UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)



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

FOR THE QUARTERLY PERIOD ENDED March 31, ~~2019~~2020 OR



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

FOR THE TRANSITION PERIOD FROM TO

Commission file number 1-3701

AVISTA CORPORATION

(Exact name of Registrant as specified in its charter)



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

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

1411 East Mission Avenue, Spokane, Washington99202-2600

(Address of principal executive offices, including zip code)

Registrant’s telephone number, including area code: ~~509-489-0500~~

~~Web site: http://www.myavista.com~~509-489-0500

None

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

Securities registered pursuant to Section 12(b) of the Act:



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

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

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

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



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

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

Exchange Act ¨☐

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

As of ~~April 29, 2019~~May 1, 2020, ~~65,750,156~~67,293,360 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

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INDEX



Item No.		Page No.

	Acronyms and Terms	iii
	Forward-Looking Statements	1
	Available Information	4
Part I. Financial Information
Item 1.	Condensed Consolidated Financial Statements	5
	Condensed Consolidated Statements of Income - Three Months Ended March 31, ~~2019~~2020 and ~~2018~~2019	5
	Condensed Consolidated Statements of Comprehensive Income - Three Months Ended March 31, ~~2019~~2020 and ~~2018~~2019	6
	Condensed Consolidated Balance Sheets - March 31, ~~2019~~2020 and December 31, ~~2018~~2019	7
	Condensed Consolidated Statements of Cash Flows - Three Months Ended March 31, ~~2019~~2020 and ~~2018~~2019	8
	Condensed Consolidated Statements of Equity - Three Months Ended March 31, ~~2019~~2020 and ~~2018~~2019	10
	Notes to Condensed Consolidated Financial Statements	11
	Note 1. Summary of Significant Accounting Policies	11
	Note 2. New Accounting Standards	12
	Note 3. Balance Sheet Components	13
	Note 4. Revenue	15
	Note 5. ~~Leases~~Derivatives and Risk Management	18
	Note 6. ~~Derivatives and Risk Management~~	21
	~~Note 7.~~ Pension Plans and Other Postretirement Benefit Plans	2522
	Note 8.7. Income Taxes	2623
	Note 9.8. Committed Lines of Credit	2623
	Note 9. Credit Agreement	23
	Note 10. Long-Term Debt to Affiliated Trusts	2624
	Note 11. Fair Value	24
	Note 12. Common Stock	27
	Note ~~12.~~13. Accumulated Other Comprehensive Loss	27
	Note 14. Earnings per Common ~~Stock~~Share Attributable to Avista Corporation Shareholders	28
	Note 15. Commitments and Contingencies	28
	Note 16. Information by Business Segments	29
	Note 17. Termination of Proposed Acquisition by Hydro One	30
	Note 18. Sale of METALfx	31
	~~Note 13. Accumulated Other Comprehensive Loss~~	31
	~~Note 14. Earnings per Common Share Attributable to Avista Corporation Shareholders~~	32
	~~Note 15. Commitments and Contingencies~~	32
	~~Note 16. Information by Business Segments~~	33
	~~Note 17. Termination of Proposed Acquisition by Hydro One~~	34
	~~Note 18. Assets Held for Sale~~	36
	Report of Independent Registered Public Accounting Firm	3732

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
	Business Segments	33
	Executive Level Summary	33
	Regulatory Matters	35
	Results of Operations - Overall	38
	~~Business Segments~~	38
	~~Executive Level Summary~~	38
	~~Regulatory Matters~~Non-GAAP Financial Measures	39
	Results of Operations - ~~Overall~~Avista Utilities	4339
	~~Non-GAAP Financial Measures~~	44
	~~Results of Operations - Avista Utilities~~	44
	Results of Operations - Alaska Electric Light and Power Company	5046
	Results of Operations - Other Businesses	5146
	Critical Accounting Policies and Estimates	5146
	Liquidity and Capital Resources	5146
	Overall Liquidity	5146

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ACRONYMS AND TERMS

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



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

iii

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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

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ROR	-	Rate of return on rate base
ROU	-	Right-of-use lease asset
SEC	-	U.S. Securities and Exchange Commission
TCJA	-	The "Tax Cuts and Jobs Act," signed into law on December 22, 2017
Therm	-	Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy)
Watt	-	Unit of measurement ~~for electricity;~~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

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Forward-Looking Statements

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

financial performance;

cash flows;

capital expenditures;

dividends;

capital structure;

other financial items;

strategic goals and objectives;

business environment; and

plans for operations.

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

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

~~Financial Risk~~

weather conditions, which affect both energy demand and electric generating capability, including the impact of precipitation and temperature on hydroelectric resources, the impact of wind patterns on wind-generated power, weather-sensitive customer demand, and similar impacts on supply and demand in the wholesale energy markets;

our ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including our credit ratings, interest rates, other capital market conditions and global economic conditions;

changes in interest rates that affect borrowing costs, our ability to effectively hedge interest rates for anticipated debt issuances, variable interest rate borrowing and the extent to which we recover interest costs through retail rates collected from customers;

changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which can affect future funding obligations, pension and other postretirement benefit expense and the related liabilities;

~~deterioration in the creditworthiness of our customers;~~

~~the outcome of legal proceedings and other contingencies;~~

~~economic conditions in our service areas, including the economy's effects on customer demand for utility services;~~

~~declining energy demand related to customer energy efficiency, conservation measures and/or increased distributed generation;~~

changes in the long-term global climate and the long-term climate within our utilities' service areas, which can affect, among other things, customer demand patterns, the volume and timing of streamflows to our hydroelectric resources, as well as increased risk of severe weather or natural disasters, including wildfires;

~~industry and geographic concentrations which may increase our exposure to credit risks due to counterparties, suppliers and customers being similarly affected by changing conditions;~~

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Utility Regulatory Risk

state and federal regulatory decisions or related judicial decisions that affect our ability to recover costs and earn a reasonable return including, but not limited to, disallowance or delay in the recovery of capital investments, operating costs, commodity costs, interest rate swap derivatives, the ordering of refunds to customers and discretion over allowed return on investment;

the loss of regulatory accounting treatment, which could require the write-off of regulatory assets and the loss of regulatory deferral and recovery mechanisms;

~~Energy Commodity~~Operational Risk

~~volatility~~pandemics (including the current COVID-19 pandemic), which could disrupt our business, as well as the global, national and illiquidity in wholesale energy markets, including exchanges, the availability of willing buyers and sellers, changes in wholesale energy prices that can affect operating income, cash requirements to purchase electricity and natural gas, value received for wholesale sales, collateral required of us by individual counterparties and/or exchanges in wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities;

~~default or nonperformance on the part of any parties from whom we purchase and/or sell capacity or energy;~~

~~potential environmental regulations or lawsuits affecting our ability to utilize or~~local economy, resulting in a decline in customer demand, deterioration in the ~~obsolescence~~creditworthiness of our ~~power~~customers, increases in operating and capital costs, delays in capital projects, disruption in supply ~~resources;~~chains, and disruption, weakness and volatility in capital markets. In addition, any of these factors could negatively impact our liquidity and limit our access to capital, among other implications;

~~explosions, fires, accidents, pipeline ruptures~~wildfires ignited, or ~~other incidents that may limit energy supply~~allegedly ignited, by Avista Corp. equipment or facilities could cause significant loss of life and property, thereby causing serious operational and financial harm to Avista Corp. and our ~~facilities or our surrounding territory, which could result in a shortage of commodities in the market that could increase the cost of replacement commodities from other sources;~~

~~Operational Risk~~customers;

severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, snow and ice storms, that can disrupt energy generation, transmission and distribution, as well as the availability and costs of fuel, materials, equipment, supplies and support services;

explosions, fires, accidents, mechanical breakdowns or other incidents that ~~may~~could impair assets and may disrupt operations of any of our generation facilities, transmission, and electric and natural gas distribution systems or other operations and may require us to purchase replacement ~~power;~~power or incur costs to repair our facilities;

explosions, fires, accidents or other incidents arising from or allegedly arising from our operations that ~~may~~could cause ~~wildfires,~~ injuries to the public or property damage;

blackouts or disruptions of interconnected transmission systems (the regional power grid);

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terrorist attacks, cyberattacks or other malicious acts that ~~may~~could disrupt or cause damage to our utility assets or to the national or regional economy in general, including any effects of terrorism, cyberattacks, ransomware, or vandalism that damage or disrupt information technology systems;

~~work force~~work-force issues, including changes in collective bargaining unit agreements, strikes, work stoppages, the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees;

increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance;

delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities;

increasing health care costs and cost of health insurance provided to our employees and retirees;

third party construction of buildings, billboard signs, towers or other structures within our rights of way, or placement of fuel containers within close proximity to our transformers or other equipment, including overbuild atop natural gas distribution lines;

the loss of key suppliers for materials or services or other disruptions to the supply chain;

adverse impacts to our Alaska electric utility that could result from an extended outage of its hydroelectric generating resources or their inability to deliver energy, due to their lack of interconnectivity to any other electrical grids and the availability or cost of replacement power (diesel);

changing river regulation or operations at hydroelectric facilities not owned by us, which could impact our hydroelectric facilities downstream;

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change in the use, availability or abundancy of water resources and/or rights needed for operation of our hydroelectric facilities;

~~Compliance Risk~~

compliance with extensive federal, state and local legislation and regulation applicable to us, including numerous environmental, health, safety, infrastructure protection, reliability and other laws and regulations that affect our operations and costs;

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

Cyber and Technology Risk

cyberattacks on the operating systems that are used in the operation of our electric generation, transmission and distribution facilities and our natural gas distribution facilities, and cyberattacks on such systems of other energy companies with which we are interconnected, which could damage or destroy facilities or systems or disrupt operations for extended periods of time and result in the incurrence of liabilities and costs;

cyberattacks on the administrative systems that are used in the administration of our business, including customer billing and customer service, accounting, communications, compliance and other administrative functions, and cyberattacks on such systems of our vendors and other companies with which we do business, which could result in the disruption of business operations, the release of private information and the incurrence of liabilities and costs;

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 introducing new cyber security risks;

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

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

changes in our strategic business plans, which ~~may~~could 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;

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;

entering into or growth of non-regulated activities may increase earnings volatility;

~~potential legal proceedings arising from~~

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the ~~termination~~risk of ~~the proposed acquisition~~municipalization or other form of ~~the Company by Hydro One;~~service territory reduction;

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, prohibitions or restrictions on new or existing services, or 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~~fossil fuel fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities;

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

policy and/or legislative changes in various regulated areas, including, but not limited to, environmental regulation, healthcare regulations and import/export regulations;

Financial Risk

our ability to obtain financing through the issuance of debt and/or equity securities, which could be affected by various factors including our credit ratings, interest rates, other capital market conditions and global economic conditions;

changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which could affect future funding obligations, pension and other postretirement benefit expense and the related liabilities;

the outcome of legal proceedings and other contingencies;

economic conditions in our service areas, including the economy's effects on customer demand for utility services;

economic conditions nationally may affect the valuation of our unregulated portfolio companies;

declining energy demand related to customer energy efficiency, conservation measures and/or increased distributed generation;

changes in the long-term climate and weather could materially affect, among other things, customer demand, the volume and timing of streamflows required for hydroelectric generation, costs of generation, transmission and distribution. Increased or new risks may arise from severe weather or natural disasters, including wildfires;

industry and geographic concentrations which could increase our exposure to credit risks due to counterparties, suppliers and customers being similarly affected by changing conditions;

deterioration in the creditworthiness of our customers;

Energy Commodity Risk

volatility and illiquidity in wholesale energy markets, including exchanges, the availability of willing buyers and sellers, changes in wholesale energy prices that could affect operating income, cash requirements to purchase electricity and natural gas, value received for wholesale sales, collateral required of us by individual counterparties and/or exchanges in wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities;

default or nonperformance on the part of any parties from whom we purchase and/or sell capacity or energy;

potential environmental regulations or lawsuits affecting our ability to utilize or resulting in the obsolescence of our power supply resources;

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explosions, fires, accidents, pipeline ruptures or other incidents that could limit energy supply to our facilities or our surrounding territory, which could result in a shortage of commodities in the market that could increase the cost of replacement commodities from other sources;

Compliance Risk

changes in laws, regulations, decisions and policies at the federal, state or local levels, which could materially impact both our electric and gas operations and costs of operations; and

the ~~risk~~ability to comply with the terms of ~~municipalization in any of~~the licenses and permits for our ~~service territories.~~hydroelectric or thermal generating facilities at cost-effective levels.

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

Available Information

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

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PART I. Financial Information

Item 1. Condensed Consolidated Financial Statements

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands, except per share amounts

(Unaudited)


	2019			2018			2020			2019
Operating Revenues:
Utility revenues:
Utility revenues, exclusive of alternative revenue programs	$	393,241		$	408,356		$	393,820		$	393,241
Alternative revenue programs	(4,658		)	(5,939		)	(4,413		)	(4,658		)
Total utility revenues	388,583			402,417			389,407			388,583
Non-utility revenues	7,898			6,944			823			7,898
Total operating revenues	396,481			409,361			390,230			396,481
Operating Expenses:
Utility operating expenses:
Resource costs	137,347			154,618			129,547			137,347
Other operating expenses	83,978			77,298			94,496			83,978
Merger transaction costs	19,664			672			—			19,664
Depreciation and amortization	48,914			44,733			51,421			48,914
Taxes other than income taxes	31,943			30,829			30,978			31,943
Non-utility operating expenses:
Other operating expenses	7,355			6,824			1,360			7,355
Depreciation and amortization	209			181			235			209
Total operating expenses	329,410			315,155			308,037			329,410
Income from operations	67,071			94,206			82,193			67,071
Interest expense	25,651			24,776			26,347			25,651
Interest expense to affiliated trusts	357			253			270			357
Capitalized interest	(928		)	(968		)	(998		)	(928		)
Merger termination fee	(103,000		)	—			—			(103,000		)
Other expense (income)-net	(907		)	4,479
Other income-net							(382		)	(907		)
Income before income taxes	145,898			65,666			56,956			145,898
Income tax expense	30,017			10,710			8,532			30,017
Net income	115,881			54,956			48,424			115,881
Net income attributable to noncontrolling interests	(87		)	(66		)	—			(87		)
Net income attributable to Avista Corp. shareholders	$	115,794		$	54,890		$	48,424		$	115,794
Weighted-average common shares outstanding (thousands), basic	65,733			65,639			67,239			65,733
Weighted-average common shares outstanding (thousands), diluted	65,941			65,931			67,381			65,941

Earnings per common share attributable to Avista Corp. shareholders:
Basic	$	1.76		$	0.84		$	0.72		$	1.76
Diluted	$	1.76		$	0.83		$	0.72		$	1.76

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)


	2019			2018			2020		2019
Net income	$	115,881		$	54,956		$	48,424	$	115,881
Other Comprehensive Income:
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $43 and $55 respectively	160			204
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $54 and $43 respectively							205		160
Total other comprehensive income	160			204			205		160
Comprehensive income	116,041			55,160			48,629		116,041
Comprehensive income attributable to noncontrolling interests	(87		)	(66		)	—		(87		)
Comprehensive income attributable to Avista Corporation shareholders	$	115,954		$	55,094		$	48,629	$	115,954

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS

Avista Corporation

Dollars in thousands

(Unaudited)


	March 31,			December 31,			March 31,			December 31,
	2019			2018			2020			2019
Assets:
Current Assets:
Cash and cash equivalents	$	14,861		$	14,656		$	18,919		$	9,896
Accounts and notes receivable-less allowances of $6,395 and $5,233, respectively	170,200			165,824
Accounts and notes receivable-less allowances of $4,576 and $2,419, respectively							155,253			166,657
Materials and supplies, fuel stock and stored natural gas	61,354			63,881			56,681			66,583
Regulatory assets	41,566			48,552			13,057			21,851
Other current assets	60,948			54,010			30,328			40,142
Assets held for sale	15,874			—
Total current assets	364,803			346,923			274,238			305,129
Net utility property	4,626,054			4,648,930			4,842,318			4,797,007
Goodwill	52,426			57,672			52,426			52,426
Non-current regulatory assets	605,497			614,354			750,866			670,802
Other property and investments-net and other non-current assets	241,203			114,697			254,151			257,092
Total assets	$	5,889,983		$	5,782,576		$	6,173,999		$	6,082,456
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	109,922		$	108,372		$	88,184		$	110,219
Current portion of long-term debt and capital leases	104,989			107,645
Current portion of long-term debt							52,000			52,000
Short-term borrowings	119,000			190,000			185,000			185,800
Regulatory liabilities	55,464			113,209			66,336			51,715
Other current liabilities	175,454			120,358			174,286			130,979
Liabilities held for sale	1,813			—
Total current liabilities	566,642			639,584			565,806			530,713
Long-term debt and capital leases	1,701,207			1,755,529
Long-term debt							1,843,981			1,843,768
Long-term debt to affiliated trusts	51,547			51,547			51,547			51,547
Pensions and other postretirement benefits	218,456			222,537			207,313			212,006
Deferred income taxes	501,928			487,602			525,217			528,513
Non-current regulatory liabilities	786,233			780,701			783,376			775,436
Other non-current liabilities and deferred credits	195,748			71,031			237,664			201,189
Total liabilities	4,021,761			4,008,531			4,214,904			4,143,172
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; 65,749,932 and 65,688,356 shares issued and outstanding, respectively	1,140,242			1,136,491
Common stock, no par value; 200,000,000 shares authorized; 67,292,233 and 67,176,996 shares issued and outstanding, respectively							1,209,312			1,210,741
Accumulated other comprehensive loss	(7,706		)	(7,866		)	(10,054		)	(10,259		)
Retained earnings	734,774			644,595			759,837			738,802
Total Avista Corporation shareholders’ equity	1,867,310			1,773,220			1,959,095			1,939,284
Noncontrolling Interests	912			825
Total equity	1,868,222			1,774,045
Total liabilities and equity	$	5,889,983		$	5,782,576		$	6,173,999		$	6,082,456

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)


	2019			2018			2020			2019
Operating Activities:
Net income	$	115,881		$	54,956		$	48,424		$	115,881
Non-cash items included in net income:
Depreciation and amortization	49,123			45,823			51,421			49,123
Deferred income tax provision and investment tax credits	8,883			(5,049		)	(6,765		)	8,883
Power and natural gas cost amortizations (deferrals), net	(48,084		)	72			6,380			(48,084		)
Amortization of debt expense	669			815			653			669
Amortization of investment in exchange power	613			613			—			613
Stock-based compensation expense	4,845			1,963			872			4,845
Equity-related AFUDC	(1,485		)	(1,392		)	(1,599		)	(1,485		)
Pension and other postretirement benefit expense	9,084			8,170			7,952			9,084
Other regulatory assets and liabilities and deferred debits and credits	1,016			2,127			11,902			1,016
Change in decoupling regulatory deferral	4,471			5,703			4,155			4,471
Gain on sale of investments							(3,242		)	—
Other	(1,943		)	3,778			5,112			(1,943		)
Contributions to defined benefit pension plan	(7,300		)	(7,300		)	(7,300		)	(7,300		)
Changes in certain current assets and liabilities:
Accounts and notes receivable	(9,787		)	15,963			6,078			(9,787		)
Materials and supplies, fuel stock and stored natural gas	(394		)	8,815			9,901			(394		)
Collateral posted for derivative instruments	3,432			18,382			(14,283		)	3,432
Income taxes receivable							10,500			—
Income taxes payable							4,901			19,360
Other current assets	1,705			(473		)	(2,166		)	1,705
Accounts payable	16,697			(21,997		)	(19,527		)	16,697
Income taxes payable	19,360			15,432
Other current liabilities	30,095			38,374			21,905			30,095
Net cash provided by operating activities	196,881			184,775			135,274			196,881

Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	(93,615		)	(81,817		)	(95,525		)	(93,615		)
Issuance of notes receivable at subsidiaries	(200		)	(1,000		)
Repayments of notes receivable at subsidiaries	261			—
Issuance of notes receivable by subsidiaries							(2,779		)	(200		)
Equity and property investments made by subsidiaries	(3,504		)	(3,671		)	(1,313		)	(3,504		)
Distributions received from investments	149			—
Proceeds from sale of investments made by subsidiaries							5,148			—
Other	(755		)	(866		)	(662		)	(345		)
Net cash used in investing activities	(97,664		)	(87,354		)	(95,131		)	(97,664		)

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)


	2019			2018			2020			2019
Financing Activities:
Net decrease in short-term borrowings	$	(71,000	)	$	(55,398	)	$	(800	)	$	(71,000	)
Maturity of long-term debt and capital leases	(665		)	(3,037		)
Maturity of long-term debt and finance leases							(700		)	(665		)
Issuance of common stock, net of issuance costs	190			232			175			190
Cash dividends paid	(25,615		)	(24,634		)	(27,389		)	(25,615		)
Other	(896		)	(4,483		)	(2,406		)	(896		)
Net cash used in financing activities	(97,986		)	(87,320		)	(31,120		)	(97,986		)

Net increase in cash and cash equivalents, including cash classified within current assets held for sale	1,231			10,101
Less: Net increase in cash and cash equivalents classified within current assets held for sale (see Note 18 of Notes to Condensed Consolidated Financial Statements)	1,026			—
Net increase in cash and cash equivalents	205			10,101			9,023			1,231

Cash and cash equivalents at beginning of period	14,656			16,172			9,896			14,656

Cash and cash equivalents at end of period	$	14,861		$	26,273		$	18,919		$	14,861

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)


	2019			2018			2020			2019
Common Stock, Shares:
Shares outstanding at beginning of period	65,688,356			65,494,333			67,176,996			65,688,356
Shares issued	61,576			174,144			115,237			61,576
Shares outstanding at end of period	65,749,932			65,668,477			67,292,233			65,749,932
Common Stock, Amount:
Balance at beginning of period	$	1,136,491		$	1,133,448		$	1,210,741		$	1,136,491
Equity compensation expense	4,452			1,798			804			4,452
Issuance of common stock, net of issuance costs	190			232			175			190
Payment of minimum tax withholdings for share-based payment awards	(891		)	(3,929		)	(2,408		)	(891		)
Balance at end of period	1,140,242			1,131,549			1,209,312			1,140,242
Accumulated Other Comprehensive Loss:
Balance at beginning of period	(7,866		)	(8,090		)	(10,259		)	(7,866		)
Other comprehensive income	160			204			205			160
Reclassification of excess income tax benefits	—			(1,742		)
Balance at end of period	(7,706		)	(9,628		)	(10,054		)	(7,706		)
Retained Earnings:
Balance at beginning of period	644,595			604,470			738,802			644,595
Net income attributable to Avista Corporation shareholders	115,794			54,890			48,424			115,794
Cash dividends paid on common stock	(25,615		)	(24,634		)	(27,389		)	(25,615		)
Reclassification of excess income tax benefits	—			1,742
Balance at end of period	734,774			636,468			759,837			734,774
Total Avista Corporation shareholders’ equity	1,867,310			1,758,389			1,959,095			1,867,310
Noncontrolling Interests:
Balance at beginning of period	825			656			—			825
Net income attributable to noncontrolling interests	87			66			—			87
Cash dividends paid to subsidiary noncontrolling interests	—			(540		)
Balance at end of period	912			182			—			912
Total equity	$	1,868,222		$	1,758,571		$	1,959,095		$	1,868,222
Dividends declared per common share	$	0.3875		$	0.3725		$	0.4050		$	0.3875

The Accompanying Notes are an Integral Part of These Statements.

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AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

The accompanying condensed consolidated financial statements of Avista Corp. as of and for the interim periods ended March 31, ~~2019~~2020 and March 31, ~~2018~~2019 are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results for the interim periods. All such adjustments are of a normal recurring nature. The condensed consolidated financial statements have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Condensed Consolidated Statements of Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These condensed consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company's audited consolidated financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019 (~~2018~~2019 Form 10-K).

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

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

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

Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 16 for business segment information. See Note 18 for discussion of ~~assets held for~~the sale atof METALfx, an unregulated subsidiary of the Company.

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.

Derivative Assets and Liabilities

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

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

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 cash payments made or received are recorded as a regulatory asset or liability isand are subsequently amortized as a component of interest expense over the ~~term~~life of the associated debt. The ~~Company records an offset of~~settled interest rate swap ~~derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice~~derivatives are also included as a part of ~~the commissions to provide recovery through the~~Avista Corp.'s cost of debt calculation for ratemaking ~~process.~~purposes.

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AVISTA CORPORATION

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

Fair Value Measurements

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

Contingencies

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~~ ~~March 31, 2019, the Company has not recorded any significant amounts related to unresolved contingencies.~~ See Note 15 for further discussion of the Company's commitments and contingencies.

COVID-19

In March 2020, the Company filed an application for authorization to defer certain incremental COVID-19 related costs with the OPUC. In April and May 2020, the Company made similar filings with the IPUC and the WUTC, respectively. In Alaska, a Senate Bill was signed into law that provides for deferral and recovery of incremental COVID-19 related costs subject to approval by the RCA. The recovery of any deferred costs would be determined in future rate making proceedings.

NOTE 2. NEW ACCOUNTING STANDARDS

ASU No. ~~2016-02, "Leases~~2016-12 "Financial Instruments - Credit Losses (Topic ~~842)"~~

~~ASU No. 2018-01, "Leases (Topic 842)~~326): ~~Land Easement Practical Expedient for Transition to Topic 842"~~

~~ASU No. 2018-11, "Leases (Topic 842): Targeted Improvements"~~Measurement of Credit Losses on Financial Instruments"

On January 1, ~~2019,~~2020, the Company adopted ASU ~~No. 2016-02,~~2016-13, which ~~outlines~~replaces the incurred loss impairment methodology in previous GAAP with a ~~model for entities~~methodology that reflects expected credit losses, and requires consideration of a broader range of reasonable and supportable information to ~~use in accounting for leases and supersedes previous lease accounting guidance, as well as several practical expedients in ASU Nos. 2018-01 and 2018-11.~~

inform credit loss estimates. The Company ~~adopted ASU No. 2016-02 utilizing a modified retrospective adoption method with~~analyzed its financial instruments within the ~~"package~~scope of ~~three"~~this guidance, primarily trade receivables, and hindsight practical expedients offered by the standard. The "package of three" provides for an entity to not reassess at adoption whether any expired or existing contracts are deemed, for accounting purposes, to be or contain leases, the classification of any expired or existing leases, and any initial direct costs for any existing leases. As a result, the Companyit did not ~~apply the new guidance~~have a material impact to existing contracts that are or contain leases, and did not reassess the classification of those leases. The Company used the benefit of hindsight in determining both term and impairments associated with any existing leases. Use of this practical expedient has resulted in lease terms that best represent management's expectations with respect to use of the underlying asset but did not result in recognition of any impairment.

The Company elected to adopt ASU No. 2018-01, which allows an entity to exclude from application of Topic 842 all easements executed prior to January 1, 2019. In addition, the Company elected to adopt the "comparatives under 840" practical expedient offered in ASU No. 2018-11, which allows an entity to apply the new lease standard at the adoption date, recognizing any necessary cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption and presenting comparative periods in the financial statements under ASC 840 (previous lease accounting guidance). Adoption of the standard did not result in a cumulative effect adjustment within the Company's financial ~~statements.~~

~~As allowed by ASU No. 2016-02, the Company elected~~statements and does not ~~to apply the requirements of the standard to short-term leases, those leases with an initial term of 12 months or less. These leases are not recorded on the balance sheet and are immaterial~~require additional disclosure in these Notes to the ~~financial statements.~~

~~Adoption of the standard impacted the Company's~~ Condensed Consolidated Balance Sheet through recognition of right-of-use (ROU) assets and lease liabilities for the Company's operating leases. Accounting for finance leases (formerly capital leases) remained substantially unchanged, except the Company reclassified the amounts as of December 31, 2018 to conform to the presentation of operating leases as of March 31, 2019. See Note 5 for further information on the Company's leases.

~~ASU No. 2018-02 “Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”~~

In February 2018, the FASB issued ASU No. 2018-02, which amended the guidance for reporting comprehensive income. This ASU allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the enactment of the TCJA in December 2017. This ASU became effective for periods beginning after December

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~~AVISTA CORPORATION~~

15, 2018 and early adoption was permitted. Upon adoption, the requirements of this ASU must be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the TCJA is recognized. The Company early adopted this standard effective January 1, 2018 and elected to apply the guidance during the period of adoption rather than apply the standard retrospectively. As a result, the Company reclassified $1.7 million in tax benefits from accumulated other comprehensive loss to retained earnings during the three months ended March 31, 2018.Financial Statements.

ASU 2018-13 ~~" Fair~~"Fair Value Measurement (Topic 820)"

In August 2018, the FASB issued ASU No. 2018-13, which amends the fair value measurement disclosure requirements of ASC 820. The requirements of this ASU include additional disclosure regarding the range and weighted average used to develop significant unobservable inputs for Level 3 fair value estimates and the elimination of certain other previously required disclosures, such as the narrative description of the valuation process for Level 3 fair value measurements. This ASU isbecame effective ~~for periods beginning after December 15, 2019~~on January 1, 2020 and ~~early adoption is permitted. Entities have~~ the ~~option to early adopt the eliminated or modified disclosure~~ requirements ~~and delay the adoption of all the new disclosure requirementsuntil the effective date of the ASU. The Company is in the process of evaluating this standard; however, it has determined that it will not early adopt any portion~~ of this ~~standard as of March 31, 2019.~~ASU did not have a material impact on the Company's fair value disclosures. See Note 11 for the Company's fair value disclosures.

ASU No. 2018-14 "Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20)"

In August 2018, the FASB issued ASU No. 2018-14, which amends ASC 715 to add, remove and/or clarify certain disclosure requirements related to defined benefit pension and other postretirement plans. The additional disclosure requirements are primarily narrative discussion of significant changes in the benefit obligations and plan assets. The removed disclosures are primarily information about accumulated other comprehensive income expected to be recognized over the next year and the effects of changes associated with assumed health care costs. This ASU is effective for periods beginning after December 15, 2021 and early adoption is permitted. The Company is in the process of evaluating this standard; however, it has determined that it will not early adopt this standard as of March 31, ~~2019.~~2020.

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AVISTA CORPORATION

NOTE 3. BALANCE SHEET COMPONENTS

Materials and Supplies, Fuel Stock and Stored Natural Gas

Inventories of materials and supplies, fuel stock and stored natural gas are recorded at average cost for our regulated operations and the lower of cost or market for our non-regulated operations and consisted of the following as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):



	March 31,		December 31,
	2020		2019
Materials and supplies	$	49,007	$	47,402
Fuel stock	4,740		4,875
Stored natural gas	2,934		14,306
Total	$	56,681	$	66,583

March 31, December 31,
2019 2018
Materials and supplies $ 47,705
$ 47,403
Fuel stock 4,930
4,869
Stored natural gas 8,719
11,609
Total $ 61,354
$ 63,881

Other Current Assets

Other current assets consisted of the following as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):



	March 31,		December 31,
	2020		2019
Collateral posted for derivative instruments after netting with outstanding derivative liabilities	$	2,470	$	4,434
Prepayments	22,569		19,652
Income taxes receivable	—		11,047
Other	5,289		5,009
Total	$	30,328	$	40,142

March 31, December 31,
2019 2018
Collateral posted for derivative instruments after netting with outstanding derivative liabilities $ 37,347
$ 26,809
Prepayments 16,647
17,536
Other 6,954
9,665
Total $ 60,948
$ 54,010

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~~AVISTA CORPORATION~~

Net Utility Property

Net utility property consisted of the following as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):



	March 31,		December 31,
	2020		2019
Utility plant in service	$	6,521,033	$	6,462,993
Construction work in progress	189,827		164,941
Total	6,710,860		6,627,934
Less: Accumulated depreciation and amortization	1,868,542		1,830,927
Total net utility property	$	4,842,318	$	4,797,007

March 31, December 31,
2019 2018
Utility plant in service $ 6,202,942
$ 6,209,968
Construction work in progress 165,725
160,598
Total 6,368,667
6,370,566
Less: Accumulated depreciation and amortization 1,742,613
1,721,636
Total net utility property $ 4,626,054
$ 4,648,930

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

Other property and investments-net and other non-current assets consisted of the following as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):



	March 31,		December 31,
	2020		2019
Operating lease ROU assets	$	65,303	$	69,746
Finance lease ROU assets	50,069		50,980
Non-utility property	26,511		27,159
Equity investments	51,467		51,258
Investment in affiliated trust	11,547		11,547
Notes receivable	14,970		14,060
Deferred compensation assets	8,670		8,948
Other	25,614		23,394
Total	$	254,151	$	257,092

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March 31, December 31,
2019 2018
Operating lease ROU assets $ 70,834
$ —
Finance lease ROU assets 53,711
—
Non-utility property 29,557
31,355
Equity investments 32,967
29,257
Investment in affiliated trust 11,547
11,547
Notes receivable 11,161
11,073
Deferred compensation assets 8,675
8,400
Other 22,751
23,065
Total $ 241,203
$ 114,697

AVISTA CORPORATION

Other Current Liabilities

Other current liabilities consisted of the following as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):



	March 31,		December 31,
	2020		2019
Accrued taxes other than income taxes	$	48,980	$	36,965
Employee paid time off accruals	24,084		22,343
Accrued interest	31,033		16,486
Current portion of pensions and other postretirement benefits	9,811		8,826
Income taxes payable	5,199		298
Derivative liabilities	27,409		10,928
Other current liabilities	27,770		35,133
Total other current liabilities	$	174,286	$	130,979

March 31, December 31,
2019 2018
Accrued taxes other than income taxes $ 49,206
$ 36,858
Income taxes payable 20,368
141
Employee paid time off accruals 21,813
20,992
Accrued interest 30,315
16,704
Current portion of pensions and other postretirement benefits 9,503
9,151
Operating lease liabilities 4,120
—
Finance lease liabilities 2,695
—
Utility energy commodity derivative liabilities 4,035
3,908
Other current liabilities 33,399
32,604
Total other current liabilities $ 175,454
$ 120,358

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Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):



	March 31,		December 31,
	2020		2019
Operating lease liabilities	$	62,145	$	65,565
Finance lease liabilities	51,016		51,750
Deferred investment tax credits	30,588		30,444
Asset retirement obligations	20,263		20,338
Derivative liabilities	60,278		19,685
Other	13,374		13,407
Total	$	237,664	$	201,189

March 31, December 31,
2019 2018
Operating lease liabilities $ 67,635
$ —
Finance lease liabilities 53,850
—
Deferred investment tax credits 31,383
29,725
Asset retirement obligations 18,455
18,266
Derivative liabilities 10,861
10,300
Other 13,564
12,740
Total $ 195,748
$ 71,031

Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):



	March 31, 2020				December 31, 2019
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	78	$	—	$	6,310	$	264
Decoupling surcharge	10,927		15,504		12,098		14,806
Pension and other postretirement benefit plans	—		206,112		—		208,754
Interest rate swaps	—		246,566		—		168,594
Deferred income taxes	—		96,525		—		95,752
Settlement with Coeur d'Alene Tribe	—		41,005		—		41,332
AFUDC above FERC allowed rate	—		41,333		—		40,749
Demand side management programs	—		8,670		—		12,170
Utility plant to be abandoned	—		31,678		—		31,291
Other regulatory assets	2,052		63,473		3,443		57,090
Total regulatory assets	$	13,057	$	750,866	$	21,851	$	670,802

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March 31, 2019 December 31, 2018
Current Non-Current Current Non-Current
Regulatory Assets
Energy commodity derivatives $ 28,159
$ 11,862
$ 41,428
$ 16,866
Decoupling surcharge 6,782
8,395
3,408
17,501
Pension and other postretirement benefit plans —
224,805
—
228,062
Interest rate swaps —
138,327
—
133,854
Deferred income taxes —
93,646
—
91,188
Settlement with Coeur d'Alene Tribe —
42,316
—
42,643
Demand side management programs —
15,064
—
19,674
Utility plant to be abandoned —
24,477
—
24,334
Other regulatory assets 6,625
46,605
3,716
40,232
Total regulatory assets $ 41,566
$ 605,497
$ 48,552
$ 614,354

Regulatory Liabilities
Income tax related liabilities $ 29,401
$ 421,216
$ 27,997
$ 425,613
Deferred natural gas costs 1,253
—
40,713
—
Deferral power costs 12,555
26,106
25,072
16,933
Decoupling rebate 1,061
4,664
6,782
204
Utility plant retirement costs —
300,373
—
297,379
Interest rate swaps —
20,396
—
28,078
Other regulatory liabilities 11,194
13,478
12,645
12,494
Total regulatory liabilities $ 55,464
$ 786,233
$ 113,209
$ 780,701

AVISTA CORPORATION



	March 31, 2020				December 31, 2019
	Current		Non-Current		Current		Non-Current
Regulatory Liabilities
Income tax related liabilities	$	23,975	$	404,046	$	23,803	$	407,549
Deferred natural gas costs	5,449		—		3,189		—
Deferral power costs	23,595		20,716		14,155		23,544
Decoupling rebate	363		5,972		255		2,398
Provision for rate refund (Washington remand case)	8,490		—		3,565		—
Utility plant retirement costs	—		317,203		—		312,403
Interest rate swaps	—		16,136		—		17,088
Other regulatory liabilities	4,464		19,303		6,748		12,454
Total regulatory liabilities	$	66,336	$	783,376	$	51,715	$	775,436

NOTE 4. REVENUE

ASC 606 defines the core principle of the revenue recognition 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.

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Utility Revenues

Revenue from Contracts with Customers

General

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."

Non-Derivative Wholesale Contracts

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

Alternative Revenue Programs (Decoupling)

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

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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 specifically scoped out of ASC 606. As such, these revenues are disclosed separately from revenue from contracts with customers. Revenue is recognized for these items upon the settlement/expiration of the derivative contract. Derivative revenue includes those transactions that are entered into and settled within the same month.

Other Utility Revenue

Other utility revenue includes rent, revenues from the lineman training school, sales of materials, late fees and other charges that do not represent contracts with customers.Other utility revenue also includes the provision for earnings sharing and the deferral and amortization of refunds to customers associated with the TCJA. This revenue is scoped out of ASC 606, as this revenue does not represent items where a customer is a party that has contracted with the Company to obtain goods or services that are an output of the Company’s ordinary activities in exchange for consideration. As such, these revenues are presented separately from revenue from contracts with customers.

Other Considerations for Utility Revenues

Gross Versus Net Presentation

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

Utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) are taxes that are imposed on Avista Utilities as opposed to being imposed on its customers; therefore, Avista Utilities is the taxpayer and records these

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transactions on a gross basis in revenue from contracts with customers and operating expense (taxes other than income taxes). The utility-related taxes collected from customers at AEL&P are imposed on the customers rather than AEL&P; therefore, the customers are the taxpayers and AEL&P is acting as their agent. As such, these transactions at AEL&P are presented on a net basis within revenue from contracts with customers.

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



	2020		2019
Utility-related taxes	$	18,700	$	19,089

2019 2018
Utility-related taxes $ 19,089
$ 19,167

Non-Utility Revenues

Revenue from Contracts with Customers

Non-utility ~~revenues~~revenue from contracts with customers ~~are primarily~~is derived from contracts with one performance obligation. Prior to its sale in April 2019 (See Note 18 for further discussion on the ~~operations~~sale of ~~METALfx. The contracts associated with~~METALfx), METALfx ~~have~~had one performance obligation, the delivery of a product, and revenues ~~are~~were recognized when the risk of loss ~~transfers~~transferred to the customer, which ~~occurs~~occurred when products ~~are~~were shipped. The Steam Plant Brew Pub serves food and beverages to customers, its one performance obligation, and recognizes revenues at the time of service to the customer.

Significant Judgments and Unsatisfied Performance Obligations

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

The Company has certain capacity arrangements, where the Company has a contractual obligation to provide either electric or natural gas capacity to its customers for a fixed fee. Most of these arrangements are paid for in arrears by the customers and do not result in deferred revenue and only result in receivables from the customers. The Company does have one capacity agreement where the customer makes payments throughout the year and depending on the timing of the customer payments, it can result in an immaterial amount of deferred revenue or a receivable from the customer. As of March 31, ~~2019,~~2020, the Company estimates it had unsatisfied capacity performance obligations of ~~$9.1~~$4.7 million, which will be recognized as revenue in future periods as the capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.

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Disaggregation of Total Operating Revenue

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

2019 2018
Avista Utilities
Revenue from contracts with customers $ 354,301
$ 354,162
Derivative revenues 24,127
58,392
Alternative revenue programs (4,658 ) (5,939 )
Deferrals and amortizations for rate refunds to customers 2,135
(19,822 )
Other utility revenues 1,797
1,961
Total Avista Utilities 377,702
388,754
AEL&P
Revenue from contracts with customers 10,736
14,650
Deferrals and amortizations for rate refunds to customers (48 ) (1,122 )
Other utility revenues 193
135
Total AEL&P 10,881
13,663
Other
Revenue from contracts with customers 7,647
6,729
Other revenues 251
215
Total other 7,898
6,944
Total operating revenues $ 396,481
$ 409,361

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	2020			2019
Avista Utilities
Revenue from contracts with customers	$	351,628		$	354,301
Derivative revenues	31,075			24,127
Alternative revenue programs	(4,413		)	(4,658		)
Deferrals and amortizations for rate refunds to customers	(2,606		)	2,135
Other utility revenues	1,521			1,797
Total Avista Utilities	377,205			377,702
AEL&P
Revenue from contracts with customers	12,126			10,736
Deferrals and amortizations for rate refunds to customers	(48		)	(48		)
Other utility revenues	124			193
Total AEL&P	12,202			10,881
Other
Revenue from contracts with customers	514			7,647
Other revenues	309			251
Total other	823			7,898
Total operating revenues	$	390,230		$	396,481

Utility Revenue from Contracts with Customers by Type and Service

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



	2020						2019
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	107,977	$	5,866	$	113,843	$	115,392	$	5,852	$	121,244
Commercial and governmental	78,849		6,199		85,048		79,245		4,821		84,066
Industrial	24,711		—		24,711		25,248		—		25,248
Public street and highway lighting	1,783		61		1,844		1,903		63		1,966
Total retail revenue	213,320		12,126		225,446		221,788		10,736		232,524
Transmission	3,774		—		3,774		5,152		—		5,152
Other revenue from contracts with customers	5,289		—		5,289		8,194		—		8,194
Total revenue from contracts with customers	$	222,383	$	12,126	$	234,509	$	235,134	$	10,736	$	245,870

2019 2018
Avista Utilities AEL&P Total Utility Avista Utilities AEL&P Total Utility
ELECTRIC OPERATIONS
Residential $ 115,392
$ 5,852
$ 121,244
$ 114,753
$ 6,538
$ 121,291
Commercial and governmental 79,245
4,821
84,066
78,909
8,044
86,953
Industrial 25,248
—
25,248
25,119
—
25,119
Public street and highway lighting 1,903
63
1,966
1,859
68
1,927
Total retail revenue 221,788
10,736
232,524
220,640
14,650
235,290
Transmission 5,152
—
5,152
3,830
—
3,830
Other revenue from contracts with customers 8,194
—
8,194
6,291
—
6,291
Total electric revenue from contracts with customers $ 235,134
$ 10,736
$ 245,870
$ 230,761
$ 14,650
$ 245,411

NATURAL GAS OPERATIONS
Residential $ 77,336
$ —
$ 77,336
$ 80,653
$ —
$ 80,653
Commercial 36,595
—
36,595
37,373
—
37,373
Industrial and interruptible 1,627
—
1,627
1,683
—
1,683
Total retail revenue 115,558
—
115,558
119,709
—
119,709
Transportation 2,484
—
2,484
2,567
—
2,567
Other revenue from contracts with customers 1,125
—
1,125
1,125
—
1,125
Total natural gas revenue from contracts with customers $ 119,167
$ —
$ 119,167
$ 123,401
$ —
$ 123,401

~~NOTE 5. LEASES~~

ASC 842, which outlines a model for entities to use in accounting for leases and supersedes previous lease accounting guidance, became effective on January 1, 2019. The core principle of the model is that an entity should recognize the ROU assets and liabilities that arise from leases on the balance sheet and depreciate or amortize the asset and liability over the term of the lease, as well as provide disclosure to enable users of the condensed consolidated financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases.

~~Significant Judgments and Assumptions~~

~~The Company determines if an arrangement is a lease, as well as its classification, at its inception.~~

ROU assets represent the Company's right to use an underlying asset for the lease term, and lease liabilities represent the Company's obligation to make lease payments arising from the lease. Operating and finance lease ROU assets and lease liabilities are recognized at the commencement date of the agreement based on the present value of lease payments over the lease term. As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The implicit rate is used when it is readily determinable. The operating and finance lease ROU assets also include any lease payments made and exclude lease incentives, if any, that accrue to the benefit of the lessee.

Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. Any difference between lease expense and cash paid for leased assets is recognized as a regulatory asset or regulatory liability.

~~Description of Leases~~

The Company has operating leases for land associated with its utility operations, as well as communication sites which support network and radio communications within its service territory. The Company's leases have remaining terms of 1 to 74 years.

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~~Most of the Company's leases include options to extend the lease term for periods of 5 to 50 years. Exercise of these options is at the Company's discretion.~~

The ~~Company has an operating lease~~following table disaggregates revenue from contracts with the state of Montana associated with submerged land around the Company's hydroelectric facilities in the Clark Fork River basin, which expires in 2046. The terms of this lease are subject to renegotiation, depending on the outcome of ongoing litigation between Montana and NorthWestern Energy. In addition, the state of Montana and Avista Corp. are engaged in litigation regarding the lease terms. As such, amounts recorded for this lease are uncertain and amounts may change in the future depending on the outcome of the ongoing litigation.

Through its wholly-owned subsidiary, AEL&P, the Company has a PPA which is treated as a finance lease for accounting purposes related to the Snettisham Hydroelectric Project, which expires in 2034. For ratemaking purposes, this lease is treated as an operating lease with a constant level of annual rental expense (straight line rent expense). Because of this regulatory treatment, any difference between the operating lease expense for ratemaking purposes and the expenses recognized under finance lease treatment (interest and amortization of the finance lease ROU asset) is recorded as a regulatory asset and amortized during the later years of the lease when the finance lease expense is less than the operating lease expense included in base rates. In 2018 and prior years, the total costcustomers associated with the Snettisham PPA was included in resource costs. Due to the adoption of the new lease standard, the amortization of the ROU asset is now included in depreciation and amortization and the interest associated with the lease liability is now included in interest expense on the Condensed Consolidated Statement of Income.

~~Certain of the~~ Company's lease agreements include rental payments which are periodically adjusted over the term of the agreement based on the consumer price index. The Company's lease agreements do not include any material residual value guarantees or material restrictive covenants.

~~Avista Corp. does not record leases with a term of 12-months or less in the Condensed Consolidated Balance Sheet. Total short-term lease cost for the three months ended March 31, 2019 is immaterial.~~

~~Leases that Have Not Yet Commenced~~

In March 2019, the Company signed a PPA with Clearway Energy Group (Clearway) to purchase all of the power generated from the Rattlesnake Flat Wind project in Adams County, Washington. The facility has a nameplate capacity of 144 MW and is expected to generate approximately 50 aMW. During negotiations with Clearway, Avista Corp. was involved in the selection of the preferred generation facility type. The PPA is a 20-year agreement with deliveries expected to begin in 2020. The PPA provides Avista Corp. with additional renewable energy, capacity and environmental attributes. Avista Corp. expects to recover the cost of the power purchased through its retail rates. This PPA is considered a lease under ASC 842; however, all of the payments are variable payments based on whether power is generated from the facility. Since all the payments are variable, the Company will not record a lease liability for the agreement, but the expense will be included in resource costs when it becomes operational in 2020.

~~The components of lease expense were as follows~~natural gas operations for the three months ended March 31 (dollars in thousands):



	2020		2019
	Avista Utilities		Avista Utilities
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	84,173	$	77,336
Commercial	39,401		36,595
Industrial and interruptible	2,194		1,627
Total retail revenue	125,768		115,558
Transportation	2,352		2,484
Other revenue from contracts with customers	1,125		1,125
Total revenue from contracts with customers	$	129,245	$	119,167

2019
Operating lease cost:
Fixed lease cost (Other operating expenses) $ 1,103
Variable lease cost (Other operating expenses) 243
Total operating lease cost $ 1,346

Finance lease cost:
Amortization of ROU asset (Depreciation and amortization) $ 910
Interest on lease liabilities (Interest expense) 699
Total finance lease cost $ 1,609

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~~Supplemental cash flow information related to leases was as follows for the three months ended March 31 (dollars in thousands):~~

2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash outflows:
Operating lease payments $ 4,092
Interest on finance lease 699
Total operating cash outflows $ 4,791

Finance cash outflows:
Principal payments on finance lease $ 665

~~Supplemental balance sheet information related to leases was as follows for March 31, 2019 (dollars in thousands):~~

March 31,
2019
Operating Leases
Operating lease ROU assets (Other property and investments-net and other non-current assets) $ 70,834

Other current liabilities $ 4,120
Other non-current liabilities and deferred credits 67,635
Total operating lease liabilities $ 71,755

Finance Leases
Finance lease ROU assets (Other property and investments-net and other non-current assets) (a) $ 53,711

Other current liabilities (b) $ 2,695
Other non-current liabilities and deferred credits (b) 53,850
Total finance lease liabilities $ 56,545

Weighted Average Remaining Lease Term
Operating leases 27.32 years
Finance leases 9.64 years

Weighted Average Discount Rate
Operating leases 3.82 %
Finance leases 4.85 %

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~~(a)~~

At December 31, 2018, the finance lease ROU assets were included in "Net utility property" on the Condensed Consolidated Balance Sheet. Due to the adoption of ASC 842 on January 1, 2019, the Company has reclassified these amounts to "Other property and investments-net and other non-current assets" on the Condensed Consolidated Balance Sheet such that their presentation as of March 31, 2019 is consistent with operating leases.

~~(b)~~

At December 31, 2018, the finance lease liabilities were included in "Current portion of long-term debt" and "Long-term debt and capital leases" on the Condensed Consolidated Balance Sheet. Due to the adoption of ASC 842 on January 1, 2019, the Company has reclassified these amounts to "Other current liabilities" and "Other non-current liabilities and deferred credits" on the Condensed Consolidated Balance Sheet such that their presentation as of March 31, 2019 is consistent with operating leases.

~~Maturities of lease liabilities (including principal and interest) were as follows as of March 31, 2019 (dollars in thousands):~~

Operating Leases Finance Leases
Remainder 2019 $ 4,272
$ 4,091
2020 4,364
5,462
2021 4,367
5,457
2022 4,375
5,460
2023 4,383
5,456
Thereafter 95,923
54,574
Total lease payments $ 117,684
$ 80,500
Less: imputed interest (45,929 ) (23,955 )
Total $ 71,755
$ 56,545

~~Future minimum lease payments (including principal and interest) under Topic 840 as of December 31, 2018 (dollars in thousands):~~

Operating Leases Finance Leases
2019 $ 4,995
$ 5,455
2020 4,876
5,462
2021 4,859
5,457
2022 4,782
5,460
2023 4,780
5,456
Thereafter 102,389
54,574
Total lease payments $ 126,681
$ 81,864
Less: imputed interest —
(24,654 )
Total $ 126,681
$ 57,210

NOTE 6.5. DERIVATIVES AND RISK MANAGEMENT

Energy Commodity Derivatives

Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista Corp. utilizes derivative instruments, such as forwards, futures, swap derivatives and options, in order to manage the various risks relating to these commodity price exposures. Avista Corp. has an energy resources risk policy and control procedures to manage these risks.

As part of Avista Corp.'s resource procurement and management operations in the electric business, Avista Corp. engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve Avista Corp.'s load obligations and the use of these resources to capture available economic value through wholesale market transactions. These include sales and purchases of electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with load

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obligations and hedging a portion of the related financial risks. These transactions range from terms of intra-hour up to multiple years.

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

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

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The following table presents the underlying energy commodity derivative volumes as of March 31, 2020 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):



	Purchases				Sales
	Electric Derivatives		Gas Derivatives		Electric Derivatives		Gas Derivatives
Year	Physical (1) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs	Physical (1) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs
Remainder 2020	3	395	10,232	61,330	366	1,491	871	27,035
2021	—	123	305	32,120	—	246	1,490	21,700
2022	—	—	450	7,820	—	—	—	2,700

As of March 31, 2020, there are no expected deliveries of energy commodity derivatives after 2022.

The following table presents the underlying energy commodity derivative volumes as of December 31, 2019 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):


	Purchases				Sales				Purchases				Sales
	Electric Derivatives		Gas Derivatives		Electric Derivatives		Gas Derivatives		Electric Derivatives		Gas Derivatives		Electric Derivatives		Gas Derivatives
Year	Physical (1) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs	Physical (1) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs	Physical (1) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs	Physical (1) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs
Remainder 2019	30	596	4,640	81,438	109	2,280	669	35,913
2020	—	—	1,138	53,388	123	959	1,430	16,378	2	442	9,813	78,803	133	1,724	2,984	37,848
2021	—	—	—	15,290	—	246	1,049	4,100	—	—	153	25,523	—	246	1,040	13,108
2022	—	—	—	—	—	—	—	—	—	—	225	4,725	—	—	—	675
2023	—	—	—	—	—	—	—	—
Thereafter	—	—	—	—	—	—	—	—

~~The following table presents the underlying energy commodity derivative volumes as~~As of December 31, ~~2018 that~~2019, there are no expected ~~to be delivered in each respective year (in thousands~~deliveries 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
2019 206
941
10,732
101,293
197
2,790
2,909
54,418
2020 —
—
1,138
47,225
123
959
1,430
14,625
2021 —
—
—
9,670
—
—
1,049
4,100
2022 —
—
—
—
—
—
—
—
2023 —
—
—
—
—
—
—
—
Thereafter —
—
—
—
—
—
—
—

energy commodity derivatives after 2022.


(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.

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

Foreign Currency Exchange Derivatives

A significant portion of Avista Corp.’s natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.’s short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency ~~prices 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 March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):



	March 31,		December 31,
	2020		2019
Number of contracts	23		20
Notional amount (in United States dollars)	$	5,219	$	5,932
Notional amount (in Canadian dollars)	7,247		7,828

March 31, December 31,
2019 2018
Number of contracts 22
31
Notional amount (in United States dollars) $ 6,681
$ 4,018
Notional amount (in Canadian dollars) 8,917
5,386

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

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derivatives and U.S. Treasury lock agreements. These interest rate swap derivatives and U.S. Treasury lock agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances.

The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. has outstanding as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):



Balance Sheet Date	Number of Contracts	Notional Amount		Mandatory Cash Settlement Date
March 31, 2020	7	$	70,000	2020
	4	45,000		2021
	11	120,000		2022
	1	10,000		2023
December 31, 2019	7	70,000		2020
	3	35,000		2021
	10	110,000		2022

Balance Sheet Date Number of Contracts Notional Amount Mandatory Cash Settlement Date
March 31, 2019 6 $ 70,000
2019
6 60,000
2020
2 25,000
2021
8 90,000
2022
December 31, 2018 6 $ 70,000
2019
6 60,000
2020
2 25,000
2021
7 80,000
2022

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 Avista Corp.'s cost of debt calculation for ratemaking purposes.

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

Summary of Outstanding Derivative Instruments

The amounts recorded on the Condensed Consolidated Balance Sheet as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.

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The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of March 31, ~~2019~~2020 (in thousands):


	Fair Value										Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet			Gross Asset		Gross Liability			Collateral Netted			Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current liabilities	$	15	$	(15	)	$	—	$	—		$	36	$	(103	)	$	—		$	(67	)
Interest rate swap derivatives
Other current liabilities											—		(32,967		)	12,967			(20,000		)
Other non-current liabilities and deferred credits											—		(79,271		)	14,123			(65,148		)
Energy commodity derivatives
Other current assets	2,587		(530		)	—		2,057			28,964		(26,503		)	(695		)	1,766
Other property and investments-net and other non-current assets	2,503		(1,754		)	—		749			6,072		(3,626		)	—			2,446
Other current liabilities	—		(524		)	—		(524		)	51		(2,590		)	—			(2,539		)
Other non-current liabilities and deferred credits	—		(12,402		)	2,860		(9,542		)	—		(24		)	—			(24		)
Energy commodity derivatives
Other current assets	262		(12		)	—		250
Other current liabilities	26,875		(55,284		)	24,374		(4,035		)
Other non-current liabilities and deferred credits	4,349		(16,211		)	10,543		(1,319		)
Total derivative instruments recorded on the balance sheet	$	36,591	$	(86,732	)	$	37,777	$	(12,364	)	$	35,123	$	(145,084	)	$	26,395		$	(83,566	)

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The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, ~~2018~~2019 (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	$	97	$	—		$	—	$	97
Interest rate swap derivatives
Other current assets	589		—			—		589
Other current liabilities	238		(9,379		)	1,316		(7,825		)
Other non-current liabilities and deferred credits	725		(24,677		)	5,454		(18,498		)
Energy commodity derivatives
Other current assets	416		(245		)	—		171
Other property and investments-net and other non-current assets	6,369		(5,446		)	—		923
Other current liabilities	34,760		(41,241		)	3,378		(3,103		)
Other non-current liabilities and deferred credits	28		(1,215		)	—		(1,187		)
Total derivative instruments recorded on the balance sheet	$	43,222	$	(82,203	)	$	10,148	$	(28,833	)

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 liabilities $ —
$ (45 ) $ —
$ (45 )
Interest rate swap derivatives
Other current assets 5,283
—
—
5,283
Other property and investments-net and other non-current assets 5,283
(440 ) —
4,843
Other non-current liabilities and deferred credits —
(7,391 ) 530
(6,861 )
Energy commodity derivatives
Other current assets 400
(130 ) —
270
Other current liabilities 31,457
(73,155 ) 37,790
(3,908 )
Other non-current liabilities and deferred credits 4,426
(21,292 ) 13,427
(3,439 )
Total derivative instruments recorded on the balance sheet $ 46,849
$ (102,453 ) $ 51,747
$ (3,857 )

Exposure to Demands for Collateral

Avista Corp.'s derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement. In the event of a downgrade in Avista Corp.'s credit ratings or changes in market prices, additional collateral may be required. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against Avista Corp.'s credit facilities and cash. Avista Corp. actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements.

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The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (in thousands):


	March 31,		December 31,		March 31,			December 31,
	2019		2018		2020			2019
Energy commodity derivatives
Cash collateral posted	$	72,264	$	78,025	$	1,775		$	7,812
Letters of credit outstanding	56,100		6,500		25,000			17,400
Balance sheet offsetting (cash collateral against net derivative positions)	34,917		51,217		(695		)	3,378

Interest rate swap derivatives
Cash collateral posted	2,860		530		27,090			6,770
Letters of credit outstanding					3,910			—
Balance sheet offsetting (cash collateral against net derivative positions)	2,860		530		27,090			6,770

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.

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The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral Avista Corp. could be required to post as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (in thousands):



	March 31,		December 31,
	2020		2019
Energy commodity derivatives
Liabilities with credit-risk-related contingent features	$	1	$	814
Additional collateral to post	1		814

Interest rate swap derivatives
Liabilities with credit-risk-related contingent features	112,238		34,056
Additional collateral to post	81,280		26,912

March 31, December 31,
2019 2018
Energy commodity derivatives
Liabilities with credit-risk-related contingent features $ 1,406
$ 2,193
Additional collateral to post 1,415
2,193

Interest rate swap derivatives
Liabilities with credit-risk-related contingent features 15,210
7,831
Additional collateral to post 10,064
6,579

NOTE 7.6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Avista Utilities

Avista Utilities’ maintained the same pension and other postretirement plans during the three months ended March 31, ~~2019~~2020 as those described as of December 31, ~~2018.~~2019. 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 $7.3 million in cash to the pension plan for the three months ended March 31, ~~2019~~2020 and it expects to contribute a total of ~~$22.0~~$22 million in ~~2019.~~2020.

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 months ended March 31 (dollars in thousands):



	Pension Benefits						Other Postretirement Benefits
	2020			2019			2020			2019
Service cost	$	5,546		$	4,874		$	979		$	772
Interest cost	6,971			7,138			1,515			1,372
Expected return on plan assets	(9,125		)	(7,815		)	(630		)	(718		)
Amortization of prior service cost	75			75			(275		)	(275		)
Net loss recognition	1,654			2,415			1,243			1,246
Net periodic benefit cost	$	5,121		$	6,687		$	2,832		$	2,397

Pension Benefits Other Postretirement Benefits
2019 2018 2019 2018
Service cost (a) $ 4,874
$ 5,450
$ 772
$ 804
Interest cost 7,138
6,466
1,372
1,197
Expected return on plan assets (7,815 ) (8,250 ) (718 ) (500 )
Amortization of prior service cost 75
75
(275 ) (815 )
Net loss recognition 2,415
2,088
1,246
1,655
Net periodic benefit cost $ 6,687
$ 5,829
$ 2,397
$ 2,341
Total service costs in the table above are recorded to the same accounts as labor expense. Labor and benefits expense is recorded to various projects based on whether the work is a capital project or an operating expense. Approximately 40 percent of all labor and benefits is capitalized to utility property and 60 percent is expensed to utility other operating expenses.

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

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

NOTE 8.7. INCOME TAXES

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



	2020					2019
Federal income taxes at statutory rates	$	11,961		21.0	%	$	30,639		21.0	%
Increase (decrease) in tax resulting from:
Tax effect of regulatory treatment of utility plant differences	(2,402		)	(4.2	)	(2,080		)	(1.4	)
State income tax expense	1,227			2.1		1,659			1.1
Acquisition costs	—			—		(1,824		)	(1.2	)
Settlement of equity awards	165			0.3		612			0.4
Other	(2,419		)	(4.2	)	1,011			0.7
Total income tax expense	$	8,532		15.0	%	$	30,017		20.6	%

2019 2018
Federal income taxes at statutory rates $ 30,639
21.0 % $ 13,790
21.0 %
Increase (decrease) in tax resulting from:
Tax effect of regulatory treatment of utility plant differences (2,080 ) (1.4 ) (1,018 ) (1.6 )
State income tax expense 1,659
1.1
964
1.5
Acquisition costs (1,824 ) (1.2 ) 46
0.1
Settlement of equity awards 612
0.4
(990 ) (1.5 )
Other 1,011
0.7
(2,082 ) (3.2 )
Total income tax expense $ 30,017
20.6 % $ 10,710
16.3 %

NOTE 9.8. COMMITTED LINES OF CREDIT

Avista Corp.

Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million ~~that expires~~. The Company expects to amend and extend the revolving line of credit agreement in the second quarter for a revised term of one additional year beyond the current maturity date of April 2021,. with the option to extend for an additional one year period. The committed line of credit is secured by non-transferable first mortgage bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.

Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company’s revolving committed line of credit were as follows as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):



	March 31,			December 31,
	2020			2019
Balance outstanding at end of period	$	185,000		$	182,300
Letters of credit outstanding at end of period	$	32,983		$	21,473
Average interest rate at end of period	1.66		%	2.64		%

March 31, December 31,
2019 2018
Balance outstanding at end of period (1) $ 119,000
$ 190,000
Letters of credit outstanding at end of period $ 60,103
$ 10,503
Average interest rate at end of period 3.31 % 3.18 %
As of March 31, 2020 and December 31, 2019, the borrowings outstanding under Avista Corp.'s committed line of credit were


~~(1)~~	~~As of March 31, 2019 and December 31, 2018, the balance outstanding was classified as short-term borrowings on the Condensed Consolidated Balance Sheet.~~

classified as short-term borrowings on the Condensed Consolidated Balance Sheet.

AEL&P

AEL&P has a committed line of credit in the amount of ~~$25.0~~$25.0 million that expires in November ~~2019~~.2024. As of March 31, ~~2019~~2020 and December 31, ~~2018,~~2019, there were no borrowings orof $0 and $3.5 million, respectively, and there were no letters of credit outstanding under this committed line of credit. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the committed line of credit.

NOTE 9. CREDIT AGREEMENT

Credit Agreement

On April 6, 2020, the Company entered into a Credit Agreement with U.S. Bank National Association, as Lender and Administrative Agent, and CoBank, ACB, as Lender in the amount of $100 million at an interest rate of 1-Month LIBOR plus 125 basis points with a maturity date of April 5, 2021. Loans under this agreement are unsecured and have a variable annual interest rate determined by either the Eurodollar rate or the Alternative Base Rate depending on the type of loan selected by Avista Corp.

The Credit Agreement contains customary covenants and default provisions, including a covenant not to permit the ratio of "consolidated total debt" to "consolidated total capitalization" of Avista Corp. to be greater than 65 percent at any time.

The Company has borrowed the entire $100 million available under this agreement, which is being used to provide additional liquidity. The amount can be repaid early; however, the amount repaid cannot be re-borrowed.

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NOTE 10. LONG-TERM DEBT TO AFFILIATED TRUSTS

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

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The distribution rates paid were as follows during the three months ended March 31, ~~2019~~2020 and the year ended December 31, ~~2018:~~2019:



	March 31,		December 31,
	2020		2019
Low distribution rate	2.46	%	2.79	%
High distribution rate	2.79	%	3.61	%
Distribution rate at the end of the period	2.46	%	2.79	%

March 31, December 31,
2019 2018
Low distribution rate 3.50 % 2.36 %
High distribution rate 3.61 % 3.61 %
Distribution rate at the end of the period 3.50 % 3.61 %

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

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

NOTE 11. FAIR VALUE

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

The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to 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 in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

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

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

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The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):



	March 31, 2020				December 31, 2019
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	963,500	$	1,107,956	$	963,500	$	1,124,649
Long-term debt (Level 3)	947,000		949,144		947,000		1,048,440
Snettisham finance lease obligation (Level 3)	53,850		56,900		54,550		58,000
Long-term debt to affiliated trusts (Level 3)	51,547		33,506		51,547		41,238

March 31, 2019 December 31, 2018

Carrying
Value

Estimated
Fair Value

Carrying
Value

Estimated
Fair Value
Long-term debt (Level 2) $ 1,053,500
$ 1,155,199
$ 1,053,500
$ 1,142,292
Long-term debt (Level 3) 767,000
734,742
767,000
734,742
Snettisham finance lease obligation (Level 3) 56,545
56,900
57,210
55,600
Long-term debt to affiliated trusts (Level 3) 51,547
38,145
51,547
38,145

These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The price ranges obtained from the third party brokers consisted of par values of ~~74.00~~65.00 to ~~121.59,~~133.98, where a par value of 100.0 represents the carrying value recorded on the Condensed Consolidated Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices; however, due to their limited trading activity, they are classified as Level 2 because brokers must generate quotes and make estimates if there is no trading activity near a period end. Level 3 long-term debt consists of private placement bonds and debt to affiliated trusts, which typically have no secondary trading activity. Fair values in Level 3 are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for Avista Corp. bonds. Due to the unique nature of the Snettisham capital 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 lease obligation was discounted to present value using the Morgan Markets A Ex-Fin discount rate as published on March 31, ~~2019.~~2020.

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Condensed Consolidated Balance Sheets as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 at fair value on a recurring basis (dollars in thousands):


	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total		Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
March 31, 2019
March 31, 2020
Assets:
Energy commodity derivatives	$	—	$	31,363	$	—	$	(31,113	)	$	250	$	—	$	35,061	$	—	$	(30,849	)	$	4,212
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		123		(123		)	—		—		—		26		(26		)	—
Foreign currency exchange derivatives	—		15		—		(15		)	—		—		36		—		(36		)	—
Interest rate swap derivatives	—		5,090		—		(2,284		)	2,806
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)	1,758		—		—		—			1,758		2,642		—		—		—			2,642
Equity securities (2)	6,456		—		—		—			6,456		5,585		—		—		—			5,585
Total	$	8,214	$	36,468	$	123	$	(33,535	)	$	11,270	$	8,227	$	35,097	$	26	$	(30,911	)	$	12,439
Liabilities:
Energy commodity derivatives	$	—	$	68,668	$	—	$	(66,030	)	$	2,638	$	—	$	30,464	$	—	$	(30,154	)	$	310
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		2,227		(123		)	2,104		—		—		2,279		(26		)	2,253
Power exchange agreement	—		—		612		—			612
Foreign currency exchange derivatives	—		15		—		(15		)	—		—		103		—		(36		)	67
Interest rate swap derivatives	—		15,210		—		(5,144		)	10,066		—		112,238		—		(27,090		)	85,148
Total	$	—	$	83,893	$	2,839	$	(71,312	)	$	15,420	$	—	$	142,805	$	2,279	$	(57,306	)	$	87,778

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	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total		Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
December 31, 2018
December 31, 2019
Assets:
Energy commodity derivatives	$	—	$	36,252	$	—	$	(35,982	)	$	270	$	—	$	41,546	$	—	$	(40,452	)	$	1,094
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		31		(31		)	—		—		—		27		(27		)	—
Foreign currency exchange derivatives												—		97		—		—			97
Interest rate swap derivatives	—		10,566		—		(440		)	10,126		—		1,552		—		(963		)	589
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)	1,745		—		—		—			1,745		2,232		—		—		—			2,232
Equity securities (2)	6,157		—		—		—			6,157		6,271		—		—		—			6,271
Total	$	7,902	$	46,818	$	31	$	(36,453	)	$	18,298	$	8,503	$	43,195	$	27	$	(41,442	)	$	10,283
Liabilities:
Energy commodity derivatives	$	—	$	89,283	$	—	$	(87,199	)	$	2,084	$	—	$	45,144	$	—	$	(43,830	)	$	1,314
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		2,805		(31		)	2,774		—		—		3,003		(27		)	2,976
Power exchange agreement	—		—		2,488		—			2,488
Power option agreement	—		—		1		—			1
Foreign currency exchange derivatives	—		45		—		—			45
Interest rate swap derivatives	—		7,831		—		(970		)	6,861		—		34,056		—		(7,733		)	26,323
Total	$	—	$	97,159	$	5,294	$	(88,200	)	$	14,253	$	—	$	79,200	$	3,003	$	(51,590	)	$	30,613


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

The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 65 for additional discussion of derivative netting.

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

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

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

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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 ~~$0.5~~$0.4 million as of March 31, ~~2019~~2020 and December 31, ~~2018.~~2019.

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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. The Company 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.

For the natural gas commodity exchange agreement, the Company uses the same Level 2 brokered 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 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 March 31, ~~2019~~2020 (dollars in thousands):



	Fair Value (Net) at
	March 31, 2020			Valuation Technique	Unobservable Input	Range and Weighted Average Price
Natural gas exchange agreement	$	(2,253	)	Internally derived weighted average cost of gas	Forward purchase prices	$1.16 - $1.80/mmBTU $1.47 Weighted Average
					Forward purchase prices	$1.16 - $1.80/mmBTU $1.47 Weighted Average
					Forward sales prices	$1.33 - $3.79/mmBTU $2.96 Weighted Average
					Purchase volumes	155,000 - 310,000 mmBTUs
					Sales volumes	60,000 - 310,000 mmBTUs

Fair Value (Net) at
March 31, 2019 Valuation Technique
Unobservable
Input
Range
Power exchange agreement $ (612 )
Surrogate facility
pricing
O&M charges $40.05-$52.59/MWh (1)
Transaction volumes 28,860 MWhs
Natural gas exchange
agreement
$ (2,104 ) Internally derived
weighted average
cost of gas
Forward purchase
prices
$1.70 - $2.98/mmBTU

Forward sales prices $1.63 - $4.11/mmBTU
Purchase volumes 270,000 - 310,000 mmBTUs
Sales volumes 60,000 - 310,000 mmBTUs

~~(1) The average O&M charges for the delivery year beginning in November 2018 are~~ ~~$45.61~~ ~~per MWh.~~

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.

The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the three months ended March 31 (dollars in thousands):



	Natural Gas Exchange Agreement			Power Exchange Agreement			Total
Three months ended March 31, 2020:
Balance as of January 1, 2020	$	(2,976	)	$	—		$	(2,976	)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1)	485			—			485
Settlements	238			—			238
Ending balance as of March 31, 2020 (2)	$	(2,253	)	$	—		$	(2,253	)
Three months ended March 31, 2019:
Balance as of January 1, 2019	$	(2,774	)	$	(2,488	)	$	(5,262	)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1)	8,977			(1,018		)	7,959
Settlements	(8,307		)	2,894			(5,413		)
Ending balance as of March 31, 2019 (2)	$	(2,104	)	$	(612	)	$	(2,716	)

Natural Gas Exchange Agreement Power Exchange Agreement Total
Three months ended March 31, 2019:
Balance as of January 1, 2019 $ (2,774 ) $ (2,488 ) $ (5,262 )
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1) 8,977
(1,018 ) 7,959
Settlements (8,307 ) 2,894
(5,413 )
Ending balance as of March 31, 2019 (2) $ (2,104 ) $ (612 ) $ (2,716 )

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Natural Gas Exchange Agreement Power Exchange Agreement Total
Three months ended March 31, 2018:
Balance as of January 1, 2018 $ (3,164 ) $ (13,245 ) $ (16,409 )
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1) 203
(1,877 ) (1,674 )
Settlements 156
4,959
5,115
Ending balance as of March 31, 2018 (2) $ (2,805 ) $ (10,163 ) $ (12,968 )


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


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

NOTE 12. COMMON STOCK

The Company ~~has~~had entered into four separate sales agency agreements under which the sales agents ~~may offer~~offered and ~~sell~~sold new shares of the Company’s common stock from time to time. ~~No shares were issued under these agreements during~~During the three months ended March 31, 2019. These agreements provide for the offering of a maximum of approximately 3.8 million shares, of which approximately 1.1 million remain unissued as of March 31, 2019. Subject to the satisfaction of customary conditions,2020 the Company ~~has~~did not issue shares under the ~~right to increase the maximum number of shares that may be offered under these~~sales agency agreements. These sales agency agreements expired on February 29, 2020. The Company is currently working on entering into new sales agency agreements.

NOTE 13. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss, net of tax, consisted of the following as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):

March 31, December 31,
2019 2018
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,048 and $2,091, respectively $ 7,706
$ 7,866



	March 31,		December 31,
	2020		2019
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,673 and $2,727, respectively	$	10,054	$	10,259

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


		Amounts Reclassified from Accumulated Other Comprehensive Loss								Amounts Reclassified from Accumulated Other Comprehensive Loss
Details about Accumulated Other Comprehensive Loss Components		2019			2018			Affected Line Item in Statement of Income		2020			2019			Affected Line Item in Statement of Income
Amortization of defined benefit pension items	Amortization of defined benefit pension items								Amortization of defined benefit pension items
Amortization of net prior service cost		$	(200	)	$	(228	)	(a)		$	(200	)	$	(200	)	(a)
Amortization of net loss		3,661			2,995			(a)		3,100			3,661			(a)
Adjustment due to effects of regulation		(3,258		)	(2,508		)	(a)		(2,641		)	(3,258		)	(a)
		203			259			Total before tax		259			203			Total before tax
		(43		)	(55		)	Tax expense		(54		)	(43		)	Tax expense
		$	160		$	204		Net of tax		$	205		$	160		Net of tax


(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 76 for additional details).

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NOTE 14. 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 months ended March 31 (in thousands, except per share amounts):


	2019		2018		2020		2019
Numerator:
Net income attributable to Avista Corp. shareholders	$	115,794	$	54,890	$	48,424	$	115,794
Denominator:
Weighted-average number of common shares outstanding-basic	65,733		65,639		67,239		65,733
Effect of dilutive securities:
Performance and restricted stock awards	208		292		142		208
Weighted-average number of common shares outstanding-diluted	65,941		65,931		67,381		65,941
Earnings per common share attributable to Avista Corp. shareholders:
Basic	$	1.76	$	0.84	$	0.72	$	1.76
Diluted	$	1.76	$	0.83	$	0.72	$	1.76

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

NOTE 15. COMMITMENTS AND CONTINGENCIES

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

~~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 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 Corp. is reducing TDG by constructing spill crest modifications on spill gates at the dam. These modifications have been shown to be effective in reducing TDG downstream. TDG monitoring and analysis is ongoing. Under the terms of the mitigation plan, Avista Corp. will continue to work with stakeholders to determine the degree to which TDG abatement reduces future mitigation obligations. The Company has sought, and will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue.

~~Legal Proceedings Related to the Terminated Acquisition by Hydro One~~

~~See Note 17 for information regarding the termination of the proposed acquisition of the Company by Hydro One.~~

In connection with the now terminated acquisition, three lawsuits were filed in the United States District Court for the Eastern District of Washington and were subsequently voluntarily dismissed by the plaintiffs.

~~One lawsuit was filed in the Superior Court for the State of Washington in and for Spokane County, captioned as follows:~~

~~Fink v. Morris, et al.,~~ ~~No. 17203616-6 (filed September 15, 2017, amended complaint filed October 25, 2017).~~

The complaint generally alleged that the members of the Board of Directors of Avista Corp. breached their fiduciary duties by, among other things, conducting an allegedly inadequate sale process and agreeing to the acquisition at a price that allegedly undervalued Avista Corporation, and that Hydro One Limited, Olympus Holding Corp., and Olympus Corp. aided and abetted those purported breaches of duty. The complaint sought various remedies, including monetary damages, attorneys’ fees and expenses. Subsequent to the termination of the proposed acquisition in January 2019, the complaint was voluntarily dismissed by the plaintiffs.

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2015 Washington General Rate Cases

In January 2016, the Company received an order (Order 05) that concluded its electric and natural gas general rate cases that were originally filed with the WUTC in February 2015. New electric and natural gas rates were effective on January 11, 2016.

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

In January 2016, the Industrial Customers of Northwest Utilities, the Public Counsel Unit of the Washington State Office of the Attorney General (PC) and the WUTC Staff, which is a separate party in the general rate case proceedings from the WUTC Advisory Staff, filed Motions for Clarification requesting the WUTC to clarify their attrition adjustment and the end result electric revenue amounts. The Motions for Clarification suggested that the electric revenue decrease should have been significantly larger than what was included in Order 05.

~~In February 2016, the WUTC 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

In March 2016, PCPublic Counsel (PC) filed in Thurston County Superior Court a Petition for Judicial Review of the WUTC's Order 05 and Order ~~06 described above.~~06. In April 2016, this matter was certified for review directly by the Court of Appeals, an intermediate appellate court in the State of Washington.

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On August 7, 2018, the Court of Appeals issued a "Published Opinion" (Opinion) which concluded that the WUTC's use of an attrition allowance to calculate Avista Corp.'s rate base violated Washington law. In the Opinion, the Court stated that because the projected additions to rate base in the future were not "used and useful" for service at the time the request for the rate increase was made, they may not lawfully be included in the Company's rate base to justify a rate increase. Accordingly, the Court concluded that the WUTC erred in including an attrition allowance in the calculation of Avista Corp.’s electric and natural gas rate base. The Court noted, however, that the law does not prohibit an attrition allowance in the calculation, for ratemaking purposes, of recoverable operating and maintenance expense. Since the WUTC order provided one lump sum attrition allowance without distinguishing what portion was for rate base and which was for operating and maintenance expenses or other considerations, the Court struck all portions of the attrition allowance attributable to Avista Corp.'s rate base and reversed and remanded the case for the WUTC to recalculate Avista Corp.’s rates without including an attrition allowance in the calculation of rate base.

On ~~October 1, 2018,~~March 6, 2020, the Court of Appeals terminated its review of this case, remanding it back to the Thurston County Superior Court. On April 17, 2019, the Thurston County Superior Court issued a Remand Order, granting a Joint Motion of Avista Corp., PC andCompany received an order from the WUTC that will require it to ~~remand the case back to the WUTC. A pre-hearing conference which will set forth the procedural schedule will be held on May 17, 2019.~~

~~The total attrition allowance approved by the WUTC in Order 05 and reaffirmed in Order 06 was $35.2~~refund $8.5 million ~~with $28.3 million related~~ to electric and ~~$6.9~~natural gas customers. The Company will refund $4.9 million ~~related~~to electric customers and $3.6 million to natural ~~gas.~~gas customers. The Company ~~believes the potential amount to return to customers is limited to the 2015 general rate cases because~~previously recorded a customer refund liability of $3.6 million in ~~subsequent~~2019.

Boyds Fire (State of Washington ~~general rate cases (specifically those approved in April 2018), the WUTC did not include any attrition allowance on rate base. Even though~~Department of Natural Resources v. Avista)

On August 19, 2019, the Company ~~believes~~was served with a complaint filed by the ~~issue only relates~~State of Washington Department of Natural Resources, seeking recovery of fire suppression costs and related expenses incurred in connection with a wildfire that occurred in Ferry County, Washington in August 2018. Specifically, the complaint alleges that the fire, which became known as the “Boyds Fire,” was caused by a dead ponderosa pine tree falling into an overhead distribution line, and that Avista Corp. was negligent in failing to identify and remove it before the ~~2015 general rate cases,~~tree came into contact with the ~~Company cannot predict~~line. Avista Corp. disputes that the ~~outcome~~tree in question was the cause of the fire and that it was negligent in failing to identify and remove it. The case is in the early stages of discovery and the plaintiff has not yet provided a statement specifying damages. Because the resolution of this ~~matter at this time and~~claim remains uncertain, legal counsel cannot ~~estimate how much,~~express an opinion on the extent, if any, of the ~~attrition allowance may be removed from~~Company’s liability, nor is it possible for the ~~general rate cases or if other amounts from subsequent general rate cases will be included.~~Company to estimate the impact of any outcome at this time. The Company intends to vigorously defend itself in the litigation.

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 2021 of the Notes to Consolidated Financial Statements" in the ~~2018~~2019 Form 10-K for additional discussion regarding other contingencies.

NOTE 16. INFORMATION BY BUSINESS SEGMENTS

The business segment presentation reflects the basis used by the Company's management to analyze performance and determine the allocation of resources. The Company's management evaluates performance based on income (loss) from operations before income taxes as well as net income (loss) 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,

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

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



	Avista Utilities		Alaska Electric Light and Power Company			Total Utility		Other			Intersegment Eliminations (1)			Total
For the three months ended March 31, 2020:
Operating revenues	$	377,205	$	12,202		$	389,407	$	823		$	—		$	390,230
Resource costs	129,557		(10		)	129,547		—			—			129,547
Other operating expenses	91,279		3,217			94,496		1,360			—			95,856
Depreciation and amortization	48,974		2,447			51,421		235			—			51,656
Income (loss) from operations	76,534		6,246			82,780		(587		)	—			82,193
Interest expense (3)	24,983		1,589			26,572		131			(86		)	26,617
Income taxes	7,404		1,301			8,705		(173		)	—			8,532
Net income (loss) attributable to Avista Corp. shareholders	45,979		3,395			49,374		(950		)	—			48,424
Capital expenditures (4)	94,056		1,470			95,526		109			—			95,635
For the three months ended March 31, 2019:
Operating revenues	$	377,702	$	10,881		$	388,583	$	7,898		$	—		$	396,481
Resource costs	138,712		(1,365		)	137,347		—			—			137,347
Other operating expenses (2)	100,583		3,059			103,642		7,355			—			110,997
Depreciation and amortization	46,507		2,407			48,914		209			—			49,123
Income from operations	60,224		6,513			66,737		334			—			67,071
Interest expense (3)	24,264		1,596			25,860		588			(440		)	26,008
Income taxes	28,544		1,363			29,907		110			—			30,017
Net income attributable to Avista Corp. shareholders	111,901		3,552			115,453		341			—			115,794
Capital expenditures (4)	92,309		1,306			93,615		162			—			93,777
Total Assets:
As of March 31, 2020:	$	5,808,619	$	272,178		$	6,080,797	$	112,213		$	(19,011	)	$	6,173,999
As of December 31, 2019:	$	5,713,268	$	271,393		$	5,984,661	$	113,390		$	(15,595	)	$	6,082,456

Avista
Utilities
Alaska Electric Light and Power Company Total Utility Other
Intersegment
Eliminations
(1)
Total
For the three months ended March 31, 2019:
Operating revenues $ 377,702
$ 10,881
$ 388,583
$ 7,898
$ —
$ 396,481
Resource costs 138,712
(1,365 ) 137,347
—
—
137,347
Other operating expenses (2) 100,583
3,059
103,642
7,355
—
110,997
Depreciation and amortization 46,507
2,407
48,914
209
—
49,123
Income from operations 60,224
6,513
66,737
334
—
67,071
Interest expense (3) 24,264
1,596
25,860
588
(440 ) 26,008
Income taxes 28,544
1,363
29,907
110
—
30,017
Net income attributable to Avista Corp. shareholders 111,901
3,552
115,453
341
—
115,794
Capital expenditures (4) 92,309
1,306
93,615
162
—
93,777
For the three months ended March 31, 2018:
Operating revenues $ 388,754
$ 13,663
$ 402,417
$ 6,944
$ —
$ 409,361
Resource costs 151,665
2,953
154,618
—
—
154,618
Other operating expenses (2) 75,139
2,831
77,970
6,824
—
84,794
Depreciation and amortization 43,267
1,466
44,733
181
—
44,914
Income (loss) from operations 88,145
6,122
94,267
(61 ) —
94,206
Interest expense (3) 23,965
894
24,859
335
(165 ) 25,029
Income taxes 10,417
1,464
11,881
(1,171 ) —
10,710
Net income (loss) attributable to Avista Corp. shareholders 55,540
3,772
59,312
(4,422 ) —
54,890
Capital expenditures (4) 81,176
641
81,817
214
—
82,031
Total Assets:
As of March 31, 2019: (5) $ 5,524,962
$ 275,488
$ 5,800,450
$ 107,398
$ (17,865 ) $ 5,889,983
As of December 31, 2018: $ 5,458,104
$ 272,950
$ 5,731,054
$ 87,050
$ (35,528 ) $ 5,782,576


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


(2)	Other operating expenses for Avista Utilities for the three months ended March 31, 2019 include merger transaction costs ~~of $19.7 million,~~ which are separately disclosed on the Condensed Consolidated Statements of Income. ~~The three months ended March 31, 2018 include merger transaction costs of $0.7 million, which are also separately disclosed.~~


(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.


~~(5)~~	~~The total assets for Other as of March 31, 2019 includes $15.9 million in assets held for sale related to the sale of METALfx. See Note 18 for further discussion.~~

NOTE 17. TERMINATION OF PROPOSED ACQUISITION BY HYDRO ONE

On July 19, 2017, Avista Corp. entered into a Merger Agreement that provided for Avista Corp. to become an indirect, wholly-owned subsidiary of Hydro One, subject to the satisfaction or waiver of specified closing conditions, including approval by regulatory agencies. Hydro One, based in Toronto, is Ontario’s largest electricity transmission and distribution provider.

~~At the effective time~~Termination of the acquisition, each share of Avista Corp. common stock issued and outstanding, other than shares of Avista Corp. common stock that are owned by Hydro One and its affiliates, were to be converted automatically into the right to receive an amount in cash equal to $53, without interest.Merger Agreement

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~~Denial by Regulatory Commissions~~

~~The closing of the acquisition was subject to various conditions, including, among others, receipt of regulatory approval from the WUTC, IPUC, MPSC, OPUC, and the RCA.~~

~~Washington~~ - On March 27, 2018, Avista Corp. and Hydro One filed an all-parties (including the WUTC Staff), all-issues settlement agreement with the WUTC recommending approval of the acquisition of the Company by Hydro One. The settlement agreement was subject to WUTC approval.

On December 5, 2018, the Company and Hydro One received a decision from the WUTC, denying the proposed acquisition. On December 17, 2018, the Company and Hydro One filed a petition requesting that the WUTC reconsider its December 5, 2018 order denying approval of the acquisition, together with a petition requesting that the WUTC rehear the matter to accept new evidence. Under Washington State law, the WUTC had 20 days to act on the petition for reconsideration.

On January 8, 2019, the WUTC provided notice of its deemed denial by operation of law of the filed petition to reconsider the denial of approval for the acquisition. The WUTC did not take action on the petition within the required 20 days of its filing so the petition was automatically denied under the state's Administrative Procedure Act. In the same notice, the WUTC also denied the petition for a rehearing on the basis that it does not apply.

~~Idaho~~ -On April 13, 2018, Avista Corp. and Hydro One filed an all-issues settlement agreement (to which the IPUC Staff was a party) with the IPUC recommending approval of the acquisition of the Company by Hydro One. The settlement agreement was subject to IPUC approval.

~~On January 3, 2019, the Company and Hydro received a decision from the IPUC, finding that the proposed acquisition was not permitted by Idaho law~~. ~~Avista Corp. and Hydro One had until January 24, 2019 to file a petition for reconsideration with the IPUC, which they did not file.~~

~~Oregon~~ - On May 25, 2018, Avista Corp. and Hydro One filed an all-parties (including the OPUC Staff), all-issues settlement agreement with the OPUC related to the Oregon merger proceeding. The settlement agreement was subject to review and approval by the OPUC.

~~On January 15, 2019, due~~Due to the denial of the ~~acquisition~~proposed merger by ~~the WUTC and IPUC, the OPUC issued an order suspending indefinitely the procedural schedule in its merger docket until Hydro One and Avista Corp. informed the OPUC that they had sought a reversal~~certain of the ~~denial decisions through appeal or other means that would provide a justiciable issue for the OPUC to address.~~

~~Termination of the Merger Agreement~~

OnCompany's regulatory commissions, on January 23, 2019, Avista Corp., Hydro One and certain subsidiaries thereof, entered into a Termination Agreement indicating their mutual agreement to terminate the Merger Agreement, effective immediately. Pursuant to the terms of the Termination Agreement, Hydro One paid Avista Corp. a $103 million termination fee on January 24, 2019. The termination fee was used for reimbursing the Company's transaction costs incurred from 2017 to 2019. The balance of the termination fee remaining after payment of 2019 transaction costs and applicable income taxes was used for general corporate purposes and reduced the Company's need for external financing. The 2019 costs totaled $19.7 million pre-tax and included financial advisers' fees, legal fees, consulting fees and employee time.

~~Other Information Related to the Terminated Acquisition~~

Due to the termination of the acquisition, all the financial commitments that were included in the various settlement agreements with the commissions for the proposed acquisition will not be required to be performed or observed.

The Company incurred significant transaction costs consisting primarily of consulting, banking fees, legal fees and employee time, and these costs are not being passed through to customers. When the Company was assuming the transaction was going to be completed, a significant portion of these costs were not deductible for income tax purposes. Now that the transaction has been terminated, the Company expects more of the previously incurred transaction costs to be deductible so it expects additional tax benefits from these costs in 2019.

See Note 15 for discussion of shareholder lawsuits filed against the Company, the Company’s directors, Hydro One, Olympus Holding Corp., and Olympus Corp. in relation to the Merger Agreement and the proposed acquisition.

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NOTE 18. ~~ASSETS HELD FOR~~ SALE OF METALfx

In April 2019, Bay Area Manufacturing, Inc., a non-regulated subsidiary of Avista Corp., entered into a definitive agreement to sell its interest in METALfx to an independent third party. The transaction iswas a stock sale for a total cash purchase price of $17.5 million plus cash on-hand, subject to customary closing adjustments. The transaction closed on April 18, 2019, and as of that date the Company has no further involvement with METALfx.

The purchase price of $17.5 million, as adjusted, was divided among the security holders of METALfx, including the minority shareholder, pro rata based on ownership (Avista Corp. owned 89.2 percent of the equity of METALfx). As required under the purchase agreement, $1.2 million (7 percent of the purchase price) will be held in escrow for 24 months from the closing of the transaction to satisfy certain indemnification ~~obligations under the purchase agreement.~~obligations.

When all escrow amounts are released, ~~based on preliminary estimates,~~ the ~~sales~~sale transaction ~~is expected to~~will provide cash proceeds to Avista Corp., net of payments to the minority holder, contractually obligated compensation payments and other transaction expenses, of ~~$16.6 million and result~~$16.5 million. The sale has resulted in a net gain after-tax of $3.3 million, with $2.4 ~~million.~~million recognized in the three months ended March 31, 2019. The Company expects to receive the full amount of its portion of the escrow accounts; therefore, the full amounts ~~are~~have been included in the gain calculation. The gross gain is included in "Other income," the transaction expenses paid are included in "Non-utility Other operating expenses" and any taxes associated with the sale are included in "Income tax expense" on the Condensed Consolidated Statements of Income.

Prior to the completion of the sales transaction, METALfx was not a reportable business segment and was included in other in the business segment footnote at Note 16. ~~As of March 31, 2019, the assets of METALfx met the criteria for held for sale presentation; however, this~~This transaction does not meet the criteria for discontinued operations as it does not represent a strategic shift that will have a major effect on the Company's ongoing operations. ~~The Company elected to present the required held for sale information below, rather than modifying the Condensed Consolidated Balance Sheet. The major classes~~

Table of ~~assets and liabilities that were held for sale as of March 31, 2019 were as follows (dollars in thousands):~~Contents

March 31, 2019
Assets:
Current Assets:
Cash and cash equivalents $ 1,026
Accounts and notes receivable-less allowances of $5 3,048
Materials and supplies 2,922
Other current assets 159
Total current assets 7,155
Goodwill 5,247
Deferred income taxes (1) 1,598
Other property and investments-net and other non-current assets 1,874
Total assets $ 15,874
Liabilities:
Current Liabilities:
Accounts payable $ 760
Other current liabilities 901
Total current liabilities 1,661
Other non-current liabilities 152
Total liabilities $ 1,813


~~(1)~~
~~On a standalone basis, METALfx has a deferred tax asset; however, on a consolidated basis, Avista Corp. has a net deferred tax liability which does not include the deferred tax asset above.~~AVISTA CORPORATION

~~Table of Contents~~

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of

Avista Corporation

Spokane, Washington

Results of Review of Interim Financial Information

We have reviewed the accompanying condensed consolidated balance sheet of Avista Corporation and subsidiaries (the "Company") as of March 31, ~~2019,~~2020, and the related condensed consolidated statements of income, comprehensive income, equity and cash flows, for the three-month periods ended March 31, ~~2019~~2020 and ~~2018,~~2019, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, ~~2018,~~2019, 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 ~~19, 2019,~~25, 2020, 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, ~~2018,~~2019, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Seattle, Washington

May ~~1, 2019~~7, 2020

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations has been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q. The interim Management’s Discussion and Analysis of Financial Condition and Results of Operations does not contain the full detail or analysis which would be included in a full fiscal year Form 10-K; therefore, it should be read in conjunction with the Company's ~~2018~~2019 Form 10-K.

Business Segments

Our business segments have not changed during the three months ended March 31, ~~2019.~~2020. See the ~~2018~~2019 Form 10-K as well as “Note 16 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.

The following table presents net income ~~(loss)~~ attributable to Avista Corp. shareholders for each of our business segments (and the other businesses) for the three months ended March 31 (dollars in thousands):


	2019		2018			2020			2019
Avista Utilities	$	111,901	$	55,540		$	45,979		$	111,901
AEL&P	3,552		3,772			3,395			3,552
Other	341		(4,422		)	(950		)	341
Net income attributable to Avista Corp. shareholders	$	115,794	$	54,890		$	48,424		$	115,794

Executive Level Summary

Overall Results

Net income attributable to Avista Corp. shareholders was $48.4 million for the three months ended March 31, 2020, compared to $115.8 million for the three months ended March 31, ~~2019, an increase from $54.9 million for the three months ended March 31, 2018.~~

~~The increase in earnings was due to an increase in earnings at Avista Utilities and our other businesses, partially offset by a decrease in earnings at AEL&P.~~2019.

Avista Utilities' ~~earnings increased~~net income decreased due to the receipt, in the first quarter of 2019, of a $103 million termination fee from Hydro One ~~as well as~~(see "Note 17 of the ~~positive impact of general rate increases and customer growth. These increases~~Notes to Condensed Consolidated Financial Statements") which were partially offset by ~~final transaction costs~~associated expenses of $19.7 million pre-tax. In addition, during the first quarter of 2020, we recorded an accrual for customer refunds related to the ~~Hydro One transaction, taxes associated with~~outcome of the ~~termination fee, increased net~~2015 Washington general rate cases outcome (see "Regulatory Matters"), an accrual for disallowed replacement power ~~supply costs, transmission~~during an unplanned outage at Colstrip (see "Regulatory Matters"), and ~~distribution operating and maintenance costs (other operating expenses), depreciation and amortization, and interest expense.~~

~~AEL&P earnings decreased primarily due to~~we had an increase in other operating ~~expenses.~~expenses and depreciation and amortization, which were partially offset by a decrease in our income tax expense and resource costs.

AEL&P net income decreased slightly, primarily due to a net decrease in income from operations that was caused by an increase in resource costs that was larger than the increase in operating revenues.

The increase in ~~earnings~~net income at our other businesses for the year-to-date was primarily ~~because~~due to the ~~first quarter~~sale of ~~2018 included~~ an ~~impairment of one of our investments~~equity investment and ~~expenses associated with a renovation project. Also, there were~~ increased earnings from ~~equity investments in the first quarter of 2019 as compared to the first quarter of 2018.~~our other investments.

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

~~General Rate Cases~~COVID-19 Global Pandemic

The COVID-19 global pandemic is currently impacting all aspects of our business, as well as the global, national and ~~Regulatory Lag~~local economies. It is likely that the continued spread of COVID-19 and efforts to contain the virus, such as quarantines or closures or reduced operations of businesses, governmental agencies and other institutions, will continue to cause an economic slowdown and possibly a recession, resulting in significant disruptions in various public, commercial or industrial activities and causing employee absences which could interfere with operation and maintenance of the Company’s facilities. These circumstances have affected and will likely continue to adversely affect our operations, results of operations, financial condition and cash flows in the following ways:

Operations

We ~~expect~~provide critical services to ~~experience regulatory lag during the period 2019 through 2021 due~~our customers. Accordingly, it is paramount that we keep our employees who operate our business safe so that we continue to the delay in general rate case filings related to the terminated Hydro One transaction and our continued investment in utility infrastructure. On April 30, 2019 we filed general rates cases in Washington that are two-year rate plans.provide reliable service. We ~~also filed a general rate case in Oregon in March and we expect to file general rate cases in Idaho~~implemented business continuity plans in the ~~second quarter~~context of ~~2019.~~this global pandemic. We ~~expect these cases to provide rate relief in early 2020 and begin reducing the regulatory lag~~believe that ~~we have been experiencing. Going forward,~~ we will continue to ~~strive~~be able to ~~reduce the regulatory timing lag~~conduct our utility operations effectively and ~~more closely align~~provide safe and reliable service to our ~~earned returns with those authorized by 2022. This will require adequate and timely rate relief in our jurisdictions. See "Regulatory Matters" for additional discussion of the 2019 general rate cases.~~customers.

~~Termination of the Proposed Acquisition by Hydro One~~

In July 2017, Avista Corp. entered into a Merger Agreement that provided for Avista Corp. to become an indirect, wholly-owned subsidiary of Hydro One, subject to the satisfaction or waiver of specified closing conditions, including approval by regulatory agencies.

On January 23, 2019, Avista Corp., Hydro One and certain subsidiaries thereof, entered into a termination agreement (Termination Agreement) indicating their mutual agreement to terminate the Merger Agreement, effective immediately. Pursuant to the terms of the Merger Agreement and the Termination Agreement, Hydro One paid Avista Corp. a $103 million

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~~termination fee~~We have taken precautions concerning employee and facility hygiene, imposed travel limitations on ~~January 24, 2019. The termination fee~~employees and directed our employees to work remotely whenever possible. Protocols have been established and implemented to protect employees and the public when work requires public interaction. We have informed retail customers and state regulators that disconnections and late fees for non-payment are temporarily suspended.

Although we have not experienced any significant issues to date, it is possible that COVID-19 could have a negative impact on the ability of suppliers, vendors or contractors to perform, which could increase operating costs and delay and/or increase the costs of capital projects.

Results of Operations

During the three months ended March 31, 2020, we did not experience a material reduction in overall customer loads or retail revenues as the economic restrictions and closures did not take effect in our service territory until mid-March. In the month of April, there was ~~used~~a decrease of approximately 5 percent on overall electric load, which consisted of approximately a 12 percent decrease in commercial and a 14 percent decrease in industrial, which was partially offset by approximately a 10 percent increase in residential. In contrast, natural gas loads appear to be within normal bounds for ~~reimbursing~~the time of year. We expect a gradual economic recovery and prolonged high unemployment that will depress load and customer growth into 2021. We have decoupling and other regulatory mechanisms in Washington, Idaho and Oregon, which mitigate the impact of lower loads and revenues for residential and certain commercial customer classes. There are limitations on increases in decoupling surcharges in a particular year and revenue recognition criteria established by GAAP. Although we expect to ultimately recognize all decoupling revenue, there can be a delay in revenue recognition. Over 90 percent of our ~~transaction costs incurred from 2017~~utility revenue is covered by regulatory mechanisms.

We have suspended customer disconnections and late fees for non-payment. In combination with the economic downturn, we increased our bad debt expense by $1.6 million in the first quarter and expect bad debt expense to ~~2019. These costs, including income taxes, total approximately $51 million. The balance~~increase by $3.4 million for the remainder of 2020 as compared to our original forecast. We expect to offset at least some of the ~~termination fee~~negative impacts of COVID-19 at Avista Utilities with cost savings, and we have filed petitions for an accounting order in each of our jurisdictions to defer the recognition of COVID-19 expenses as well as identified cost savings of other COVID-19 related benefits.

Coronavirus Aid, Relief, and Economic Security Act (the CARES Act)

On March 27, 2020, the CARES Act, an economic stimulus package in response to COVID-19 was ~~used~~signed into law. The CARES Act contains corporate income tax provisions, including providing temporary changes regarding the prior and future utilization of net operating losses, temporary suspension of certain payment requirements for ~~general corporate purposes~~the employer portion of social security taxes, and ~~reduced~~the creation of certain refundable employee retention credits.

Financial Condition, Liquidity and Cash Flows

For 2020, we expect our ~~need~~net cash flows from operations to decrease primarily due to lower expected revenues from retail sales of electricity and natural gas and lower payments from customers.

We do not expect the impact of COVID-19 to change our estimate of utility capital expenditures for ~~external financing. For further information, see "Note 17~~2020. It is possible that a prolonged economic restrictions or business interruption could cause a decrease in our utility capital expenditures.

Disruptions and overall declines in the financial markets have decreased the fair value of pension plan assets and lower discount rates will increase the pension liability. This could ultimately increase future pension plan funding requirements and expenses. The impact on pension plan assets is mitigated as a significant portion of the ~~Notes~~assets are fixed-income securities with a target of 35 percent invested in equity securities.

As of March 31, 2020, we had $182.0 million of available liquidity under the Avista Corp. $400.0 million committed line of credit and $25.0 million under the AEL&P committed line of credit. As of April 30, 2020, we had $188.1 million of available liquidity under the Avista Corp. $400.0 million committed line of credit and $25.0 million under the AEL&P committed line of credit. In addition, in April 2020, we entered into a one-year credit agreement with two financial institutions in the amount of $100.0 million. We borrowed the entire $100.0 million available under this agreement, which was added to ~~Condensed Consolidated Financial Statements.”~~our cash reserves.

After considering the impacts of COVID-19, including the expectation of lower net operating cash flows, and the expected issuances of long-term debt and equity during 2020, we expect net cash flows from operations, together with cash available under our committed lines of credit and the $100.0 million borrowed under the new credit agreement, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.

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AVISTA CORPORATION

However, disruption, weakness and volatility in the financial markets could increase our costs, and delay our ability, to fund capital requirements from conventional sources. To the extent that access to the capital markets is adversely affected, we may need to consider alternative sources of funding for operations and for working capital, any of which could increase our cost of capital.

In addition to any of the issues identified above, we cannot predict the duration and severity of the COVID-19 global pandemic. The longer and more severe the economic restrictions and business disruption is, the greater the impact on our operations, results of operations, financial condition and cash flows will be.

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.

Avista Utilities

Washington General Rate Cases

2015 General Rate Cases

In January 2016, we received an order ~~which was reaffirmed by the WUTC in February 2016~~ that concluded our electric and natural gas general rate cases that were originally filed with the WUTC in February 2015. New electric and natural gas rates were effective on January 11, 2016.

The WUTC-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 WUTC also approved an ROR of 7.29 percent, with a common equity ratio of 48.5 percent and a 9.5 percent ROE.PC Petition for Judicial Review

In March 2016, ~~the Public Counsel Unit of the Washington State Office of the Attorney General~~PC filed in Thurston County Superior Court a Petition for Judicial Review of the WUTC's ~~orders (described above) that concluded our 2015 electric and natural gas general rate cases.~~Orders. In April 2016, this matter was certified for review directly by the Court of Appeals, an intermediate appellate court in the State of Washington.

On August 7, 2018, the Court of Appeals issued ~~an Opinion~~a "Published Opinion" (Opinion) which concluded that the WUTC's use of an attrition allowance to calculate Avista Corp.'s rate base violated Washington law. In the Opinion, the Court stated that because the projected additions to rate base in the future were not "used and useful" for service at the time the request for the rate increase was made, they may not lawfully be included in our rate base to justify a rate increase. Accordingly, the Court concluded that the WUTC erred in including an attrition allowance in the calculation of our electric and natural gas rate base. The Court noted, however, that the law does not prohibit an attrition allowance in the calculation, for ratemaking purposes, of recoverable operating and maintenance expense. Since the WUTC order provided one lump sum attrition allowance without distinguishing what portion was for rate base and which was for operating and maintenance expenses or other considerations, the Court struck all portions of the attrition allowance attributable to ~~Avista Corp.’s~~our rate base and reversed and remanded the case for the WUTC to recalculate ~~Avista Corp.’s~~our rates without including an attrition allowance in the calculation of rate base.

On ~~April 17, 2019, the Thurston County Superior Court issued a Remand Order, granting a Joint Motion of Avista Corp., PC and~~March 6, 2020, we received an order from the WUTC that will require us to ~~remand the case back to the WUTC. A pre-hearing conference which will set forth the procedural schedule will be held on May 17, 2019.~~

~~The total attrition allowance approved by the WUTC was $35.2~~refund $8.5 million ~~with $28.3 million related~~ to electric and ~~$6.9~~natural gas customers. We will refund $4.9 million ~~related~~to electric customers and $3.6 million to natural ~~gas.~~gas customers. We previously recorded a customer refund liability of $3.6 million in 2019. The ~~Company cannot predict the outcome of this matter at this time~~refund will be returned to customers over one year and cannot estimate how much, if any, of the attrition allowance may be removed from the general rate cases. See "Note 15 of the Notes to Condensed Consolidated Financial Statements" for further discussion of this matter.began on April 1, 2020.

~~2017~~2019 General Rate Cases

On ~~April 26, 2018,~~March 25, 2020, we received an order from the WUTC ~~issued a final order in our electric and natural gas general rate cases~~ that ~~were originally~~approved the partial multi-party settlement agreement that was filed on ~~May 26, 2017. In the order, the WUTC~~November 21, 2019. The approved ~~new electric~~ rates ~~effective on May 1, 2018, that increased base rates by 2.2 percent (designed~~are designed to increase annual base electric revenues by ~~$10.8 million). The net increase in electric base rates was made up of an increase in our base revenue requirement of $23.2~~$28.5 million, ~~an increase of $14.5 million in power supply costs and a decrease of $26.9 million for the impacts of the TCJA, which reflects the federal income tax rate change from 35 percent to 21~~or 5.7 percent, and ~~the amortization of the regulatory liability for plant excess deferred income taxes that was recorded as of December 31, 2017.~~

While the WUTC authorized an increase in the ERM baseline to reflect increased power supply costs, it directed the parties to examine the functionality and rationale of the Company's power cost modeling and adjust the baseline only in extraordinary circumstances if necessary to more closely match the baseline to actual conditions.

~~For natural gas, the WUTC approved new~~annual natural gas base ~~rates, effective on May 1, 2018, that decreased base rates by 2.4 percent (designed to decrease natural gas~~ revenues by ~~$2.1 million).~~$8.0 million, or 8.5 percent, effective April 1, 2020. The ~~net decrease in natural gas~~revenue increases are based on a 9.4 percent return on equity with a common equity ratio of 48.5 percent and a rate of return on rate base ~~rates~~of 7.21 percent.

As part of the WUTC order, we will return approximately $40 million from the ERM rebate to customers over a two-year period. The ERM rebate includes approximately $3 million that was ~~made up~~recently disallowed by the WUTC for the cost of

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replacement power during an ~~increase~~unplanned outage at the Colstrip generating facility in ~~base revenues of $3.4 million that was offset by~~2018. The WUTC directed us to return a ~~decrease of $5.5 million for the impacts from the TCJA, which reflects the federal income tax rate change and the amortization~~larger portion of the ~~regulatory liability for plant-related excess deferred income taxes that was recorded as of December 31, 2017.~~ERM money during the first year to achieve a net-zero billed impact to electric customers.

~~In addition to the above,~~Included in the WUTC ~~also ordered, effective June 1, 2018, a one-year temporary reduction~~order is the acceleration of $7.9 million in our revenue requirements for electric and $3.2 million for natural gas, reflecting reductions for the return of tax benefits associated with the non-plant excess deferred income taxes and the customer refund liability that was established in 2018 related to the change in federal income tax expense for the period January 1, 2018 to April 30, 2018.

~~The new rates are based on a ROR of 7.50 percent with a common equity ratio of 48.5 percent and a 9.5 percent ROE.~~

~~In our original filings, we requested three-year rate plans for electric and natural gas; however, in the final order the WUTC only provided for new rates effective on May 1, 2018.~~

~~TCJA Proceedings~~

In February 2019, we filed an all-party settlement agreement with the WUTC related to the electric tax benefits associated with the TCJA that were set aside for Colstrip in the 2017 general rate case order (effective May 1, 2018). In the settlement agreement, the parties agreed to utilize $10.9 million of the electric tax benefits to offset costs associated with accelerating the depreciation of Colstrip Units 3 & 4 to reflect a remaining useful life ~~of those units~~ through December 31, ~~2027. That~~2025. The order utilizes certain electric tax benefits associated with the 2018 tax reform to partially offset these increased costs. The order also sets aside $3 million for community transition efforts to mitigate the impacts of the eventual closure of Colstrip, half funded by customers and half funded by our shareholders. We recorded this liability and recognized the shareholder portion of the ~~settlement agreement was denied. The WUTC has indicated that it will review~~expense in the ~~TCJA~~first quarter of 2020.

Lastly, the order includes the extension of electric and ~~Colstrip in our next general rate case (which was filed on April 30, 2019). The settlement agreement is subject to WUTC approval.~~natural gas decoupling mechanisms through March 31, 2025.

~~2019~~2020 General Rate Cases

~~On April 30, 2019, we filed~~We expect to file electric and natural gas general rate cases with the WUTC in the fourth quarter of 2020.

Idaho General Rate Cases

2019 General Rate Cases

On October 11, 2019, Avista Corp. and all parties to our electric general rate case reached a settlement agreement that ~~are two-year rate plans. We have requested~~was approved by the ~~following electric and natural gas base rate changes each year, which~~IPUC. New rates went into effect on December 1, 2019.

The rates that went into effect are designed to ~~result in the following increases in~~decrease annual base electric revenues ~~(dollars in millions):~~

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

Base
Rate Increase
April 1, 2020 $ 45.8
9.1 % $ 12.9
13.8 %
April 1, 2021 $ 18.9
3.5 % $ 6.5
6.1 %

~~Our requests~~by $7.2 million (or 2.8 percent), effective December 1, 2019. The settlement revenue decreases are based on a ~~proposed ROR of 7.52~~9.5 percent ROE with a common equity ratio of 50 percent and a ~~9.9~~rate of return ROR on rate base of 7.35 percent, ~~ROE. The WUTC has up to 11 months to review~~which is a continuation of current levels. This outcome is in line with our ~~request and issue a decision.~~

~~Under these rate plans, we would not file new general rate cases for new rates to be effective prior to April 1, 2022.~~expectations.

The ~~purpose~~primary element of ~~our general rate case requests is to recover costs associated with~~ the ~~need to replace infrastructure that has reached the end of its useful life and make technology investments required to build the integrated energy services grid.~~

~~Among the projects included~~difference in the ~~filing are:~~

~~The upgrade~~agreed upon base revenues in the settlement agreement from our original request is that the settlement includes the continued recovery of ~~generating units and other equipment at~~costs for our ~~Little Falls Dam,~~wind generation power purchase agreements, which will ~~provide more generating capacity.~~include Palouse Wind and Rattlesnake Flat, through the PCA mechanism rather than through base rates.

Our distribution grid modernization program that rebuilds and upgrades electric feeders in the system, replacing old equipment like poles, conductor, and transformers to improve service reliability, capture energy efficiency savings and improve operational ability.

~~Ongoing management and replacement of electric distribution wood poles through our wood pole management program.~~

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.

~~The rebuild of a high voltage transmission line, including the installation of steel poles and crossarms.~~

~~Technology upgrades that support necessary business processes and operational efficiencies.~~

~~As a part of these general rate cases, we are also seeking to extend our electric and natural gas decoupling mechanisms for an additional five years (through March 31, 2025).~~

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~~Idaho General Rate Cases~~

~~2017 General Rate Cases~~

On December 28, 2017, the IPUC approved a settlement agreement between us and other parties to our electric and natural gas general rate cases. New rates were effective on January 1, 2018 and January 1, 2019.

The settlement agreement is a two-year rate plan and has the following electric and natural gas base rate changes each year, which are designed to result in the following increases in annual 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
1.8 % $ 1.1
2.7 %

~~The settlement agreement is based on a ROR of 7.61 percent with a common equity ratio of 50 percent and a 9.5 percent ROE.~~

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

~~TCJA Proceedings~~

On May 31, 2018, the IPUC approved an all-party settlement agreement related to the income tax benefits associated with the TCJA. Effective June 1, 2018, through separate tariff schedules, until such time as these changes can be reflected in base rates within the next general rate case, current customer rates were reduced to reflect the reduction of the federal income tax rate to 21 percent, and the amortization of the regulatory liability for plant-related excess deferred income taxes. This reduction reduces annual electric rates by $13.7 million (or 5.3 percent reduction to base rates) and natural gas rates by $2.6 million (or 6.1 percent reduction to base rates).

In March 2019, the IPUC approved an all-party settlement agreement related to the electric tax benefits that were set aside for Colstrip in the 2017 general rate case order. In the approved settlement agreement, the parties agreed to utilize approximately $6.4 million of the electric tax benefits to offset costs associated with accelerating the depreciation of Colstrip Units 3 & 4, to reflect a remaining useful life of those units through December 31, 2027. The remaining tax benefits of approximately $5.8 million will be returned to customers through a temporary rate reduction over a period of one year beginning on April 1, 2019. The tax benefits being utilized are related to non-plant excess deferred income taxes, and the customer refund liability that was established in 2018 related to the change in federal income tax expense for the period January 1, 2018 to May 31, 2018.

~~2019~~2020 General Rate Cases

We expect to file electric and natural gas general rate cases with the IPUC in the ~~second~~fourth quarter of ~~2019.~~2020.

Oregon General Rate Cases

2019 General Rate Case

On October 9, 2019, the OPUC approved the all-party settlement agreements filed in the third quarter of 2019. New rates went into effect on January 15, 2020.

OPUC approved rates that are designed to increase annual natural gas billed revenues by $3.6 million, or 4.2 percent.

The OPUC’s decision reflects a ROR on rate base of 7.24 percent, with a common equity ratio of 50 percent and a 9.4 percent ROE, both of which represent a continuation of existing authorized levels.

In addition, the approved settlement agreements included agreement among the parties to a future independent review of our interest rate hedging practices, with any recommendations based on the results and findings in the final report to be applicable only on a prospective basis and do not apply to any prior interest rate hedging activity.

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2020 General Rate Case

On March ~~15, 2019~~16, 2020, we filed a natural gas general rate case with the OPUC. We have requested an overall increase in base natural gas rates of ~~7.8~~9.8 percent (designed to increase annual natural gas revenues by ~~$6.7~~$6.8 million). Our request is based on a proposed ROR of ~~7.55~~7.50 percent with a common equity ratio of 50 percent and a 9.9 percent ROE. ~~The OPUC has up to 10 months to review our request and issue a decision.~~

~~TCJA Proceedings~~

In February 2019, the OPUC approved the deferral amount of $3.8 million related to 2018 income tax benefits associated with the TCJA. The 2018 deferred benefits will be returned to customers through a temporary rate reduction over a period of one year beginning March 1, 2019. We will continue the deferral of the TCJA benefits during 2019 for later return to customers, until such time as these changes can be reflected in base rates.

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Petition for Judicial Review of the Deferral of Capital Projects

In February 2019 and October 2018, the OPUC issued orders which concluded that, contrary to the OPUC's past practice, Oregon statutes that authorize the deferral of expense for later recovery from customers do not authorize the OPUC to allow deferrals of any costs related to capital investments (utility plant). In April 2019, Avista Corp. and other petitioners filed a Petition for Judicial Review with the Oregon Court of Appeals seeking review of the above OPUC orders. The ~~Company cannot predict~~OPUC, on April 6, 2020, rescinded its prior orders that were the ~~outcome of this matter at this time, including whether or not any decision~~subject of the ~~court would~~appeal, and issued a proposed order meant to replace the orders on appeal. The affected utilities, including Avista Corp., have ~~retroactive effect.~~advised the OPUC that they do not take exceptions to the proposed order, which reinstates the OPUC’s general authority to approve full revenue requirement deferrals, including a return of and on investment. If the proposed order becomes final, and no party seeks review of the revised order, the Court of Appeals will dismiss the appeal.

AMI Project

In March 2016, the WUTC 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. As of March 31, ~~2019,~~2020, the estimated future undepreciated value for the existing electric meters ~~is $20.7~~was $22.6 million. In September 2017, the WUTC also approved our request to defer the undepreciated net book value of existing natural gas encoder receiver transmitters (ERT) (consistent with the accounting treatment we obtained on our existing electric meters) that will be retired as part of the AMI project. As of March 31, ~~2019,~~2020, the estimated future undepreciated value for the existing natural gas ERTs ~~is $3.8~~was $3.3 million. Replacement of the electric meters and natural gas ERTs began during the second half of 2018 and is ongoing.

In September 2017, the WUTC approved a Petition to defer the depreciation expense associated with the AMI project, 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, and 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. Both the IPUC and the OPUC approved our request. In addition, in connection with the 2017 Idaho electric general rate case, ~~(discussed above),~~ 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 above),~~ the OPUC approved cost recovery of Oregon's share of the MDM system, effective November 1, 2017.

Avista Utilities

Purchased Gas Adjustments

PGAs are designed to pass through changes in natural gas costs to Avista Utilities' customers with no change in utility margin (operating revenues less resource costs) or net income. In Oregon, we absorb (cost or benefit) 10 percent of the difference between actual and projected natural gas costs included in retail rates for supply that is not hedged. Total net deferred natural gas costs among all jurisdictions were a liability of ~~$1.3~~$5.4 million as of March 31, ~~2019~~2020 and a net liability of ~~$40.7~~$3.2 million as of December 31, ~~2018. These deferred natural gas costs balances represent amounts due to customers.~~2019.

Power Cost Deferrals and Recovery Mechanisms

The ERM is an accounting method used to track certain differences between Avista Utilities' actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for our Washington customers. Under the ERM, Avista Utilities makes an annual filing on or before April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. See the ~~2018~~2019 Form 10-K for a full discussion of the mechanics of the ERM and the various sharing bands. Total net deferred power costs under the ERM were a liability of ~~$34.8~~$44.1 million as of March 31, ~~2019,~~2020, compared to a liability of ~~$34.4~~$37.0 million as of December 31, ~~2018.~~2019. These deferred power cost balances represent amounts due to customers. Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million in the rebate or surcharge direction, we must make a filing with the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers.

~~Under the ERM, Avista Utilities makes an annual filing on or before April 1~~

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The cumulative rebate balance exceeds $30 million and as a result, our 2019 filing contained a proposed rate ~~refund, effective July 1, 2019 over a three-year period. We anticipate filing a motion during the second quarter of 2019 to consolidate this~~refund. The ERM ~~filing~~proceeding was considered with our ~~2019 Washington general rate case (which was filed on April 30, 2019). In our motion, we will request that the WUTC withhold the refund associated with the ERM for use in the~~ 2019 general rate case ~~rather than passing it back~~proceeding and a refund was approved and will be returned to customers over ~~the three-year period that was proposed~~a two-year period. See further discussion in the ~~ERM filing.~~section "Washington General Rate Cases" above.

Avista Utilities has a PCA mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the

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PCA mechanism were ~~a liability~~assets of ~~$3.0~~$0.1 million as of March 31, ~~2019, compared to a liability of $7.6~~2020 and $0.3 million as of December 31, ~~2018.~~2019. These deferred power cost balances represent amounts due tofrom customers.

Decoupling and Earnings Sharing Mechanisms

Decoupling (also known as a FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of our jurisdictions, Avista Utilities' electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed "normal" kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and "normal" sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only residential and certain commercial customer classes are included in our decoupling mechanisms. See the ~~2018~~2019 Form 10-K for a discussion of the mechanisms in each jurisdiction.

Total net cumulative decoupling deferrals among all jurisdictions were regulatory assets of ~~$9.5~~$20.1 million as of March 31, ~~2019~~2020 and ~~$13.9~~$24.3 million as of December 31, ~~2018.~~2019. These decoupling assets represent amounts due from customers. Total net earnings sharing balances among all jurisdictions were regulatory liabilities of ~~$0.9~~$0.7 million as of March 31, ~~2019~~2020 and ~~$1.5 million as of~~ December 31, ~~2018.~~2019. These earnings sharing liabilities represent amounts due to customers.

See "Results of Operations - Avista Utilities" for further discussion of the amounts recorded to operating revenues in ~~2019~~2020 and ~~2018~~2019 related to the decoupling and earnings sharing mechanisms.

COVID-19

In March 2020, we filed an application for authorization to defer certain incremental COVID-19 related costs with the OPUC. In April and May 2020, we made similar filings with the IPUC and the WUTC, respectively. In Alaska, a Senate Bill was signed into law that provides for deferral and recovery of incremental COVID-19 related costs subject to approval by the RCA. The recovery of any deferred costs would be determined in future rate making proceedings.

Results of Operations - Overall

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

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

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Three months ended March 31, ~~2019~~2020 compared to the three months ended March 31, ~~2018~~2019

The following graph shows the total change in net income attributable to Avista Corp. shareholders for the first quarter of ~~2018~~2019 to the first quarter of ~~2019,~~2020, as well as the various factors that caused such change (dollars in millions):

Utility revenues ~~decreased~~remained consistent at ~~both~~ Avista Utilities when compared to the first quarter of 2019. The outcome from the 2015 Washington general rate cases decreased revenue by $4.9 million. In addition, residential and ~~AEL&P. Avista Utilities' revenues decreased primarily due to a decrease in wholesale electric revenues (primarily from a decrease in volumes). This~~commercial load was ~~partially~~lower than the first quarter of 2019. The above decreases were offset by an increase ~~in revenue~~ from ~~wholesale~~electric and natural gas ~~revenues (primarily from an increase in sales prices), general rate increases~~decoupling rates, higher PGA rates and customer growth. AEL&P's revenues ~~decreased due to a decrease in retail rates associated with the federal income tax law change, as well as a decrease~~increased from an increase in sales volumes due to weather that was ~~warmer~~cooler than the prior year.

Non-utility revenues decreased due to the sale of METALfx, which occurred in April 2019.

Utility resource costs decreased at ~~both~~ Avista Utilities and AEL&P. While resource costs in isolation decreased at Avista Utilities, when considered with our wholesale electric sales, our net power supply costs (resource costs less wholesale revenues) increased as compared to 2018. This was due to lower ~~hydroelectric~~fuel for generation and other fuel costs, as well as ~~higher purchased power prices and~~lower natural gas ~~fuel prices.~~purchases. The ~~decrease~~increase at AEL&P was due to ~~a decrease~~an increase in deferred power supply ~~expenses, as well as the~~

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adoption of the new lease standard on January 1, 2019, which resulted in the reclassification of Snettisham power purchase costs from resource costs to depreciation and amortization and interest expense in 2019. See "Notes 2 and 5 of the Notes to Condensed Consolidated Financial Statements" for further information regarding the adoption of the new lease standard.expenses.

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~~primarily related to increases in generation and distribution operating and maintenance costs, an accrual for disallowed replacement power during an unplanned outage at Colstrip (see "Regulatory Matters"), and ~~employee incentive and benefit costs.~~an increase in bad debt expense.

The merger transaction costs are related to the ~~now terminated~~proposed (now terminated) acquisition by Hydro ~~One acquisition. These~~One. There were no additional costs increased for the first quarter of 2019 because 2019 includes financial advisers' fees, legal fees, consulting fees and employee time, whereas the first quarter of 2018 consisted primarily of employee time incurred directly relatedin 2020 relating to ~~the transaction. None of the acquisition costs are being passed through to customers.~~this matter.

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

The merger termination fee was ~~received from~~related to the termination of the proposed Hydro One acquisition.

The increase in other was primarily related to a decrease in non-utility other operating expenses due to the ~~mutual agreement~~sale of METALfx during the second quarter of 2019 and also due to ~~terminate~~lower property taxes. In addition, there was a gain from the ~~proposed acquisition. See "Note 17~~sale of an equity investment in the ~~Notes to Condensed Consolidated Financial Statements" for additional discussion.~~first quarter of 2020.

Income taxes ~~increased~~decreased primarily due to a decrease in income ~~taxes associated with the merger termination fee.~~before taxes. Our effective tax rate was 15.0 percent for the first quarter of 2020 compared to 20.6 percent for the first quarter of ~~2019 compared to 16.3 percent for the first quarter of 2018. We expect our full year 2019 effective tax rate to be approximately 16 percent to 17 percent.~~2019. See "Note 87 of the Notes to Condensed Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.

The increase in other was primarily because 2018 included an impairment of an investment and additional charges associated with a renovation, whereas the first quarter of 2019 included earnings from our investments.

Non-GAAP Financial Measures

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

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Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. Electric utility margin is electric operating revenues less electric resource costs, while natural gas utility margin is natural gas operating revenues less natural gas resource costs. The most directly comparable GAAP financial measure to electric and natural gas utility margin is utility operating revenues as presented in "Note 16 of the Notes to Condensed Consolidated Financial Statements."

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

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Results of Operations - Avista Utilities

Three months ended March 31, ~~2019~~2020 compared to the three months ended March 31, ~~2018~~2019

Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three months ended March 31 (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 deferrals/amortizations to customers related to federal income tax law changes.

Total electric operating revenues in the graph above include intracompany sales of $6.1 million and $19.7 million for the three months ended March 31, 2020 and March 31, 2019, respectively.

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


	Electric Operating Revenues						Electric Decoupling Revenues
	2019			2018			2020			2019
Current year decoupling deferrals (a)	$	(2,681	)	$	4,012		$	5,131		$	(2,681	)
Amortization of prior year decoupling deferrals (b)	1,076			(4,880		)	(4,608		)	1,076
Total electric decoupling revenue	$	(1,605	)	$	(868	)	$	523		$	(1,605	)


(a)	Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative ~~numbers~~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 ~~numbers~~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 decreased ~~$6.0~~$10.3 million for the first quarter of ~~2019~~2020 as compared to the first quarter of ~~2018~~2019 primarily due to the following:

a ~~$1.1 million~~ ~~increase in retail electric revenue due to an increase in total MWhs sold (increased revenues $8.1 million), partially offset by a decrease in revenue per MWh (decreased revenues $7.0 million).~~

◦•

~~The~~

an $8.5 million decrease in retail electric revenue due to a decrease in total MWhs sold (decreased revenues $10.6 million), partially offset by an increase in total retail MWhs sold was the result of weather that was cooler than the prior year (which increased electric heating loads) and customer growth. Compared to the first quarter of 2018, residential electric userevenue per ~~customer increased 5 percent and commercial use per customer increased 1 percent. Heating degree days in Spokane were 14 percent above normal and 17 percent above the first quarter of 2018.~~MWh (increased revenues $2.1 million).

◦

The decrease in total retail MWhs sold was primarily the result of a decrease in residential, commercial and industrial sales volumes due to weather that was warmer than normal and warmer than the prior year. These were partially offset by residential and commercial customer growth. Compared to the first quarter of 2019, residential electric use per customer decreased 9 percent and commercial use per customer decreased 2 percent. Heating degree days in Spokane were 7 percent below normal and 17 percent below the first quarter of 2019.

◦

The increase in revenue per MWh was primarily due to ~~a decrease~~an increase in decoupling rates (as ~~our~~there was a decoupling ~~surcharges were larger~~surcharge in ~~prior years, which resulted in higher surcharge rates in 2018 as~~2020 compared to a decoupling rebate in 2019) ~~and decreases associated with the lower corporate tax rate.~~. This was partially offset by a general rate ~~increases~~decrease in ~~Washington (effective May~~Idaho, effective December 1, ~~2018)~~2019.


•	a $6.4 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $5.5 million) and ~~Idaho (effective January 1, 2019)~~an increase in sales volumes (increased revenues $0.9 million). The fluctuation in volumes and prices was

a ~~$19.2 million~~ decrease in wholesale electric revenues due to a decrease in sales volumes (decreased revenues $15.1 million) and a decrease in sales prices (decreased revenues $4.1 million). The fluctuation in volumes and prices was primarily the result of our optimization activities.

a ~~$1.2 million~~ ~~decrease in sales of fuel due to a decrease in sales of natural gas fuel as part of thermal generation resource optimization activities.~~

a ~~$0.7 million~~ decrease in electric decoupling revenue. Weather was cooler than normal in the first quarter of 2019, which resulted in decoupling deferral rebates related to the current year. This was partially offset by the amortization of decoupling rebates from prior years.

~~the~~ ~~$14.1 million~~ increase in other electric revenues was primarily related to federal income tax law changes that lowered the corporate tax rate from 35 percent to 21 percent. As our customers' rates had the 35 percent corporate tax rate built in from prior general rate cases, we deferred the impact of the change in the first quarter of 2018. Effective May 1, 2018 in Washington and June 1, 2018 in Idaho, base rates reflect the lower 21 percent corporate tax.

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primarily the result of our optimization activities.


•	a $7.7 million decrease in sales of fuel due to a decrease in sales of natural gas fuel as part of thermal generation resource optimization activities.


•	a $2.1 million increase in electric decoupling revenue. Weather was warmer than normal in the first quarter of 2020, reducing the demand for electric heating, resulting in decoupling deferral surcharges related to the current year. There was also the amortization of decoupling surcharges from prior years.


•	the $2.8 million decrease in other electric revenues was primarily related to a $1.4 million accrual for customer refunds related to our 2015 Washington general rate case that was remanded back to the WUTC during 2019. See "Regulatory Matters" for further discussion. In addition, there was a $1.1 million decrease in tax reform amortization associated with the 2018 federal tax rate change.

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three months ended March 31 (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 deferrals/amortizations to customers related to federal income tax law changes.

Total natural gas operating revenues in the graph above include intracompany sales of $12.8 million and $23.7 million for the three months ended March 31, 2020 and March 31, 2019, respectively.

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

Natural Gas Operating
Revenues
2019 2018
Current year decoupling deferrals (a) $ (6,106 ) $ 149
Amortization of prior year decoupling deferrals (b) 3,053
(5,220 )
Total natural gas decoupling revenue $ (3,053 ) $ (5,071 )

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	Natural Gas Decoupling Revenues
	2020			2019
Current year decoupling deferrals (a)	$	(3,556	)	$	(6,106	)
Amortization of prior year decoupling deferrals (b)	(1,380		)	3,053
Total natural gas decoupling revenue	$	(4,936	)	$	(3,053	)


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

(b)

Total natural gas revenues ~~increased $21.2~~decreased $14.7 million for the first quarter of ~~2019~~2020 as compared to the first quarter of ~~2018~~2019 primarily due to the following:

a ~~$4.2~~$10.2 million ~~decrease~~increase in natural gas retail revenues due to ~~lower~~an increase in retail rates ~~(decreased~~(increased revenues ~~$20.0~~$22.1 million), partially offset by ~~an increase~~a decrease in volumes ~~(increased~~(decreased revenues ~~$15.8~~$11.9 million).


◦	Retail rates increased from higher PGAs, decoupling rate increases and a general rate increase in Oregon, effective January 15, 2020.

◦

~~We sold more retail~~Retail natural gas sales decreased in the first quarter of ~~2019~~2020 as compared to the first quarter of ~~2018~~2019 primarily due to ~~colder weather~~lower residential, commercial and industrial usage, partially ~~due to~~offset by customer growth. Compared to first quarter of ~~2018,~~2019, residential use per customer ~~increased 13~~decreased 12 percent and commercial use per customer ~~increased 16~~decreased 10 percent. Heating degree days in Spokane were 147 percent ~~above~~below normal, and 17 percent ~~above~~below the first quarter of ~~2018.~~2019. Heating degree days in Medford were 104 percent above normal, and 73 percent ~~above~~below the first quarter of ~~2018.~~2019.

◦•

~~Lower retail rates were~~

a $20.0 million decrease in wholesale natural gas revenues due to ~~PGAs and rate decreases associated with the lower corporate tax rate and decoupling rate decreases (as our decoupling surcharges were larger~~a decrease in ~~prior years, which resulted in higher surcharge rates in 2018 as compared to 2019)~~prices (decreased revenues $22.7 million), partially offset by ~~general rate increases~~an increase in ~~Washington (effective May 1, 2018) and Idaho (effective January 1, 2019)~~volumes (increased revenues $2.7 million). Differences between revenues

a ~~$16.1 million~~ ~~increase in wholesale natural gas revenues due to an increase in prices (increased revenues $13.1 million) and an increase in volumes (increased revenues $3.0 million). Differences between revenues~~

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and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.

~~a $2.0~~the $2.5 million increase in natural gas decoupling revenue. Weather was cooler than normal in the first quarter of 2019, which resulted in decoupling deferral rebates related to the current year. This was partially offset by the amortization of decoupling rebates from prior years.

~~the~~ ~~$7.4 million~~ ~~increase~~decrease in other natural gas revenues was primarily related to a $3.6 million accrual for customer refunds related to our 2015 Washington general rate case that was remanded back to the WUTC during 2019. See "Regulatory Matters" for further discussion. This was partially offset by a decrease of $1.4 million in the provision for tax rate refunds associated with the federal income tax law changes that lowered the corporate tax rate from 35 percent to 21 percent. As our customers' rates had the 35 percent corporate tax rate built in from prior general rate cases, we deferred the impact of the change in ~~the first quarter of~~ 2018. ~~Effective May 1, 2018 in Washington, June 1, 2018 in Idaho and March 1, 2019 in Oregon, base rates reflect the lower 21 percent corporate tax.~~

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

Electric
Customers

Natural Gas
Customers
2019 2018 2019 2018
Residential 343,938
339,218
319,483
313,247
Commercial 42,874
42,624
35,707
35,506
Interruptible —
—
42
38
Industrial 1,314
1,321
239
248
Public street and highway lighting 601
588
—
—
Total retail customers 388,727
383,751
355,471
349,039

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	Electric Customers		Natural Gas Customers
	2020	2019	2020	2019
Residential	349,368	343,938	326,126	319,483
Commercial	43,300	42,874	36,194	35,707
Interruptible	—	—	43	42
Industrial	1,295	1,314	241	239
Public street and highway lighting	638	601	—	—
Total retail customers	394,601	388,727	362,604	355,471

Utility Resource Costs

The following graphs present Avista Utilities' resource costs for the three months ended March 31 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of ~~$23.7~~$12.8 million and ~~$10.3~~$23.7 million for the three months ended March 31, ~~2019~~2020 and March 31, ~~2018, respectively.~~

~~Total natural gas resource costs in the graph above include intracompany resource costs of $19.7 million and $6.9 million for the three months ended March 31,~~ 2019, ~~and March 31, 2018,~~ respectively.

Total electric resource costs decreased ~~$5.0~~$18.3 million for the first quarter of ~~2019~~2020 as compared to the first quarter of ~~2018~~2019 primarily due to the following:

a ~~$6.1~~$4.2 million decrease in ~~purchased~~ power ~~costs~~purchased due to a decrease in the volume of power purchases (decreased costs ~~$10.5~~$5.7 million), partially offset by an increase in wholesale prices (increased costs ~~$4.4~~$1.5 million). The fluctuation in volumes and prices was primarily the result of our optimization activities during the quarter.

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•
~~AVISTA CORPORATION~~ an $8.8 million decrease in fuel for generation primarily related to a decrease in natural gas prices, a decrease in customer volumes sold and an increase in hydroelectric generation as compared to the first quarter of 2019.

a ~~$7.9 million~~ ~~increase in fuel for generation primarily due to an increase in thermal generation, as well as an increase in natural gas fuel prices.~~

a ~~$0.8~~$6.3 million ~~increase~~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.

~~an $11.0 million decrease from net amortizations and deferrals of power costs.~~

~~a $3.4 million net increase from other regulatory amortizations and other electric resource costs.~~

Total natural gas resource costs ~~increased~~ in the graph above include intracompany resource costs of $6.1 million and $19.7 million for the three months ended March 31, 2020 and March 31, 2019, respectively.

Total natural gas resource costs decreased $~~18.3~~15.3 million for the first quarter of ~~2019~~2020 as compared to the first quarter of ~~2018~~2019 primarily due to the following:

a ~~$52.2~~$59.4 million ~~increase~~decrease in natural gas purchased due to ~~an increase~~a decrease in the price of natural gas ~~(increased~~(decreased costs ~~$39.3 million) and an increase in total therms purchased (increased costs $12.9~~$59.4 million).

a ~~$35.7~~$44.6 million ~~decrease~~increase from net amortizations and deferrals of natural gas costs, primarily ~~reflecting higher~~due to a spike in natural gas ~~prices.~~

prices during the first quarter of 2019 from a ~~$1.8 million increase from other regulatory amortizations.~~natural gas supply disruption in Canada, which resulted in significant amount of PGA deferrals during that period.

Utility Margin

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


	Electric				Natural Gas				Intracompany						Total				Electric				Natural Gas				Intracompany						Total
	2019		2018		2019		2018		2019			2018			2019		2018		2020		2019		2020		2019		2020			2019			2020		2019
Operating revenues	$	256,467	$	262,477	$	164,677	$	143,448	$	(43,442	)	$	(17,171	)	$	377,702	$	388,754	$	246,208	$	256,467	$	149,950	$	164,677	$	(18,953	)	$	(43,442	)	$	377,205	$	377,702
Resource costs	93,881		98,890		88,273		69,946		(43,442		)	(17,171		)	138,712		151,665		75,531		93,881		72,979		88,273		(18,953		)	(43,442		)	129,557		138,712
Utility margin	$	162,586	$	163,587	$	76,404	$	73,502	$	—		$	—		$	238,990	$	237,089	$	170,677	$	162,586	$	76,971	$	76,404	$	—		$	—		$	247,648	$	238,990

Electric utility margin ~~decreased $1.0~~increased $8.1 million and natural gas utility margin increased ~~$2.9~~$0.6 million.

Electric utility margin ~~decreased~~increased primarily due to ~~an increase in net power supply costs. The increase~~a decrease in net power supply costs ~~was~~ due to ~~lower hydroelectric generation, as well as higher purchased~~ power purchase prices and ~~natural gas~~thermal fuel ~~prices.~~costs that were lower than those recovered through our rates (authorized costs). For the first quarter of ~~2019,~~2020, we had a ~~$2.5~~$5.2 million pre-tax ~~expense~~benefit under the ERM in Washington, compared to a ~~$4.9~~$2.5 million pre-tax ~~benefit~~expense for the first quarter of ~~2018.~~2019. For the full year of ~~2019,~~2020, we expect to be in a benefit position under the ERM within the 7590 percent customer/2510 percent Company sharing band.

~~Partially offsetting the impact of higher net power supply costs,~~ In addition, electric utility margin was positively impacted by customer growth. The above increases were partially offset by an accrual for customer refunds of $1.4 million related to our 2015 Washington general rate ~~increases in Washington (effective May 1, 2018) and Idaho (effective January 1, 2019), and customer growth.~~case that was remanded back to the WUTC during 2019. See "Regulatory Matters" for further discussion.

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Natural gas utility margin increased primarily due to a general rate ~~increases~~increase in ~~Washington (effective May 1, 2018) and Idaho (effective~~Oregon, effective January ~~1, 2019),~~15, 2020 and customer growth. These increases were mostly offset by an accrual for customer refunds of $3.6 million related to our 2015 Washington general rate case that was remanded back to the WUTC during 2019. See "Regulatory Matters" for further discussion.

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

Results of Operations - Alaska Electric Light and Power Company

Three months ended March 31, ~~2019~~2020 compared to the three months ended March 31, ~~2018~~2019

Net income for AEL&P was $3.4 million for the three months ended March 31, 2020 compared to $3.6 million for the three months ended March 31, ~~2019 compared to $3.8 million for the three months ended March 31, 2018.~~

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2019.

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


	Three months ended March 31,
	2019			2018		2020			2019
Operating revenues	$	10,881		$	13,663	$	12,202		$	10,881
Resource costs	(1,365		)	2,953		(10		)	(1,365		)
Utility margin	$	12,246		$	10,710	$	12,212		$	12,246

Electric revenues ~~decreased~~increased for the first quarter of ~~2019~~2020 primarily due to ~~lower~~higher sales volumes to residential and commercial customers for ~~2019~~2020 as compared to ~~2018.~~2019. This resulted from weather that was ~~warmer~~cooler than the prior ~~year.~~year, as well as more hydroelectric generation than the first quarter of 2019.

Resource costs decreased from the prior year due to the adoption of the new lease standard on January 1, 2019, which resulted in the reclassification of Snettisham power purchase costs from resource costs to depreciation and amortization and interest expense in 2019. See "Notes 2 and 5 of the Notes to Condensed Consolidated Financial Statements" for further information regarding the adoption of the new lease standard. In addition, AEL&P had low hydroelectric generation during the first quarter of 2019, which ~~prevented AEL&P from providing~~limited energy provided to their interruptible customers. A portion of the sales to interruptible customers is used to reduce the overall cost of power to AEL&P's firm customers. When interruptible sales are below a certain threshold, AEL&P recognizes a regulatory asset and records a reduction to deferred power supply costs (resource costs) to reflect a future billable amount to its firm customers when the cost of power rates are reset.

~~For operating expenses, there was a slight increase in other operating expenses for~~ During the first quarter of ~~2019 primarily due~~2020, hydroelectric generation returned to ~~an increase~~normal levels, which resulted in ~~distribution maintenance costs.~~less resource costs compared to the first quarter of 2019.

Results of Operations - Other Businesses

Net ~~income~~loss for our other businesses was $1.0 million for the three months ended March 31, 2020 compared to net income of $0.3 million for the three months ended March 31, ~~2019 compared to a net loss of $4.4 million for the three months ended March 31, 2018.~~2019.

During the first quarter of ~~2019,~~2020, we had ~~net~~an impairment loss and an accrual for bad debt, which were partially offset by investment gains associated with our equity investments, primarily from a gain on the sale of one of our investments. This is compared to ~~investments losses in~~ the first quarter of ~~2018 primarily~~2019 that resulted in net investment gains.

Due to market deterioration from ~~an impairment of one of~~a possible future recession, further losses could be incurred on our ~~investments. In addition,~~non-utility investments during the ~~first quarter~~remainder of ~~2018 we had expenses associated with a renovation project.~~2020.

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. Our critical accounting policies that require the use of estimates and assumptions were discussed in detail in the ~~2018~~2019 Form 10-K and have not changed ~~materially from that discussion.~~materially.

Liquidity and Capital Resources

Overall Liquidity

~~Our~~

We expect that COVID-19 will have a negative impact on our overall liquidity. For 2020, we expect our net cash flows from operations to decrease primarily due to lower expected revenues from retail sales of electricity and natural gas and lower payments from customers.

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In response to potential liquidity needs, in April 2020, we entered into a $100 million credit agreement, see "Note 9 of the Notes to Condensed Consolidated Financial Statements."

Other than COVID-19 impacts, our sources of overall liquidity and the requirements for liquidity have not materially changed in the three months ended March 31, ~~2019.~~2020. See the ~~2018~~2019 Form 10-K for further discussion.

As of March 31, ~~2019,~~2020, we had ~~$220.9~~$182.0 million of available liquidity under the Avista Corp. committed line of credit and $25.0 million under the AEL&P committed line of credit. ~~With~~After considering the impacts of COVID-19, with our $400.0 million credit facility that expires in April 2021, ~~and~~ AEL&P's $25.0 million credit facility that expires in November ~~2019,~~2024 and the new $100.0 million credit agreement that expires in April 2021, we believe that we have adequate liquidity to meet our needs for the next 12 months. ~~We anticipate pursuing an extension to the AEL&P credit facility or entering into a new agreement during 2019.~~

Review of Cash Flow Statement

Operating Activities

Net cash provided by operating activities was $~~196.9~~135.3 million for the three months endedMarch 31, ~~2019~~2020 compared to $~~184.8~~196.9 million for the three months ended March 31, ~~2018.~~2019. The ~~increase~~decrease in net cash provided by operating activities ~~was~~ primarily ~~due~~relates to a termination fee of $103.0 million received in 2019 upon the ~~receipt~~termination of the ~~$103.0 million merger termination fee from~~ Hydro One ~~that is reflected in net income for 2019.~~transaction. The termination fee was used for reimbursing our transaction costs incurred from 2017 to 2019 which totaled approximately $51.0 million, including income taxes. The balance of the termination fee was used for general corporate purposes and reduced our

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need for external financing. Our total transaction costs were $19.7 million (pre-tax) for 2019 and we also incurred approximately $15.7 million in taxes in ~~2019 (net of $1.8 million in tax benefits recaptured from 2017 and 2018).~~2019.

The above ~~increase~~decrease in net cash provided by operating activities was partially offset by power and natural gas deferrals which ~~increased~~decreased during ~~2019~~2020 due to ~~higher~~lower natural gas prices during the ~~quarter~~year (which ~~decreased~~increased cash flows by ~~$48.1~~$6.4 million) as compared to an ~~increase~~decrease to operating cash flows of ~~$0.1~~$48.1 million in ~~the first quarter of 2018.~~

~~Also, changes in our cash collateral decreased operating cash flows when~~2019. As compared to ~~2018 because during 2018, our cash collateral posted~~2019, net current assets and liabilities decreased by ~~$18.4 million, whereas in 2019 it only decreased by $3.4~~$43.0 million. The collateral decreased in both periods primarily due to fluctuations in the fair value of energy commodity derivatives which required less collateral. In addition, outstanding interest rate swaps in 2018 required less collateral.

~~Finally, changes in accounts receivable decreased operating cash flows by $9.8 million during 2019, but increased operating cash flows by $16.0 million in 2018.~~

Investing Activities

Net cash used in investing activities was $~~97.7~~95.1 million for the three months endedMarch 31, ~~2019~~2020, compared to $~~87.4~~97.7 million for the three months ended March 31, ~~2018~~2019. During the three months ended March 31, ~~2019,~~2020, we paid ~~$93.6~~$95.5 million for utility capital expenditures compared to ~~$81.8~~$93.6 million for the three months ended March 31, ~~2018.~~2019. Also, during the first quarter of ~~2019, our subsidiaries invested $3.5 million~~2020, we received proceeds from the sale of an equity investment (net of cash sold and amounts held in ~~equity and property, compared to $3.7 million invested during the first quarter~~escrow) of ~~2018.~~$5.1 million.

Financing Activities

Net cash used by financing activities was $~~98.0~~31.1 million for the three months endedMarch 31, ~~2019~~2020, compared to $~~87.3~~98.0 million for the three months ended March 31, ~~2018~~2019. Due to ~~the receipt of~~ the termination fee described above, we were able to reduce our short-term borrowings during the first quarter of 2019, as evidenced by the $71.0 million decrease in short-term borrowings during ~~the quarter.~~2019. For 2020, we had a decrease in short-term borrowings of $0.8 million.

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 March 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):


	March 31, 2019				December 31, 2018				March 31, 2020				December 31, 2019
	Amount		Percent of total		Amount		Percent of total		Amount		Percent of total		Amount		Percent of total
Current portion of long-term debt and capital leases	$	104,989	2.7	%	$	107,645	2.8	%
Current portion of long-term debt and leases									$	58,946	1.4	%	$	58,928	1.4	%
Short-term borrowings	119,000		3.1	%	190,000		4.9	%	185,000		4.4	%	185,800		4.5	%
Long-term debt to affiliated trusts	51,547		1.3	%	51,547		1.3	%	51,547		1.2	%	51,547		1.2	%
Long-term debt and capital leases	1,701,207		44.3	%	1,755,529		45.3	%
Long-term debt and leases									1,957,142		46.5	%	1,961,083		46.7	%
Total debt	1,976,743		51.4	%	2,104,721		54.3	%	2,252,635		53.5	%	2,257,358		53.8	%
Total Avista Corporation shareholders’ equity	1,867,310		48.6	%	1,773,220		45.7	%	1,959,095		46.5	%	1,939,284		46.2	%
Total	$	3,844,053	100.0	%	$	3,877,941	100.0	%	$	4,211,730	100.0	%	$	4,196,642	100.0	%

Our shareholders’ equity increased $~~94.1~~19.8 million during the first three months of ~~2019~~2020 primarily due to net income, partially offset by dividends.

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

Committed Lines of Credit

Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 ~~million that expires~~million. We expect to amend and extend the revolving line of credit agreement in the second quarter for a revised term of one additional year beyond the current maturity date of April 2021,. with the option to extend for an additional one year period. As of March 31, ~~2019,~~2020, there was ~~$220.9~~$182.0 million of available liquidity under this line of credit.

The Avista Corp. credit facility contains customary covenants and default provisions, including a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of March 31, ~~2019,~~2020, we were in compliance with this covenant with a ratio of ~~51.4~~53.5 percent.

AEL&P has a $25.0 million committed line of credit that expires in November ~~2019.~~2024. As of March 31, ~~2019,~~2020, there were no borrowings or letters of credit outstanding under this committed line of credit.

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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 March 31, ~~2019,~~2020, AEL&P was in compliance with this covenant with a ratio of ~~52.8~~53.0 percent.

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

2019 2018
Borrowings outstanding at end of period $ 119,000
$ 50,000
Letters of credit outstanding at end of period $ 60,103
$ 35,420
Maximum borrowings outstanding during the period $ 190,000
$ 111,000
Average borrowings outstanding during the period $ 113,404
$ 76,211
Average interest rate on borrowings during the period 3.30 % 2.30 %
Average interest rate on borrowings at end of period 3.31 % 2.56 %

The increase in the average interest rates as of and for the three months ended March 31, 2019 was primarily the result of a downgrade in our credit rating by Moody's during December 2018. See the 2018 10-K for further discussion of the downgrade by Moody's.



	2020			2019
Borrowings outstanding at end of period	$	185,000		$	119,000
Letters of credit outstanding at end of period	$	32,983		$	60,103
Maximum borrowings outstanding during the period	$	193,000		$	111,000
Average borrowings outstanding during the period	$	173,684		$	36,299
Average interest rate on borrowings during the period	2.33		%	2.43		%
Average interest rate on borrowings at end of period	1.66		%	3.31		%

As of March 31, ~~2019,~~2020, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements, and none of Avista Corp.'s subsidiaries constituted a “significant subsidiary” as defined in Avista Corp.'s committed line of credit.

In April 2020, we entered into a $100.0 million credit agreement with a maturity date of April 2021. We borrowed the entire $100.0 million available under this agreement, which is being used to provide additional liquidity. See "Note 9 of the Notes to Condensed Consolidated Financial Statements."

Loans under this agreement are unsecured and will have a variable annual interest rate determined by either the Eurodollar rate or the Alternative Base Rate depending on the type of loan selected by Avista Corp. The credit agreement contains customary covenants and default provisions, including a covenant not to permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time.

Liquidity Expectations

In January 2019, we received a $103 million termination fee from Hydro One in connection with the termination of the proposed acquisition. The termination fee was used for reimbursing our transaction costs incurred from 2017 to 2019. These costs, including income taxes, total approximately $51 million. The balance of the termination fee was used for general corporate purposes and reduced our need for external financing.

During ~~2019,~~2020, we expect to issue approximately $165.0 million of long-term debt and up to ~~$50.0~~$70.0 million of equity in order to refinance maturing long-term debt, and fund planned capital ~~expenditures and maintain an appropriate capital structure.~~expenditures.

After considering the impacts of COVID-19, including the expectation of lower net operating cash flows, and the expected issuances of long-term debt and equity during ~~2019,~~2020, we expect net cash flows from ~~operating activities,~~operations, together with cash available under our committed ~~line~~lines of credit ~~agreements,~~and the $100.0 million borrowed under the credit agreement entered in April, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.

Capital Expenditures

We are making capital investments to enhance service and system reliability for our customers and replace aging infrastructure. Our ~~estimates~~estimated capital expenditures for ~~2019~~2020 through ~~2021~~2022 have not materially changed during the three months ended March 31, ~~2019.~~2020. It is possible that prolonged economic restrictions or business interruptions could cause a decrease in our utility capital expenditures. See the ~~2018~~2019 Form 10-K for further ~~information.~~information on our expected capital expenditures.

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Off-Balance Sheet Arrangements

As of March 31, ~~2019~~2020, we had $~~60.1~~33.0 million in letters of credit outstanding under our $400.0 million committed line of credit, compared to $~~10.5~~21.5 million as of December 31, ~~2018~~2019. The increase in letters of credit outstanding was due to additional letters of credit being issued as collateral for energy commodity derivative instruments.

Pension Plan

Avista Utilities

In the three months endedMarch 31, ~~2019~~2020 we contributed $7.3 million to the pension plan and we expect to contribute ~~a total of~~ $22.0 million in ~~2019.~~2020. We expect to contribute a total of $110.0 million to the pension plan in the period ~~2019~~2020 through ~~2023,~~2024, with annual contributions of $22.0 million over that period.

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.

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pension plan assets and lower discount rates will increase the pension liability. This could ultimately increase future pension plan funding requirements and expenses. The impact on pension plan assets is mitigated as a significant portion of the assets are fixed-income securities with a target of 35 percent invested in equity securities. The impact on pension expense is also mitigated by pension accounting under GAAP, given that expense is based on the long-term rate of return which should be less affected by short-term market fluctuations.

See "Note 76 of the Notes to Condensed Consolidated Financial Statements" for additional information regarding the pension plan.

Contractual Obligations

Our future contractual obligations have not materially changed during the three months ended March 31, ~~2019.~~ 2020, except for in April 2020, we entered into a $100.0 million credit agreement with a maturity date of April 2021. See "Note 9 of the Notes to Condensed Consolidated Financial Statements."

See the ~~2018~~2019 Form 10-K for our contractual obligations.

Environmental Issues and Contingencies

Our environmental issues and contingencies disclosures have not materially changed during the three months ended March 31, ~~2019~~2020 except for the following:

Coal Ash Management/Disposal

In 2015, the EPA issued a final rule regarding coal combustion residuals (CCRs), also termed coal combustion byproducts or coal ash. The CCR rule has been the subject of ongoing litigation. In August 2018, the D.C. Circuit struck down provisions of the rule. Colstrip, ~~Coal Contract~~

~~Colstrip,~~of which is operated by Talen Montana, is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements. The current contract for coal supply extends through 2019; however, the coal mine operator is in bankruptcy and had indicated that it would reject the current contract in its bankruptcy. The co-ownerswe are a 15 percent owner of ~~Colstrip filed objections~~Units 3 & 4, produces this byproduct. On December 2, 2019, a proposed revision to the ~~proposed rejection~~rule was published in the Federal Register to address the D.C. Circuit's decision. The rule includes technical requirements for CCR landfills and surface impoundments under Subtitle D of the ~~coal supply contract~~Resource Conservation and ~~in February 2019,~~Recovery Act, the nation's primary law for regulating solid waste. The Colstrip owners developed a multi-year compliance plan to address the CCR requirements with existing state obligations expressed largely by the 2012 Administrative Order on Consent (AOC) with Montana Department of Environmental Quality (MDEQ). These requirements continue despite the 2018 federal court ruling.

The AOC requires MDEQ provide an ~~amended plan of reorganization was filed in~~ongoing public process which ~~the proposal to reject the coal supply contract was withdrawn. The court~~recently approved the ~~amended plan~~Remedy and Closure plans for the three major areas of ~~reorganization on March 2, 2019, which allows~~Colstrip. The AOC also requires the ~~coal supply contract~~Colstrip owners to ~~remain~~provide financial assurance primarily in ~~effect through 2019. The co-owners~~the form of ~~Colstrip are in negotiations~~surety bonds, to secure each owner’s pro rata share of various anticipated closure and remediation obligations. Avista Corp. is responsible for ~~an extension to~~its share of two major areas; the ~~coal contract beyond 2019~~Plant Site Area and at the ~~same time exploring alternative sources for coal supply. Any new arrangements for coal beyond 2019 may have higher costs than~~Effluent Holding Pond (EHP) Area. Generally, the plans include the removal of Boron, Chloride, and Sulfate from the groundwater, closure of the existing ~~coal supply agreement.~~

~~Clean Energy Commitment~~

~~On April 18, 2019, we announced~~ash storage ponds, and installation of a ~~goal~~new water treatment system to ~~serve our customers with 100 percent clean electricity by 2045 and~~convert the facility to ~~have~~ a carbon-neutral supply of electricity by the end of 2027. To help achieve these goals and add to our clean electricity portfolio, in the last three years, we have implemented three renewable energy projects on behalf of our customers, the Community Solar project in Spokane Valley, Washington (owned bydry ash storage. Avista Corp.~~), the Solar Select project in Lind, Washington (PPA) and the Rattlesnake Flat Wind project in Adams County, Washington (PPA).~~ has posted three surety bonds totaling approximately $23 million. This amount will be updated annually, decreasing over time as remediation activities are completed.

~~Climate Change - State~~

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Oregon Legislation and Regulatory Actions

GHG Reduction Targets

The State ~~Regulatory Activities~~

~~The states~~ of ~~Washington and~~ Oregon ~~have~~has adopted non-binding targets to reduce GHG (Greenhouse Gas) emissions. ~~Both states~~The State enacted ~~their~~its targets with an expectation of reaching the targets through a combination of renewable energy standards, eventual carbon pricing mechanisms, such as cap and trade regulation or a carbon tax, and assorted “complementary ~~policies,~~policies.” ~~but~~However, no specific reductions are ~~mandated.~~mandated as yet. The ~~Governors and Legislatures of both states began drafting climate-related proposals in late 2018, ahead~~State’s targets have been evaluated by state institutions against the aims of the ~~2019 legislative sessions.In Washington~~Paris Climate Accord of 2016, which include limiting the increase in global average temperatures to at least below 2 degrees Celsius above pre-industrial levels and pursuing efforts to restrict the temperature increase to 1.5 degrees Celsius above pre-industrial levels. On March 10, 2020, Oregon Governor Kate Brown issued Executive Order No. 20-04, “Directing State ~~after~~Agencies to Take Actions to Reduce and Regulate Greenhouse Gas Emissions.” The Executive Order launches rulemaking proceedings for every Oregon agency with jurisdiction over greenhouse gas-related matters, with the aim of reducing Oregon’s overall GHG emissions to 80% below 1990 levels by 2050. The Executive Order requires agencies to submit a ~~range of proposals were made, Senate Bill 5116 (SB 5116) became~~preliminary report to the vehicle for promoting the Governor’s requested action toward a “clean energy economy” in general and renewable or non-emitting electricity system specifically. SB 5116 would require Washington utilities to eliminate the allocation of coal-fired resources to Washington retail customersGovernor by the end of 2025 and to achieve carbon neutrality by 2030 while meeting a minimum 80 percent of load through delivery of renewable or non-emitting resources. The bill would require utilities to meet 100 percent of load with renewable and non-emitting resources by 2045. Under SB 5116, hydroelectric generation is considered a renewable resource. The bill was passed by both the Senate and House in April 2019 and is awaiting final approvalMay 15, 2020 regarding potential regulatory program options. We cannot reasonably predict what regulatory proceedings will arise from the ~~Governor. While we are unable to predict any outcome of these efforts, we are engaged with key parties~~Executive Order, nor how the state legislature may undertake additional requirements or revise the State's targets in ~~these policy deliberations. We do believe it likely that~~ the ~~proposed clean energy legislation will become law in 2019.~~future. We intend to seek recovery of any new costs associated with ~~the clean energy legislation~~these reduction targets, or any new reduction targets, through the regulatory process.

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 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 as incorporated in Avista Corp.’s FERC license for the Clark Fork Project, Avista Corp. works in consultation with agencies, tribes and other stakeholders to address this issue through structural modifications to the spillgates, monitoring and analysis. After extensive testing, Clark Fork Settlement Agreement stakeholders have agreed that no further spillway modifications are justified. For the remainder of the FERC License term, Avista Corp. will continue to mitigate remaining impacts of TDG while considering the potential for new approaches to further reduce TDG. The Company continues to work with stakeholders to determine the degree to which TDG abatement reduces future mitigation obligations. The Company has sought, and intends to continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue.

See the ~~2018~~2019 Form 10-K for further discussion of environmental issues and contingencies.

Enterprise Risk Management

The material risks to our businesses, and our mitigation process and procedures to address these risks, were discussed in our ~~2018~~2019 Form 10-K and have not materially changed during the three months ended March 31, ~~2019. Refer~~2020, other than the changes noted due to COVID-19. See the ~~2018~~2019 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 three months ended March 31, ~~2019.~~2020, other than the changes noted due to COVID-19. Refer to the ~~2018~~2019 Form 10-K. The financial risks included below are required interim disclosures, even if they have not materially changed from December 31, ~~2018.~~

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2019.

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 65 of the Notes to Condensed Consolidated Financial Statements" for a summary of our interest rate swap derivatives outstanding as of March 31, ~~2019~~2020 and December 31, ~~2018~~2019 and the amount of additional collateral we would have to post in certain circumstances. In addition, see "Regulatory Matters" for a discussion of commitments we made in Oregon surrounding the independent review of our interest rate hedging practices.

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AVISTA CORPORATION

Credit Risk

Avista Utilities' contracts for the purchase and sale of energy commodities can require collateral in the form of cash or letters of credit. As of March 31, ~~2019,~~2020, we had cash deposited as collateral in the amount of ~~$72.3~~$1.8 million and letters of credit of ~~$56.1~~$25.0 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 ~~2018~~2019 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 March 31, ~~2019~~2020 (including contracts that are considered derivatives and those that are considered non-derivatives), we would potentially be required to post the following additional collateral (in thousands):


	March 31, 2019		March 31, 2020
Additional collateral taking into account contractual thresholds	$	6,900	$	2,897
Additional collateral without contractual thresholds	8,500		3,407

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 March 31, ~~2019,~~2020, we had interest rate swap derivatives outstanding with a notional amount totaling $245.0 million and we had cash deposited ~~cash~~as collateral in the amount of ~~$2.9~~$27.1 million ~~as collateral~~and letters of credit of $3.9 million outstanding for these interest rate swap derivatives. If our credit ratings were lowered to below “investment grade” based on our interest rate swap derivatives outstanding at March 31, ~~2019,~~2020, we would potentially be required to post ~~up to $2.3 million of~~the following additional collateral ~~(with or without contractual thresholds).~~(in thousands):



	March 31, 2020
Additional collateral taking into account contractual thresholds	$	31,850
Additional collateral without contractual thresholds	81,280

Energy Commodity Risk

Our energy commodity risks have not materially changed during the three months ended March 31, ~~2019,~~2020, except as discussed ~~below. Refer to~~below and the ~~2018~~COVID-19 related risks. See the 2019 Form 10-K. The following table presents energy commodity derivative fair values as a net asset or (liability) as of March 31, ~~2019~~2020 that are expected to settle in each respective year (dollars in thousands):. There are no expected deliveries of energy commodity derivatives after 2022.

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 2019 $ (607 ) $ 7,354
$ (1,124 ) $ (7,539 ) $ 144
$ (20,818 ) $ (494 ) $ 254
2020 —
—
(740 ) (577 ) (680 ) (8,893 ) (1,119 ) (2,769 )
2021 —
—
—
(549 ) —
(1,065 ) (483 ) (315 )
2022 —
—
—
—
—
—
—
—
2023 —
—
—
—
—
—
—
—
Thereafter —
—
—
—
—
—
—
—



	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 2020	$	(2	)	$	(794	)	$	(203	)	$	3,185	$	427	$	4,230	$	(881	)	$	(4,997	)
2021	—			50			39			3,309		—		966		(1,345		)	(2,065		)
2022	—			—			75			368		—		—		—			(19		)

The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, ~~2018~~2019 that are expected to be delivered in each respective year (dollars in thousands):. There are no expected deliveries of energy commodity derivatives after 2022.

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)
2019 $ (2,238 ) $ 7,289
$ (991 ) $ (32,285 ) $ 34
$ (19,047 ) $ (443 ) $ 6,252
2020 —
—
(1,266 ) (7,797 ) (28 ) (4,044 ) (1,517 ) (240 )
2021 —
—
—
(1,393 ) —
—
(629 ) 47
2022 —
—
—
—
—
—

—
2023 —
—
—
—
—
—
—
—
Thereafter —
—
—
—
—
—
—
—

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~~AVISTA CORPORATION~~



	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)
2020	$	19	$	2,063	$	(895	)	$	10,929	$	(422	)	$	(7,448	)	$	(1,634	)	$	(8,922	)
2021	—		—		15			2,666		—			(26		)	(1,187		)	(1,941		)
2022	—		—		35			180		—			—			—			(5		)


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

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.

~~Regional Energy Markets~~

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The California Independent System Operator (CAISO) operates an Energy Imbalance Market (EIM) in the western United States. Most investor-owned utilities in the Pacific Northwest are either participants in the CAISO EIM or plan to integrate into the market in the near future. Factors to be considered in deciding whether to join the CAISO EIM include the amount of variable generating resources in the utilities’ systems, the ability to manage the variable generating resources within the utilities’ systems, the costs associated with joining the CAISO EIM, and the economic benefits associated with joining the CAISO EIM. As additional utilities join the CAISO EIM, there is a reduction in bilateral market liquidity and opportunities for wholesale transactions close to the operating hour. Based on these considerations, we signed an agreement in April 2019 to join the CAISO EIM. We expect to begin implementing new processes to enable participation in the EIM in the second half of 2019 and we expect to be full participants by April 2022. We estimate the total cost of joining the EIM to be approximately $25 million for both capital and operating expense spending over the three-year implementation period and we estimate annual benefits of approximately $6 million from market participation. We expect to seek recovery of the net costs through the regulatory process.

AVISTA CORPORATION

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Item 4. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) (Act) that are designed to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. With the participation of the Company’s principal executive officer and principal financial officer, the Company's management evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level as of March 31, ~~2019~~2020.

There have been no changes in the Company's internal control over financial reporting that occurred during the first quarter of ~~2019~~2020 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II. Other Information

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

Refer to the ~~2018~~2019 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 ~~2018~~2019 Form ~~10-K.~~10-K with the exception of the following:

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

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

A decrease in customer demand and revenues due to a reduction in economic activity and possibly a recession,

An increase in operating expenses, including bad debt expense due to our customers’ inability to pay amounts due to us,

A negative impact on the ability of suppliers, vendors or contractors to perform, which could increase costs and delay capital projects,

Regulatory commissions may not approve our requests to defer and recover increased expenses,

Delays in regulatory filings and the regulatory approval process, which could impact our ability to timely recover our operating expenses and costs associated with investments in utility assets,

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AVISTA CORPORATION

An increase in cyber and technology risks, including the impact on internal controls, due to a significant number of employees working remotely,

A decrease in the fair value of pension plan assets or an increase in the pension liability, which could increase future pension plan funding requirements,

A decrease in the fair value of non-utility investments, which could result in losses or impairment,

A decrease in net operating cash inflows, which could negatively impact our liquidity and limit our ability to fund capital expenditures, dividends, and other contractual commitments,

Disruption, weakness and volatility in the financial markets, which could increase our costs to fund capital requirements,

To the extent that access to the capital markets is adversely affected, we may need to consider alternative sources of funding for operations and for working capital, any of which could increase our cost of capital.

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

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

Item 6. Exhibits



15		Letter Re: Unaudited Interim Financial Information (1)
31.1		Certification of Chief Executive Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) (1)
31.2		Certification of Chief Financial Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) (1)
32		Certification of Corporate Officers (Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) (2)
~~101~~101.INS		XBRL Instance Document. The ~~following financial information from~~instance document does not appear in the ~~Quarterly Report on Form 10−Q for~~interactive data file because its XBRL tags are embedded within the ~~period ended March 31, 2019,~~inline XBRL document.
101.SCH		XBRL Taxonomy Extension Schema Document
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB		XBRL Taxonomy Extension Label Linkbase Document
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document
104		Cover page formatted as Inline XBRL and contained 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. (1)Exhibit 101.

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

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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:	May ~~1, 2019~~7, 2020	/s/ Mark T. Thies
		Mark T. Thies
		~~Senior~~Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)

5854



	Review of Cash Flow Statement	5147
	Capital Resources	5247
	Capital Expenditures	5348
	Off-Balance Sheet Arrangements	5349
	Pension Plan	5349
	Contractual Obligations	5449
	Environmental Issues and Other Contingencies	5449
	Enterprise Risk Management	54
	~~Regional Energy Markets~~	5650

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	5652

Item 4.	Controls and Procedures	5652

Part II. Other Information
Item 1.	Legal Proceedings	5652

Item 1A.	Risk Factors	5652

Item 6.	Exhibits	5753

	Signature	5854



	2019
Operating lease cost:
Fixed lease cost (Other operating expenses)	$	1,103
Variable lease cost (Other operating expenses)	243
Total operating lease cost	$	1,346

Finance lease cost:
Amortization of ROU asset (Depreciation and amortization)	$	910
Interest on lease liabilities (Interest expense)	699
Total finance lease cost	$	1,609



	2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash outflows:
Operating lease payments	$	4,092
Interest on finance lease	699
Total operating cash outflows	$	4,791

Finance cash outflows:
Principal payments on finance lease	$	665



	March 31,
	2019
Operating Leases
Operating lease ROU assets (Other property and investments-net and other non-current assets)	$	70,834

Other current liabilities	$	4,120
Other non-current liabilities and deferred credits	67,635
Total operating lease liabilities	$	71,755

Finance Leases
Finance lease ROU assets (Other property and investments-net and other non-current assets) (a)	$	53,711

Other current liabilities (b)	$	2,695
Other non-current liabilities and deferred credits (b)	53,850
Total finance lease liabilities	$	56,545

Weighted Average Remaining Lease Term
Operating leases	27.32 years
Finance leases	9.64 years

Weighted Average Discount Rate
Operating leases	3.82		%
Finance leases	4.85		%



	Electric				Natural Gas
Effective Date	Revenue Increase		Base Rate Increase		Revenue Increase		Base Rate Increase
April 1, 2020	$	45.8	9.1	%	$	12.9	13.8	%
April 1, 2021	$	18.9	3.5	%	$	6.5	6.1	%



	Natural Gas Operating Revenues
	2019			2018
Current year decoupling deferrals (a)	$	(6,106	)	$	149
Amortization of prior year decoupling deferrals (b)	3,053			(5,220		)
Total natural gas decoupling revenue	$	(3,053	)	$	(5,071	)