~~

~~Net losses for our other businesses were~~ $1.4 million for the three months ended ~~September~~June 30, ~~2017 compared to $1.3~~2023 and $0.8 million for the three months ended ~~September~~June 30, ~~2016.~~2022. Net ~~losses were $3.2~~income was $5.4 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023, compared to ~~$2.2~~$4.1 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~

~~Net losses~~2022.

The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the ~~nine~~three and six months ended ~~September~~June 30, ~~2017 were~~2023 and 2022 (dollars in thousands):


	Three months ended June 30,				Six months ended June 30,
	2023		2022		2023		2022
Operating revenues	$	11,194	$	9,906	$	25,557	$	22,960
Resource costs		1,227		1,176		2,018		1,620
Utility margin	$	9,967	$	8,730	$	23,539	$	21,340

Utility margin for the for the three and six months ended June 30 increased slightly from 2022, primarily ~~related~~due to ~~renovation expenses~~increased operating revenues resulting from both usage and ~~increased compliance costs at one~~rate increases compared to the prior year.

Results of Operations - Other Businesses

Our other businesses had a net loss of $2.7 million for the three months ended June 30, 2023 compared to net income of $6.7 million for the three months ended June 30, 2022. Net loss was $3.5 million for the six months ended June 30, 2023, compared to net income of $7.7 million for the six months ended June 30, 2022.

The decrease in net income primarily relates to decreases in the fair value of our ~~subsidiaries,~~investments in 2023, compared to net investment gains recognized in 2022. See "Note 12 of the ~~recognition~~Notes to the Condensed Consolidated Financial Statements" for further discussion of our ~~portion of net losses from our~~ equity ~~investments, and corporate costs (including costs associated with exploring strategic opportunities).~~

investment fair value.

Critical Accounting Policies and Estimates

The preparation of our condensed consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect amounts reported in the condensed consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our condensed consolidated financial statements and thus, actual

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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 ~~2016~~2022 Form 10-K and have not changed ~~materially from that discussion.~~

materially.

Liquidity and Capital Resources

Overall Liquidity

Our sources of overall liquidity and the requirements for liquidity have not materially changed in the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2023. See the ~~2016~~2022 Form 10-K for further discussion.

In March 2023, we issued $250.0 million of first mortgage bonds. A portion of the proceeds from the sale of these bonds will be used for the construction or improvement of utility facilities, and a portion was used to refinance existing indebtedness, including the repayment of our $150.0 million term loan.

As of ~~September~~June 30, ~~2017,~~2023, we had ~~$161.1~~$292.4 million of available liquidity under the Avista Corp. committed line of credit, $34.0 million of available liquidity under our letter of credit facility, and $25.0 million under the AEL&P committed line of credit. With our ~~$400.0 million~~existing credit ~~facility that expires in April 2021~~facilities and ~~AEL&P's $25.0 million credit facility that expires in November 2019,~~the expected issuances of common stock and debt within the next year, we believe ~~that~~ we have adequate liquidity to meet our needs for the next 12 months.

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Review of Consolidated Cash Flow Statement

Operating Activities

Net cash provided by operating activities was ~~$307.5 million~~ ~~for the~~ ~~nine months endedSeptember 30, 2017~~ ~~compared to~~ ~~$254.1 million~~ for the nine months ended September 30, 2016. The increase in net cash provided by operating activities was primarily related to the settlement of outstanding interest rate swaps. During 2017, we paid a net of $8.8$269.6 million for the ~~settlement of interest rate swaps,~~six months ended June 30, 2023, compared to ~~$54.0~~$205.9 million ~~in 2016. In addition, during~~for the ~~first three quarters of 2017, we posted $1.9 million of collateral for derivative instruments, compared to $19.8 million posted in the first three quarters of 2016. Our collateral increased in 2016~~six months ended June 30, 2022. The increase is primarily due to a decrease in ~~the fair value of~~collateral for our derivatives resulting in a $98.5 million increase to operating cash flows in 2023 compared to 2022, a decrease in our accounts and notes receivable balance outstanding resulting in a $78.2 million increase to operating cash flows in 2023 compared to 2022, and a net $7.5 million received for interest rate swap derivatives at that time and also due to fewer counterparties accepting letters of credit as collateral. In 2017, more counterparties are accepting letters of credit as collateral rather than cash. Finally, forsettlements during the ~~first three quarters of 2017, we had increased net income (after consideration of non-cash items included in net income) of $326.2 million,~~period compared to ~~$317.8~~$17.0 million paid in ~~2016.~~

~~The~~2022. These increases ~~above,~~in operating cash flows were partially offset by ~~increased pension contributions of $22.0~~decreases in our accounts payable and other current liabilities outstanding balances, which decreased operating cash flows by $130.0 million ~~for 2017,~~ compared to ~~$12.0 million for 2016.~~

2022.

Investing Activities

Net cash used in investing activities was ~~$302.4~~$234.1 million for the ~~nine~~six months ended~~September~~ June 30, ~~2017~~,2023, compared to ~~$315.0~~$219.4 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016~~.2022. During the ~~first three quarters of~~ ~~2017~~,six months ended June 30, 2023, we paid ~~$287.9~~$226.7 million for utility capital expenditures compared to ~~$288.1~~$210.6 million for the ~~first three quarters~~six months ended June 30, 2022. Additionally, we contributed capital of ~~2016. Also, during the first three quarters of 2017,~~$6.5 million to our ~~subsidiaries invested $10.9 million in~~ equity and property investments, compared to ~~$8.7~~$7.8 million ~~invested during~~in the first ~~three quarters~~half of ~~2016. Lastly, during~~2022.

Financing Activities

Net cash used in financing activities was $33.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017, our subsidiaries issued $2.8 million in notes receivable,~~2023, compared to ~~$9.7 million issued for the nine months ended September 30, 2016.~~

~~Financing Activities~~

~~Net~~net cash provided by financing activities ~~was~~ ~~$1.0~~of $12.9 million for the ~~nine~~six months ended~~September~~ June 30, ~~2017~~,2022. In the six months ended June 30, 2023, we issued $250.0 million of long-term debt, and repaid $6.5 million of maturing long-term debt. This compared to ~~net cash provided~~$400.0 million of ~~$57.4~~long-term debt issued in the first half of 2022, of which we used a portion to repay $250.0 million ~~for the~~ ~~nine months ended September 30, 2016~~. of maturing long-term debt. We ~~had the following transactions:~~

also decreased our short-term borrowings ~~increased~~ by ~~$75.0~~$260.0 million ~~during 2017,~~in the first half of 2023, compared to ~~an increase of $82.0~~$126.0 million in ~~2016,~~

~~during 2016,~~2022. In addition, we issued ~~$70.0 million~~ ~~under a short-term bridge loan to pay off a portion of a $90.0 million bond maturity,~~

cash dividends paid to Avista Corp. shareholders increased to $69.2 million (or $1.0725 per share) for the first three quarters of 2017 from $65.2 million (or $1.0275 per share) for the first three quarters of 2016, and

~~issuance of $1.5 million (net of issuance costs) under share-based compensation plans during 2017. In 2016, we issued $66.8~~$59.5 million of common stock ~~under sales agency agreements.~~

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in 2023, compared to $60.8 million in 2022.

Capital Resources

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings ~~and excluding noncontrolling interests,~~ consisted of the following as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016~~2022 (dollars in thousands):

September 30, 2017 December 31, 2016
Amount
Percent
of total
Amount
Percent
of total
Current portion of long-term debt and capital leases $ 277,626
7.7 % $ 3,287
0.1 %
Short-term borrowings 106,298
3.0 % 120,000
3.4 %
Long-term debt to affiliated trusts 51,547
1.4 % 51,547
1.5 %
Long-term debt and capital leases 1,491,789
41.5 % 1,678,717
47.9 %
Total debt 1,927,260
53.6 % 1,853,551
52.9 %
Total Avista Corporation shareholders’ equity 1,670,327
46.4 % 1,648,727
47.1 %
Total $ 3,597,587
100.0 % $ 3,502,278
100.0 %


	June 30, 2023					December 31, 2022
	Amount		Percent of total			Amount		Percent of total
Current portion of long-term debt and leases	$	14,793		0.3	%	$	21,084		0.4	%
Short-term borrowings		203,000		3.8	%		463,000		8.8	%
Long-term debt to affiliated trusts		51,547		1.0	%		51,547		1.0	%
Long-term debt and leases		2,637,333		49.7	%		2,387,792		45.4	%
Total debt		2,906,673		54.8	%		2,923,423		55.6	%
Total shareholders’ equity		2,400,421		45.2	%		2,334,668		44.4	%
Total	$	5,307,094		100.0	%	$	5,258,091		100.0	%

Our shareholders’ equity increased ~~$21.6~~$65.8 million during the first ~~nine months~~half of ~~2017~~2023 primarily due to net income and the issuance of common stock, which was partially offset by ~~dividends.~~

dividends paid.

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~~

Short Term Borrowings

Avista Corp.

Avista Corp. has a committed line of credit with various financial institutions in the total amount of ~~$400.0~~$500 million ~~that expires~~and an expiration date of June 2028, with the option to extend for an additional one year period (subject to customary conditions).

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In December 2022, we entered into a revolving credit agreement in ~~April 2021. As~~the amount of ~~September~~$100 million, which was terminated in June 2023.

In December 2022, we entered into a term loan, in the amount of $150 million with a maturity date of March 30, ~~2017, there were $195.0~~2023. In March 2023, we repaid the $150 million ~~of cash borrowings and $43.9 million in letters~~outstanding balance on the term loan.

In December 2022, we entered into a continuing letter of credit agreement in the aggregate amount of $50 million. Either party may terminate the agreement at any time.

The following table summarizes the balances outstanding ~~(which were primarily issued as collateral for our energy commodity~~ and ~~interest rate swap derivatives), leaving $161.1 million of~~ available liquidity ~~under this line~~as of ~~credit.~~June 30, 2023 (dollars in thousands):


	Amount of Facility		Borrowings Outstanding		Letters of Credit Outstanding (1)		Available Liquidity
Line of Credit expiring June 2028	$	500,000	$	203,000	$	4,638	$	292,362
Letter of Credit Facility		50,000	N/A			16,000		34,000
Total	$	550,000	$	203,000	$	20,638	$	326,362

(1)

Letters of credit are not reflected on the Condensed Consolidated Balance Sheets. If a letter of credit were drawn upon by the holder, we would have an immediate obligation to reimburse the bank that issued that letter.

The Avista Corp. credit ~~facility contains~~facilities contain customary ~~covenants~~covenant and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and, in the case of the letter of credit agreement, other obligations. The committed line of credit agreement also includes a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of ~~September~~June 30, ~~2017,~~2023, we were in compliance with this covenant with a ratio of ~~53.6~~54.8 percent.

Balances outstanding and interest rates of borrowings (excluding letters of credit) under Avista Corp.'s lines of credit were as follows as of and for the six months ended June 30 (dollars in thousands):


	2023			2022
$500 million line of credit, expiring June 2028
Maximum balance outstanding during the period	$	334,500		$	292,000
Average balance outstanding during the period		259,202			156,718
Average interest rate during the period		5.73	%		1.34	%
Average interest rate at end of the period		6.24	%		2.35	%
$100 million line of credit, terminated June 2023
Maximum balance outstanding during the period (1)	$	15,000		N/A
Average balance outstanding during the period (1)		283		N/A
Average interest rate during the period (1)		7.75	%	N/A

(1) Amounts for the period are through the termination date of June 8, 2023.

AEL&P

AEL&P has a $25.0 million committed line of credit that expires in ~~November 2019.~~June 2028. As of ~~September~~June 30, ~~2017,~~2023, 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,”~~&P” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of ~~September~~June 30, ~~2017,~~2023, AEL&P was in compliance with this covenant with a ratio of ~~53.9~~49.4 percent.

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

2017 2016
Borrowings outstanding at end of period $ 195,000
$ 187,000
Letters of credit outstanding at end of period $ 43,853
$ 73,195
Maximum borrowings outstanding during the period $ 195,000
$ 205,000
Average borrowings outstanding during the period $ 123,335
$ 138,296
Average interest rate on borrowings during the period 1.81 % 1.23 %
Average interest rate on borrowings at end of period 1.99 % 1.26 %

~~There were no borrowings outstanding under AEL&P's committed line of credit as of September 30, 2017 and September 30, 2016.~~

As of ~~September~~June 30, ~~2017,~~2023, 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.

~~Equity Issuances~~

See "Note 9 of the Notes to Condensed Consolidated Financial Statements" for ~~a discussion of~~additional information regarding our ~~equity issuances.~~

short-term borrowing arrangements.

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~~2017~~

AVISTA CORPORATION

Liquidity Expectations

~~In September 2017,~~

During March 2023, we ~~entered into a bond purchase agreement to issue $90.0~~issued $250 million of ~~first mortgage bonds in December 2017. No further~~ long-term ~~debt issuances are planned for 2017.~~debt. We ~~intend to use the proceeds, less issuance costs, to refinance on a long-term basis $89.1 million outstanding under our $400.0 million committed line of credit. During the fourth quarter of 2017, we~~do not expect to issue upany additional long-term debt in 2023. We expect to ~~$70.0~~issue $120 million of common stock ~~in order to fund planned capital expenditures and/or repay short-term debt incurred for such purpose.~~

~~In addition, during 2017, we filed income tax refund claims related to 2014 and 2015 to utilize net operating losses and investment tax credits and we received an income tax refund~~(including $59.5 million of ~~approximately $41.7 million~~common stock issued during the ~~fourth quarter of 2017.~~

~~After considering the expected issuances of~~six months ended June 30, 2023). The long-term debt and ~~common stock during~~equity issuances in 2023 was used to decrease existing indebtedness, including the repayment of our $150 million term loan in March 2023, and will be used for the ~~income tax refund during~~construction or improvement of utility facilities throughout the fourth quarter of 2017, we expect net cash flows from operating activities, together with cash available under our committed line of credit agreements, to provide adequate resources to fund capital expenditures, dividends and other contractual commitments.

year.

Capital Expenditures

We are making capital investments ~~in generation, transmission~~to enhance service and ~~distribution systems to preserve and enhance service~~system reliability for our customers and replace aging infrastructure. Our ~~estimated~~ capital ~~expenditures for 2017, 2018 and 2019 have not~~expenditure plans remain materially ~~changed during the nine months ended September 30, 2017.~~consistent with those disclosed in our 2022 Form 10-K. See the ~~2016~~2022 Form 10-K for further ~~information.~~

~~Off-Balance Sheet Arrangements~~

~~As of~~ ~~September 30, 2017, we had~~ ~~$43.9 million~~ ~~in letters of credit outstanding under~~information on our ~~$400.0 million~~ ~~committed line of credit, compared to~~ ~~$34.4 million~~ ~~as of~~ ~~December 31, 2016~~. The increase in outstanding letters of credit is partially related to negotiations with interest rate swap counterparties to accept letters of credit as collateral rather than cash collateral and also due to issuing additional letters of credit as collateral based on changes inexpected capital expenditures.

Pension Plan

Avista Utilities

In the ~~fair value of interest rate swap and energy commodity derivatives during the nine~~six months ended ~~September~~June 30, ~~2017.~~

~~Pension Plan~~

~~Avista Utilities~~

~~In the~~ ~~nine months endedSeptember 30, 2017~~2023 we contributed ~~$22.0~~$6.7 million to the pension ~~plan and we do not expect any further contributions during 2017.~~plan. We expect to contribute a total of ~~$66.0~~$50.0 million to the pension plan in the period ~~2017~~2023 through ~~2021,~~2027, with an annual ~~contributions~~contribution of ~~$(22.0) million over that period.~~

$10.0 million.

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 47 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 nine months ended September 30, 2017. See the 2016 Form 10-K for our contractual obligations.~~

Environmental Issues and Contingencies

Our environmental issues and contingencies disclosures have not materially changed during the six months ended June 30, 2023 except as follows:

Washington Climate Commitment Act (CCA)

The CCA establishes a cap and trade program to reduce greenhouse gas emissions and achieve the greenhouse gas limits previously established under state law. The final rules implement a cap on emissions, provide mechanisms for the ~~following~~sale and tracking of tradable emissions allowances and establish additional compliance and accountability measures. We purchase allowances recorded as inventory, and record emissions obligations and emissions expense associated with sales. As allowances are used and retired, we remove both the inventory and emissions obligation from the balance sheet. The state issues allowances necessary to serve our Washington retail electric load; off-system wholesale sales may result in additional obligation costs. The CCA also has direct impacts on our Idaho electric operations as it applies to power delivered in Washington but is allocated to Idaho customers (wholesale sales) or power generated in Washington that is ultimately delivered to Idaho customers. In May 2023, a model was approved for use in calculating the allowances needed for compliance that assumes hydroelectric generation is first used for wholesale sales, therefore reducing allowances required. As a result, the Act is expected to have minimal financial impact on our electric operations in its initial years. For our Washington natural gas operations, we expect there are additional financial burdens associated with compliance which will be deferred in accordance with our regulatory accounting order in Washington. We are seeking regulatory approval to defer incremental costs related to our Washington and Idaho electric operations.

Washington State Building Codes

In April 2022, the Washington State Building Code Council (SBCC) approved a revised energy code that requires most new commercial buildings and large multifamily buildings to install all-electric space heating. However, an amendment to the code allows for natural gas to supplement electric heat pumps. Additionally, in November 2022, SBCC approved new building and energy codes for residential housing, requiring new residential buildings in Washington to use electricity as the primary heating source. The State Legislature had the opportunity to reject or alter these new codes during their 2023 Regular Session. There was no action by the

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Legislature through the ~~nine months~~regular session that ended ~~September 30, 2017~~. in April 2023, and as such the new codes would have absent further action by the SBCC, gone into effect on July 1, 2023.

In March 2023, 23 petitioners filed suit in Washington State Superior Court challenging the validity of the building and energy code changes. The proceeding remains pending.

On April 17, 2023, the Ninth Circuit issued an opinion in a lawsuit between the California Restaurant Association and the City of Berkeley concerning regulation by the City prohibiting the installation of natural gas piping within newly constructed buildings. In its decision, the Court ruled, among other things, the City’s ordinance was expressly preempted by the federal Energy Policy and Conservation Act (EPCA), which it held encompasses and preempts building codes that purport to regulate natural gas use by covered products. The City of Berkeley has since filed a petition for en banc review of the Court's decision, which remains pending.

On May 22, 2023, the Company, along with 12 other parties, filed suit in the Federal District Court for the Eastern District of Washington, challenging the SBCC’s amendments to the Washington commercial and residential building codes on the grounds that they are also preempted by EPCA. On May 24, 2023, the SBCC voted to delay the effective date of the code amendments at issue by 120 days and commenced an emergency rulemaking process to evaluate additional amendments to the codes in light of the Ninth Circuit’s decision in the Berkeley case. On July 18, 2023, the Court declined to issue a preliminary injunction in the case on the grounds that the rules had been suspended and the SBCC was evaluating potential amendments to the same.

The Company continues to engage in both the rulemaking and the legal process.

See the ~~2016~~2022 Form 10-K for ~~all other~~further discussion of our environmental issues and contingencies.

~~Climate Change - Federal Regulatory Actions~~

The Environmental Protection Agency (EPA) released the final rules for the Clean Power Plan (Final CPP) and the Carbon Pollution Standards (Final CPS) on August 3, 2015. The Final CPP and the Final CPS are both intended to reduce the carbon dioxide (CO2) emissions from certain coal-fired and natural gas electric generating units (EGUs). These rules were published in the Federal Register on October 23, 2015 and were immediately challenged via lawsuits by other parties.

In a separate but related rulemaking, the EPA finalized CO2 new source performance standards (NSPS) for new, modified and reconstructed fossil fuel-fired EGUs under the Clean Air Act (CAA) section 111(b). These EGUs fall into the same two categories of sources regulated by the Final CPP: steam generating units (also known as “utility boilers and IGCC units”), which primarily burn coal, and stationary combustion turbines, which primarily burn natural gas.

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The promulgated and proposed greenhouse gas rulemakings mentioned above have been legally challenged in multiple venues. On February 9, 2016, the U.S. Supreme Court granted a request for stay, halting implementation of the CPP. On March 28, 2017, the Department of Justice has filed a motion with the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) requesting that the Court hold the cases challenging the CPP in abeyance while the EPA reviews the final rules applicable to existing, as well as to new, modified, and reconstructed electric generating units pursuant to an Executive Order issued by President Trump. The Executive Order also instructed the EPA to review the CPP rule. On April 28, 2017 the D.C. Circuit issued orders to hold the litigation regarding the Clean Air Act §111(d) Clean Power Plan and the §111(b) New Source Performance Standards for power plants in abeyance for a period of 60 days with status reports due from the EPA every 30 days. On October 16, 2017, the EPA proposed rule-making to repeal the CPP. Given these ongoing developments, we cannot fully predict the outcome or estimate the extent to which our facilities may be impacted by these regulations at this time. We intend to seek recovery of any costs related to compliance with these requirements through the ratemaking process.

Enterprise Risk Management

The material risks to our businesses, and our mitigation process and procedures to address these risks, were discussed in our ~~2016~~2022 Form 10-K and have not materially changed during the ~~nine~~six months ended ~~September~~June 30, ~~2017, except for strategic risks, which are discussed in further detail below. Refer to~~2023. See the ~~2016~~2022 Form ~~10-K for further discussion of our risks and the mitigation of those risks.~~

10-K.

Financial Risk

Our financial risks have not materially changed during the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2023. Refer to the ~~2016~~

2022 Form 10-K. The financial risks included below are required interim disclosures, even if they have not materially changed from December 31, ~~2016.~~

2022.

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 36 of the Notes to Condensed Consolidated Financial Statements" for a summary of our interest rate swap derivatives outstanding as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016.~~

2022 and the amount of additional collateral we would have to post in certain circumstances.

Credit Risk

~~Avista Utilities' contracts for~~

Under the ~~purchase and sale~~terms of ~~energy commodities can require collateral in the form of~~interest rate swap derivatives, we may be required to post cash or letters of ~~credit.~~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 2022 Form 10-K for further information. As of ~~September~~June 30, ~~2017,~~2023, we had interest rate swap derivatives outstanding with a notional amount totaling $20.0 million and we had no cash deposited as collateral 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 June 30, 2023, we would not be required to post additional collateral because all of our outstanding interest rate swaps were in an asset position at the time.

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As of June 30, 2023, we had cash deposited as collateral ~~in the amount~~ of ~~$19.6~~$55.0 million and letters of credit of ~~$31.5~~$16.0 million outstanding related to our energy ~~derivative~~ contracts. Price movements and/or a downgrade in our credit ratings could impact further the amount of collateral required. See “Credit Ratings” in the ~~2016~~2022 Form 10-K for further information. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below “investment grade” based on our positions outstanding at ~~September~~June 30, ~~2017,~~2023 (including contracts considered derivatives and those considered non-derivatives), we would potentially be required to post ~~up to $6.9 million of~~the following additional collateral. This amount is different from the amount disclosed in “Note 3 of the Notes to Condensed Consolidated Financial Statements” because, while this analysis includes contracts that are not considered derivatives in addition to the contracts considered in Note 3, this analysis takes into account contractual threshold limits that are not considered in Note 3. Without contractual threshold limits, we would potentially be required to post up to $7.6 million of additional collateral.

~~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. As of September 30, 2017, we had interest rate swap derivatives outstanding with a notional amount totaling $450.0 million and we had deposited cash in the amount of $34.4 million and letters of credit of $6.0 million as collateral 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 September 30, 2017, we would be required to post up to $12.7 million of additional collateral.

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(in thousands):


	June 30, 2023
Additional collateral taking into account contractual thresholds	$	6,839
Additional collateral without contractual thresholds		10,846

Energy Commodity Risk

Our energy commodity risks have not materially changed during the ~~nine~~six months ended ~~September~~June 30, ~~2017, except as discussed below. Refer to~~2023. See the ~~2016~~2022 Form 10-K. The following table presents energy commodity derivative fair values as a net asset or (liability) as of ~~September~~June 30, ~~2017 that are~~2023 expected to settle in each respective year (dollars in thousands):

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 2017 $ (3,125 ) $ (320 ) $ (1,938 ) $ (15,176 ) $ 56
$ 1,246
$ (209 ) $ 5,803
2018 (8,488 ) (921 ) (6 ) (16,557 ) (8 ) 4,530
(785 ) 7,811
2019 (5,039 ) (1,439 ) (324 ) (7,938 ) (4 ) 4,935
(778 ) 2,766
2020 —
—
(346 ) (469 ) —
83
(1,067 ) —
2021 —
—
—
—
—
—
(668 ) —
Thereafter —
—
—
—
—
—
—
—

. There are no expected deliveries of energy commodity derivatives after 2026.


	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 2023	$	532	$	345	$	(152	)	$	(11,715	)	$	(1,346	)	$	(2,840	)	$	(2,456	)	$	(8,132	)
2024		—		—		(587	)		(11,948	)		136			(898	)		(6,479	)		(7,338	)
2025		—		—		(998	)		(1,988	)		—			269			(2,834	)		(886	)
2026		—		—		(206	)		(47	)		—			—			—			—

The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, ~~2016 that are~~2022 expected to be delivered in each respective year (dollars in thousands):

. There were 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)
2023	$	1,120	$	—	$	(33,150	)	$	62,753		$	(2,374	)	$	(20,018	)	$	17,166		$	(137,585	)
2024		—		—		162			(3,879	)		—			—			(4,968	)		(5,790	)
2025		—		—		135			(220	)		—			—			(2,924	)		(701	)

(1)

Physical transactions represent commodity transactions where 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.

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)
2017 $ (4,274 ) $ 1,939
$ 97
$ (4,005 ) $ (225 ) $ 576
$ (2,036 ) $ (3,440 )
2018 (5,598 ) —
—
(2,170 ) (33 ) 854
(910 ) 709
2019 (3,123 ) —
(235 ) (3,732 ) (40 ) 975
(927 ) 103
2020 —
—
(266 ) (370 ) —
—
(1,288 ) —
2021 —
—
—
—
—
—
(869 ) —
Thereafter —
—
—
—
—
—
—
—


~~(1)~~	Physical transactions represent commodity transactions where 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.

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.

~~Strategic Risk~~

In July 2017, we entered into a Merger Agreement with Hydro One, which added additional strategic risk for Avista Corp. and its shareholders. See "Part II. Other Information; Item 1A Risk Factors" for a detailed discussion of such strategic risk. For further information on the acquisition, see “Notes 11 and 13 of the Notes to Condensed Consolidated Financial Statements.”

Future Resource Needs

~~2017 Electric~~

2023 Natural Gas Integrated Resource Plan

In ~~August 2017,~~March 2023, we filed our ~~2017 Electric~~2023 Natural Gas Integrated Resource Plan(IRP) with the ~~UTC~~WUTC, IPUC and ~~the IPUC.~~OPUC. The ~~UTC and IPUC~~state commissions review the IRPs and give the public the opportunity to comment. The ~~UTC and IPUC~~state commissions 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. The IRP details projected growth in demand for energy and the new resources needed to serve customers over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project.

standards.

Highlights of the ~~2017~~2023 Natural Gas IRP include the ~~following expectations and/or assumptions:~~

following:

~~Our current generation~~•

We anticipate having sufficient natural gas resources ~~will remain cost effective and reliable sources of power~~ to meet ~~future~~expected loads, including in Idaho where customer ~~needs over~~growth is highest, with our current transportation contracts for natural gas.

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•

Customer forecasts are increasingly difficult to model due to a variety of recently passed rules and codes, including building code updates in Washington.

•

Emissions compliance with the CCA in Washington and Climate Protection Plan in Oregon greatly impact our resource strategy, including the use of renewable natural gas, synthetic methane, and credits or allowances.

•

Our Idaho preferred resource strategy continues to utilize a least cost basis.

We will monitor these assumptions on an on-going basis and adjust our resource requirements accordingly.

We are required to file a natural gas IRP every two years and we anticipate our next ~~20 years.~~

~~Energy storage costs are significantly lower than those assumed~~IRP to be filed in 2025.

2023 Electric Integrated Resource Plan

In June 2023, we filed our 2023 Electric IRP with the WUTC and IPUC. The state commissions review the IRPs and give the public the opportunity to comment. The state commissions do not approve or disapprove of the content in the ~~2015 IRP, which, for~~IRPs; rather they acknowledge the ~~first time, makes the energy storage technology operationally attractive~~IRPs are prepared in ~~meeting energy needs in the 20-year timeframe~~accordance with applicable standards.

Highlights of the ~~2017 IRP.~~

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~~We are working to enter into a power purchase agreement related to a solar facility of at least 15 MW for our new Solar Select Program for commercial and industrial customers.~~

~~We estimate that conservation will effectively provide approximately 53.3 percent of the requirements of future load growth.~~

~~Colstrip will remain a cost effective and reliable source of power to meet future customer needs.~~

~~If Colstrip were retired in 2030, customer bills would increase approximately $50.0 million in the first year following retirement.~~

~~Major changes from the 2015~~2023 Electric IRP include the ~~following expectations and/or assumptions:~~

following:

•

The ~~2017 Expected Case~~forecast for growth in energy ~~forecast will grow at 0.47~~requirements is 0.9 percent per year, ~~replacing~~higher than the ~~0.6~~0.2 percent annual growth rate in the ~~2015~~2021 IRP. Higher growth largely reflects higher residential and commercial electric vehicle forecasts and new building electrification.

~~Peak load growth will be lower than energy growth,~~•

We announced several resource acquisitions and an expected divestiture (Colstrip at ~~0.42 percent for the winter and 0.46 percent for the summer.~~

~~Lower expected load growth combined with recent Mid-Columbia hydroelectric contracts, energy efficiency, and demand response will delay the need for additional resources from~~ the end of ~~2020 until 2026.~~2025) since our 2021 IRP.

•

~~Demand response~~ ~~(temporarily reducing~~The resource strategy selected in the ~~demand for energy)~~IRP is designed to achieve an 80 percent reduction in greenhouse gas emissions by 2045.

•

We need long-duration storage to serve customers in peak hours after 2035.

•

We created a ~~viable strategy for meeting future~~Named Community Investment Fund to increase energy-related investments in disadvantaged communities. The fund will increase distributed energy ~~needs~~resources such as energy efficiency, small-scale renewables, and energy ~~storage~~storage.

We will monitor these assumptions on an on-going basis and ~~solar have been added as future resources.~~

~~We expect lower emissions from Avista Corp. owned and controlled resources due to lower utilization of natural-gas fired peaking plants and no new combined-cycle plants.~~

adjust our resource requirements accordingly.

We are required to file an electric IRP every two years ~~with the~~and we anticipate our next IRP ~~expected~~ to be filed ~~during the third quarter of 2019. Our resource strategy may change from the 2017 IRP based on market, legislative and regulatory developments.~~

We are subject to the Washington state Energy Independence Act, which requires us to obtain a portion of our electricity from qualifying renewable resources or through purchase of RECs and acquiring all cost effective conservation measures. Future generation resource decisions will be affected by legislation for restrictions on greenhouse gas emissions and renewable energy requirements.

in 2025.

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

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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 ~~September~~June 30, ~~2017~~.

2023.

There have been no changes in the Company's internal control over financial reporting that occurred during the ~~third~~second quarter of ~~2017~~2023 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 1116 of Notes to Condensed Consolidated Financial Statements” in “Part I. Financial Information Item 1. Condensed Consolidated Financial Statements.”

Item 1A. Risk Factors

~~Please refer~~

Refer to the ~~2016~~2022 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 ~~2016~~2022 Form 10-K ~~except for~~with the exception of the following:

~~RISKS RELATED TO THE PROPOSED ACQUISITION BY HYDRO ONE~~

~~The Conditions~~

Our technology may become obsolete, development of new technologies could create additional risk, or we may not have sufficient resources to manage our technology.

Our technology may become obsolete before the ~~Acquisition May Not Be Satisfied.~~

~~The proposed acquisition~~end of its useful life. In addition, custom or new technology (including potential generative artificial intelligence) that is heavily relied upon by Hydro One requires approval by the holders of a majority of Avista Corp.'s outstanding shares of common stock and the receipt of regulatory approvals, including from the FERC, the CFIUS, the FCC, the UTC, IPUC, MPSC, OPUC, and the RCA. Such approvalsus or our counterparties may not be ~~obtained~~maintained and updated appropriately due to resource restraints, or ~~the regulatory bodies may seek to impose conditions on the completion of the transaction,~~other factors, which could cause ~~the conditions specified in the Merger Agreement~~technology failures or give rise to ~~not be satisfied~~additional operational or ~~which~~security risks. Generative artificial intelligence could ~~delay~~ also create additional regulatory scrutiny and generate uncertainty around intellectual property ownership and/or ~~increase the cost of the transaction. In addition, the failure to satisfy other closing conditions~~licensing or use. Technology failures could result in ~~a termination of the Merger Agreement by Hydro One and/or Avista Corp.~~

~~Termination Fee.~~

Upon termination of the Merger Agreement under certain specified circumstances, we would be required to pay Hydro One a Termination Fee of $103.0 million. We would also be required to pay Hydro One the Termination Fee in the event that we signed or consummated any specified alternative transaction within twelve months following the termination of the Merger Agreement under certain circumstances. Any fees due as a result of termination could have a materialsignificant adverse ~~effect~~effects on our operations, results of operations, financial condition and cash flows.

~~Market Value~~

Item 5. Other Information

During the fiscal quarter ended June 30, 2023, none of ~~Avista Corp. Common Stock; Access to Capital; Other~~

~~There can be no assurance that the Merger will be consummated. Failure to consummate the Merger could (i) affect the value of Avista Corp.'s common stock, including by reducing it to a level at~~our directors or ~~below the trading range preceding the announcement~~officers informed us of the ~~Merger Agreement and (ii) negatively affect our access to and cost~~adoption or termination of ~~both equity and debt financing.~~

~~Additionally, if the Merger is not consummated, we would have incurred significant costs and diverted the time and attention~~a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as those terms are defined in Regulation S-K, Item 408.

Table of management. A failure to consummate the Merger might also result in negative publicity, litigation against Avista Corp. or its directors and officers, and a negative impression of Avista Corp. in the financial markets. The occurrence of any of these events individually or in combination could have a material adverse effect on our financial condition, results of operations, cash flows and stock price.

~~Legal Proceedings Related to the Pending Acquisition by Hydro One.~~

In connection with the proposed acquisition, as of the date of this quarterly report, three lawsuits have been filed in the United States District Court for the Eastern District of Washington and one lawsuit has been filed in the Superior Court for the State of Washington in and for Spokane County. These lawsuits were filed against members of the Company's Board of Directors and various other parties.

The complaints generally allege, among other things, that the members of the Board breached their fiduciary duties by, among other things, conducting an allegedly inadequate sale process and agreeing to the acquisition at a price that allegedly undervalues Avista Corporation. The complaints also allege misstatements and omissions of material facts in the Company's proxy soliciting materials relating to the special meeting of shareholders to be held November 21, 2017 to approve the acquisition. The complaints seek various remedies, including an injunction against the acquisition and monetary damages, including attorneys’ fees and expenses.

The outcome of these lawsuits could, among other things, result in the termination of the Merger Agreement and/or a material adverse effect on our financial condition, results of operations, cash flows and stock price.

~~In addition to these risk factors, see a~~lso “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.

Contents

~~Item 2. Unregistered Sales of Equity Securities and Use of Proceeds~~


~~(a)~~	~~Not applicable~~


~~(b)~~	~~Not applicable~~


~~(c)~~	~~Not applicable~~

~~Dividend Restrictions~~

~~The restrictions on the payment of dividends on common stock have not materially changed during the nine months ended September 30, 2017 except for the following:~~

As a result of the Merger Agreement with Hydro One, Avista Corp. cannot (A) declare, authorize, set aside for payment or pay any dividend on, or make any other distribution in respect of, any shares of its capital stock, other than (1) dividends paid by any Subsidiary of the Company to the Company or to any wholly owned Subsidiary of the Company, (2) quarterly cash dividends with respect to the Company Common Stock not to exceed the current annual per share dividend rate by more than $0.06 per year, with record dates and payment dates consistent with the Company’s current dividend practice, or (3) a “stub period” dividend to holders of record of Company Common Stock as of immediately prior to the Effective Time equal to the product of (x) the number of days from the record date for payment of the last quarterly dividend paid by the Company prior to the Effective Time, multiplied by (y) a daily dividend rate determined by dividing the amount of the last quarterly dividend prior to the Effective Time by ninety-one or (B) adjust, split, combine, subdivide or reclassify any shares of its capital stock.

For further information regarding limitations surrounding the conduct of Avista Corp.'s business as a result of the pending acquisition, see Section 5 of the Merger Agreement, which was filed as Exhibit 2.1 to Avista Corp.’s Current Report on Form 8-K filed with the SEC on July 19, 2017. See the 2016 Form 10-K for further information on other restrictions on the payment of dividends on common stock.

~~Item 4. Mine Safety Disclosures~~

~~Not applicable.~~

AVISTA CORPORATION

Item 6. Exhibits



~~2.1~~15		~~Agreement and Plan of Merger, dated as of July 19, 2017, by and among Avista Corporation, Hydro One Limited, Olympus Holding Corp. and Olympus Corp. (1)~~
12		~~Computation of ratio of earnings to fixed charges (2)~~
15		Letter Re: Unaudited Interim Financial Information ~~(2)~~(1)
~~31.1~~
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) ~~(2)~~(1)
~~31.2~~
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) ~~(2)~~(1)
32
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) ~~(3)~~(2)
~~101~~		The following financial information from the Quarterly Report on Form 10−Q for the period ended September 30, 2017, formatted in XBRL (Extensible Business Reporting Language) and filed electronically herewith: (i) the Condensed Consolidated Statements of Income; (ii) Condensed Consolidated Statements of Comprehensive Income; (iii) the Condensed Consolidated Balance Sheets; (iv) the Condensed Consolidated Statements of Cash Flows; (v) the Condensed Consolidated Statements of Equity; and (vi) the Notes to Condensed Consolidated Financial Statements. (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.
(1 101.SCH	)	~~Previously filed as exhibit 2.1 to the registrant's Current Report on Form 8-K, filed as of July 19, 2017 and incorporated herein by reference.~~ Inline XBRL Taxonomy Extension Schema Document
(2 101.CAL	)	~~Filed herewith.~~ Inline XBRL Taxonomy Extension Calculation Linkbase Document
(3 101.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.

Table of Contents

~~AVISTA CORPORATION~~

AVISTA CORPORATION

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:	~~October 31, 2017~~ August 1, 2023	/s/ ~~Mark T. Thies~~ Kevin J. Christie
		~~Mark T. Thies~~ Kevin J. Christie
		Senior Vice President, Chief Financial Officer, Treasurer and ~~Treasurer~~ Regulatory Affairs Officer (Principal Financial Officer)



Washington		91-0462470
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

~~1411 East Mission Avenue, Spokane, Washington~~		~~99202-2600~~
~~(Address of principal executive offices)~~		~~(Zip Code)~~


Title of Each Class		Trading Symbol(s)		Name of Each Exchange on Which Registered
~~None~~ Common Stock
~~(Former name, former address and former fiscal year, if changed since last report)~~	AVA		New York Stock Exchange



Large accelerated filer	x ☒	Accelerated filer	¨ ☐
Non-accelerated filer	¨ ~~(Do not check if a smaller reporting company)~~ ☐	Smaller reporting company	¨ ☐
Emerging growth company	¨ ☐



Item No.		Page No.

	~~Forward-Looking Statements~~Acronyms and Terms	1 iii
	~~Available Information~~Forward-Looking Statements	4 1
	Available Information	5
Part I. Financial Information
Item 1.	Condensed Consolidated Financial Statements	5 6
	Condensed Consolidated Statements of Income - Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022	5 6
	Condensed Consolidated Statements of Comprehensive ~~Income -~~ Income- Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022	6 7
	Condensed Consolidated Balance Sheets - ~~September~~ June 30, ~~2017~~2023 and December 31, ~~2016~~2022	7 8
	Condensed Consolidated Statements of Cash Flows - ~~Nine~~ Six Months Ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022	9
	Condensed Consolidated Statements of Equity - ~~Nine~~ Three and Six Months Ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022	11
	Notes to Condensed Consolidated Financial Statements	12
	Note 1. Summary of Significant Accounting Policies	12
	Note 2. New Accounting Standards	14 13
	Note 3. Balance Sheet Components	14
	Note 4. Revenue	16
	Note 5. Leases	19
	Note 6. Derivatives and Risk Management	16 20
	Note 4.7. Pension Plans and Other Postretirement Benefit Plans	21 23
	Note ~~5. Committed Lines of Credit~~8. Income Taxes	22 24
	Note ~~6. Long-Term Debt and Capital Leases~~9. Short-Term Borrowings	23 25
	Note 7.10. Long Term Debt	26
	Note 11. Long-Term Debt to Affiliated Trusts	24 26
	Note 8.12. Fair Value	24 27
	Note 9.13. Common Stock	29 32
	Note ~~10.~~14. Accumulated Other Comprehensive Loss	32
	Note 15. Earnings per Common Share ~~Attributable to Avista Corporation Shareholders~~	30 33
	Note ~~11.~~16. Commitments and Contingencies	30 33
	Note ~~12.~~17. Information by Business Segments	32 37
	~~Note 13. Pending Acquisition by Hydro One~~	33
	Report of Independent Registered Public Accounting Firm	36 39

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37 40
	Business Segments	37 40
	Executive ~~Level Summary~~Overview	37 40
	Regulatory Matters	38 41
	Results of Operations - Overall	44
	Non-GAAP Financial Measures	47 46


Acronym/Term	Meaning
~~AVISTA CORPORATION~~ 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
CCA	-	Climate Commitment Act
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 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
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



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

	FOR THE QUARTERLY PERIOD ENDED June 30, 2023 OR



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

	FOR THE TRANSITION PERIOD FROM TO



	Environmental Issues and Other Contingencies	62
	Enterprise Risk Management	63
	~~Future Resource Needs~~	64

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	65

Item 4.	Controls and Procedures	65

Part II. Other Information
Item 1.	Legal Proceedings	65 67

Item 1A.	Risk Factors	65 67

Item 2.6.	~~Unregistered Sales of Equity Securities and Use of Proceeds~~Exhibits	65 68

~~Item 4.~~	~~Mine Safety Disclosures~~Signature	65

~~Item 6.~~	~~Exhibits~~	65

	~~Signature~~	66 69


MPSC	-	Public Service Commission of the State of Montana
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
SOFR	-	Secured Overnight Financing Rate
Talen	-	Talen Montana, LLC, an indirect subsidiary of Talen Energy Corporation.
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



	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
Operating Revenues:
Utility revenues	$	291,640		$	296,989		$	1,030,906		$	1,022,670
Non-utility revenues	5,456			6,360			17,161			17,690
Total operating revenues	297,096			303,349			1,048,067			1,040,360
Operating Expenses:
Utility operating expenses:
Resource costs	108,568			118,737			376,905			390,271
Other operating expenses	77,784			75,160			232,959			229,605
Acquisition costs	6,730			—			8,004			—
Depreciation and amortization	42,968			40,240			127,596			119,110
Taxes other than income taxes	23,269			22,669			79,733			74,669
Non-utility operating expenses:
Other operating expenses	6,598			6,756			19,863			18,862
Depreciation and amortization	137			193			482			573
Total operating expenses	266,054			263,755			845,542			833,090
Income from operations	31,042			39,594			202,525			207,270
Interest expense	23,955			21,632			71,170			64,223
Interest expense to affiliated trusts	216			164			601			456
Capitalized interest	(899		)	(507		)	(2,513		)	(2,258		)
Other income-net	(1,841		)	(1,562		)	(6,598		)	(7,025		)
Income before income taxes	9,611			19,867			139,865			151,874
Income tax expense	5,153			7,606			51,548			54,661
Net income	4,458			12,261			88,317			97,213
Net loss (income) attributable to noncontrolling interests	(7		)	(27		)	21			(76		)
Net income attributable to Avista Corp. shareholders	$	4,451		$	12,234		$	88,338		$	97,137
Weighted-average common shares outstanding (thousands), basic	64,412			63,857			64,392			63,282
Weighted-average common shares outstanding (thousands), diluted	64,892			64,325			64,638			63,687

Earnings per common share attributable to Avista Corp. shareholders:
Basic	$	0.07		$	0.19		$	1.37		$	1.53
Diluted	$	0.07		$	0.19		$	1.37		$	1.53
Dividends declared per common share	$	0.3575		$	0.3425		$	1.0725		$	1.0275



	September 30,		December 31,
	2017		2016
Assets:
Current Assets:
Cash and cash equivalents	$	14,716	$	8,507
Accounts and notes receivable-less allowances of $4,838 and $5,026, respectively	125,595		180,265
Regulatory asset for energy commodity derivatives	22,005		11,365
Materials and supplies, fuel stock and stored natural gas	65,961		53,314
Income taxes receivable	42,111		48,265
Other current assets	46,246		49,625
Total current assets	316,634		351,341
Net Utility Property:
Utility plant in service	5,686,633		5,506,499
Construction work in progress	194,679		150,474
Total	5,881,312		5,656,973
Less: Accumulated depreciation and amortization	1,578,148		1,509,473
Total net utility property	4,303,164		4,147,500
Other Non-current Assets:
Investment in affiliated trusts	11,547		11,547
Goodwill	57,672		57,672
Other property and investments-net and other non-current assets	80,022		72,224
Total other non-current assets	149,241		141,443
Deferred Charges:
Regulatory assets for deferred income tax	123,449		109,853
Regulatory assets for pensions and other postretirement benefits	230,988		240,114
Other regulatory assets	129,112		135,751
Regulatory asset for interest rate swaps	170,079		161,508
Non-current regulatory asset for energy commodity derivatives	16,371		16,919
Other deferred charges	13,194		5,326
Total deferred charges	683,193		669,471
Total assets	$	5,452,232	$	5,309,755



Balance Sheet Date	Number of Contracts	Notional Amount		Mandatory Cash Settlement Date
September 30, 2017	14	$	275,000	2018
	6	70,000		2019
	3	30,000		2020
	1	15,000		2021
	5	60,000		2022
December 31, 2016	6	$	75,000	2017
	14	275,000		2018
	6	70,000		2019
	2	20,000		2020
	5	60,000		2022



	Fair Value as of September 30, 2017
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current liabilities	$	—	$	(51	)	$	—	$	(51	)
Interest rate swap derivatives
Other current assets	2,637		(249		)	—		2,388
Other property and investments-net and other non-current assets	5,346		(1,896		)	—		3,450
Current interest rate swap derivative liabilities	—		(63,074		)	28,554		(34,520		)
Non-current interest rate swap derivative liabilities	—		(7,136		)	5,806		(1,330		)
Energy commodity derivatives
Other current assets	197		(70		)	—		127
Current energy commodity derivative liabilities	23,904		(46,036		)	11,078		(11,054		)
Other non-current liabilities, regulatory liabilities and deferred credits	13,891		(30,262		)	4,569		(11,802		)
Total derivative instruments recorded on the balance sheet	$	45,975	$	(148,774	)	$	50,007	$	(52,792	)



	Fair Value as of December 31, 2016
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current liabilities	$	5	$	(28	)	$	—	$	(23	)
Interest rate swap derivatives
Other current assets	3,393		—			—		3,393
Other property and investments-net and other non-current assets	5,754		(397		)	—		5,357
Current interest rate swap derivative liabilities	—		(15,756		)	9,731		(6,025		)
Non-current interest rate swap derivative liabilities	3,951		(57,825		)	25,169		(28,705		)
Energy commodity derivatives
Other current assets	18,682		(16,787		)	—		1,895
Current energy commodity derivative liabilities	16,335		(29,598		)	6,228		(7,035		)
Other non-current liabilities, regulatory liabilities and deferred credits	13,071		(29,990		)	3,630		(13,289		)
Total derivative instruments recorded on the balance sheet	$	61,191	$	(150,381	)	$	44,758	$	(44,432	)



	Pension Benefits						Other Post-retirement Benefits
	2017			2016			2017			2016
Three months ended September 30:
Service cost	$	5,092		$	4,567		$	799		$	806
Interest cost	6,976			6,895			1,374			1,530
Expected return on plan assets	(7,900		)	(6,887		)	(475		)	(465		)
Amortization of prior service cost	—			1			(274		)	(300		)
Net loss recognition	2,517			2,161			1,168			1,453
Net periodic benefit cost	$	6,685		$	6,737		$	2,592		$	3,024
Nine months ended September 30:
Service cost	$	15,226		$	13,655		$	2,422		$	2,389
Interest cost	20,903			20,695			4,147			4,623
Expected return on plan assets	(23,700		)	(20,512		)	(1,425		)	(1,415		)
Amortization of prior service cost	—			1			(898		)	(924		)
Net loss recognition	7,380			6,252			3,761			4,312
Net periodic benefit cost	$	19,809		$	20,091		$	8,007		$	8,985



Maturity Year	Description	Interest Rate	September 30, 2017			December 31, 2016
Avista Corp. Secured Long-Term Debt
2018	First Mortgage Bonds	5.95%	$	250,000		$	250,000
2018	Secured Medium-Term Notes	7.39%-7.45%	22,500			22,500
2019	First Mortgage Bonds	5.45%	90,000			90,000
2020	First Mortgage Bonds	3.89%	52,000			52,000
2022	First Mortgage Bonds	5.13%	250,000			250,000
2023	Secured Medium-Term Notes	7.18%-7.54%	13,500			13,500
2028	Secured Medium-Term Notes	6.37%	25,000			25,000
2032	Secured Pollution Control Bonds (1)	(1)	66,700			66,700
2034	Secured Pollution Control Bonds (1)	(1)	17,000			17,000
2035	First Mortgage Bonds	6.25%	150,000			150,000
2037	First Mortgage Bonds	5.70%	150,000			150,000
2040	First Mortgage Bonds	5.55%	35,000			35,000
2041	First Mortgage Bonds	4.45%	85,000			85,000
2044	First Mortgage Bonds	4.11%	60,000			60,000
2045	First Mortgage Bonds	4.37%	100,000			100,000
2047	First Mortgage Bonds	4.23%	80,000			80,000
2051	First Mortgage Bonds	3.54%	175,000			175,000
	Total Avista Corp. secured long-term debt		1,621,700			1,621,700
Alaska Electric Light and Power Company Secured Long-Term Debt
2044	First Mortgage Bonds	4.54%	75,000			75,000
	Total secured long-term debt		1,696,700			1,696,700
Alaska Energy and Resources Company Unsecured Long-Term Debt
2019	Unsecured Term Loan	3.85%	15,000			15,000
	Total secured and unsecured long-term debt		1,711,700			1,711,700
Other Long-Term Debt Components
	Capital lease obligations		62,969			65,435
	Unamortized debt discount		(668		)	(792		)
	Unamortized long-term debt issuance costs		(9,986		)	(10,639		)
	Committed line of credit to be refinanced on a long-term basis (2)		89,100			—
	Total		1,853,115			1,765,704
	Secured Pollution Control Bonds held by Avista Corporation (1)		(83,700		)	(83,700		)
	Current portion of long-term debt and capital leases		(277,626		)	(3,287		)
	Total long-term debt and capital leases		$	1,491,789		$	1,678,717



	Fair Value (Net) at
	September 30, 2017			Valuation Technique	Unobservable Input	Range
Power exchange agreement	$	(16,654	)	Surrogate facility pricing	O&M charges	$38.87-$45.20/MWh (1)
					Escalation factor	5% - 2018 to 2019
					Transaction volumes	396,984 - 432,357 MWhs
Power option agreement	$	(12	)	Black-Scholes- Merton	Strike price	$34.85/MWh - 2019
					Strike price	$47.54/MWh - 2018
					Delivery volumes	157,517 - 222,683 MWhs
Natural gas exchange agreement	$	(3,599	)	Internally derived weighted average cost of gas	Forward purchase prices	$1.70 - $2.24/mmBTU
					Forward purchase prices	$1.70 - $2.24/mmBTU
					Forward sales prices	$1.63 - $3.20/mmBTU
					Purchase volumes	115,000 - 310,000 mmBTUs
					Sales volumes	60,000 - 310,000 mmBTUs



	Avista Utilities		Alaska Electric Light and Power Company		Total Utility		Other			Intersegment Eliminations (1)			Total
For the three months ended September 30, 2017:
Operating revenues	$	280,776	$	10,864	$	291,640	$	5,456		$	—		$	297,096
Resource costs	104,516		4,052		108,568		—			—			108,568
Other operating expenses (2)	81,045		3,469		84,514		6,598			—			91,112
Depreciation and amortization	41,516		1,452		42,968		137			—			43,105
Income (loss) from operations	31,023		1,298		32,321		(1,279		)	—			31,042
Interest expense (3)	23,132		895		24,027		215			(71		)	24,171
Income taxes	5,972		44		6,016		(863		)	—			5,153
Net income (loss) attributable to Avista Corp. shareholders	5,419		427		5,846		(1,395		)	—			4,451
Capital expenditures (4)	109,066		1,073		110,139		1,050			—			111,189



	Electric				Natural Gas
Effective Date	Proposed Revenue Increase		Proposed Base Rate Increase		Proposed Revenue Increase		Proposed Base Rate Increase
May 1, 2018	$	61.4	12.5	%	$	8.3	9.3	%
May 1, 2019 (1)	$	14.0	2.5	%	$	4.2	4.4	%
May 1, 2020 (1)	$	14.4	2.5	%	$	4.4	4.4	%



	Electric Operating Revenues
	2017			2016
Washington
Decoupling surcharge (rebate)	$	(4,092	)	$	266
Provision for earnings sharing	—			355
Idaho
Decoupling rebate	$	(918	)	$	(515	)



	Natural Gas Operating Revenues
	2017			2016
Washington
Decoupling surcharge (rebate)	$	(45	)	$	376
Provision for earnings sharing (rebate)	(207		)	177
Idaho
Decoupling rebate	$	(30	)	$	(82	)
Oregon
Decoupling surcharge	$	350		$	486



	Electric Customers		Natural Gas Customers
	2017	2016	2017	2016
Residential	334,274	330,435	306,706	300,168
Commercial	42,241	41,830	35,087	34,792
Interruptible	—	—	37	35
Industrial	1,336	1,340	253	256
Public street and highway lighting	577	559	—	—
Total retail customers	378,428	374,164	342,083	335,251