AVISTA CORP - Annual Report: 2019 (Form 10-K)

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•	financial performance;

•	cash flows;

•	capital expenditures;

•	dividends;

•	capital structure;

•	other financial items;

•	strategic goals and objectives;

•	business environment; and

•	plans for operations.

•	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;

•	wildfires ignited, or 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 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 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 or incur costs to repair our facilities;

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

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

•	terrorist attacks, cyberattacks or other malicious acts that 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 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;

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•	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;

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

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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;

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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;

•	growth or decline of our customer base due to new uses for our services or decline in existing 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 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;

•	the risk of municipalization or other form of service territory reduction;

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

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•	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 fossil fuel fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities;

•	failure to identify changes in legislation, taxation and regulatory issues that 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;

•	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 could 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 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;

•	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;

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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;

•	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;

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

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Avista Utilities – an operating division of Avista Corp., comprising the regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana, most of whom are employees who operate Avista Utilities' Noxon Rapids generating facility. Avista Utilities also engages in wholesale purchases and sales of electricity and natural gas as an integral part of energy resource management and its load-serving obligation.

•	AEL&P - a utility providing electric services in Juneau, Alaska that is a wholly-owned subsidiary and the primary operating subsidiary of AERC.

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

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

•	purchasing fuel for generation,

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

•	other wholesale transactions to capture the value of generating resources, transmission contract rights and fuel delivery (transport) capacity contracts.

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(1)

"Normal" hydroelectric generation is determined by reference to the effect of upstream dam regulation on median natural water flow. Natural water flow is the flow of the rivers without the influence of dams, whereas regulated water flow takes into account any water flow changes from upstream dams due to releasing or holding back water. The calculation of "normal" varies annually due to the timing of upstream dam regulation throughout the year, as well as changes in PUD contracts.

•	the combined cycle natural gas-fired CT, known as Coyote Springs 2, located near Boardman, Oregon,

•	a 15 percent interest in units 3 & 4 of the Colstrip GS, a coal-fired boiler generating facility located in southeastern Montana,

•	a wood waste-fired boiler generating facility known as the Kettle Falls GS in northeastern Washington,

•	a two-unit natural gas-fired CT generating facility, located in northeastern Spokane (Northeast CT),

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•	a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT), and

•	two small natural gas-fired generating facilities (Boulder Park GS and Kettle Falls CT).

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(1)	The contracts for power sales decrease due to certain contracts expiring in each of these years. We are evaluating the future plan for the additional resources made available due to the expiration of these contracts.

(2)	The forecast assumes near normal hydroelectric generation.

(3)	Includes the Lancaster Plant PPA. Excludes Boulder Park GS, Kettle Falls CT, Northeast CT and Rathdrum CT, as these are considered peaking facilities and are generally not used to meet our base load requirements.

(4)	Other contracts for power purchases includes power purchase agreements for solar and wind energy.

(5)	The combined maximum capacity of Boulder Park GS, Kettle Falls CT, Northeast CT and Rathdrum CT is 278 MW, with estimated available energy production as indicated for each year.

•	Models the clean energy requirements of CETA in Washington State.

•	Optimizing a resource portfolio for 25 years instead of 20 years.

•	Assumes Colstrip exits the portfolio in 2025, and then studies the cost impacts of extending the project to 2035 for servicing loads outside of Washington.

•	Assumes the Northeast CT retires in 2035.

•	A cap and trade greenhouse gas emissions cap applies in modeling Oregon.

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•	Uses a full demand response (DR) potential assessment for potential DR programs for both residential and commercial/industrial customers.

•	Includes social cost of carbon costs, using the 2.5 percent discount rate proscribed in CETA, for Washington's share of resource emissions and market purchases for new resource acquisitions, DR programs, and energy efficiency.

•	Includes cost of upstream greenhouse gas emissions from the natural gas-fired projects at the social cost of carbon for Washington share of resources.

•	Modeled wind, solar, pumped hydro storage, nuclear, and geothermal as purchase power agreements; whereas previous IRPs assumed these resources would be modeled as an owned resource.

•	Modeled several energy storage options in this IRP including pumped hydro storage, lithium-ion, vanadium flow, zinc bromide flow, liquid air, and hydrogen all with varying energy durations. The previous IRP modeled storage generically.

•	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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•	We will need no additional natural gas transportation resources during the 20-year planning horizon in Washington, Idaho, or Oregon.

•	Due to expected carbon legislation at the state levels through a cap and trade mechanism (Oregon) or a fee mechanism (Washington), we expect natural gas prices to include a carbon price adder in Oregon and Washington, but not in Idaho.

•	North American supplies of natural gas will continue to be abundant led by shale gas development.

•	Customer growth in our service territory will increase slightly compared to the 2016 IRP. There will be increasing interest from customers to utilize natural gas for heating due to its abundant supply and consequent low cost.

•	We anticipate that any increased demand for natural gas regionally will primarily come from power generation as natural gas is increasingly being used to back up solar and wind technology, and also to replace retired coal plants. There is also potential for increased usage in other markets, such as LNG exports or exports to Mexico.

•	Slightly higher customer growth will continue to be offset by lower use per customer and an increased amount of demand side management (DSM). The combination of low-priced natural gas in addition to carbon fees or other programs has led to a higher potential for DSM measures as compared to the previous three IRPs.

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The availability of natural gas in North America will continue to change global LNG dynamics. Existing and new LNG facilities will look to export low cost North American natural gas to the higher-priced foreign markets. This could alter the price of natural gas and/or transportation in U.S. markets, constrain existing pipeline networks, stimulate development of new pipeline resources and change flows of natural gas across North America.

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(1)	Cooling degree days are 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 historical average indicate warmer than average temperatures).

(2)	Heating degree days are 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 historical averages indicate warmer than average temperatures).

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(1)	Heating degree days are 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).

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(1)	Heating degree days are 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 heating degree days below historical average indicate warmer than average temperatures).

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•	Unconsolidated equity investments are primarily in emerging technology venture capital funds and companies, including an investment in a joint venture focused on local real estate development and economic growth.

•	Real estate consists of mixed use commercial, retail office space, and land.

•	Other assets that consist of income tax receivables, cash and other deferred charges.

•	AM&D, doing business as METALfx, performed custom sheet metal fabrication of electronic enclosures, parts and systems for the computer, construction, telecom, renewable energy and medical industries. METALfx was sold in April 2019. See "Note 25 of the Notes to Consolidated Financial Statements" for further discussion of the sale.

•	Includes AERC and AJT Mining, which is a wholly-owned subsidiary of AERC and is an inactive mining company holding certain real estate.

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•	required to write off our regulatory assets, and

•	precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred, even if we are expected to recover these amounts from customers in the future.

•	severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, snow and ice storms, which could disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies support services and general business operations,

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

•	unplanned outages at generating plants,

•	fuel cost and availability, including delivery constraints,

•	explosions, fires, accidents, or mechanical breakdowns that could occur while operating and maintaining our generation, transmission and distribution systems,

•	property damage or injuries to third parties caused by our generation, transmission and distribution systems,

•	natural disasters that can disrupt energy generation, transmission and distribution, and general business operations,

•	terrorist attacks or other malicious acts that may disrupt or cause damage to our utility assets or the vendors we utilize, and

•	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.

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•	disruptive innovations in the marketplace may outpace our ability to compete or manage our risk,

•	customers may have a choice in the future over the sources from which to receive their energy and we may not be able to compete,

•	potential difficulties in integrating acquired operations and in realizing expected opportunities, diversions of management resources and losses of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities,

•	market or other conditions that could adversely affect our operations or require changes to our business strategy and could result in a non-cash goodwill impairment charge that would reduce assets and net income, and

•	potential reputational risk arising from repeated general rate case filings, degradation in the quality of service, or from failed strategic investments and opportunities, which could erode shareholder, customer and community satisfaction with the Company;

•	the risk of municipalization or other form of service territory reduction.

•	increase the operating costs of generating plants,

•	increase the lead time and capital costs for the construction of new generating plants,

•	require modification of our existing generating plants,

•	require existing generating plant operations to be curtailed or shut down,

•	reduce the amount of energy available from our generating plants,

•	restrict the types of generating plants that can be built or contracted with,

•	require construction of specific types of generation plants at higher cost, and

•	increase the cost or limit the ability of distributing natural gas to customers.

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•	certain retail electricity and natural gas sales,

•	the cost of natural gas supply, and

•	the cost of power supply.

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•	electric and natural gas utilities,

•	electric generators and transmission providers,

•	oil and natural gas producers and pipelines,

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

•	energy marketing and trading companies.

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•	our obligation to serve our retail customers at rates set through the regulatory process - we cannot decline to serve our customers and we cannot change retail rates to reflect current energy prices unless and until we receive regulatory approval,

•	customer demand, which is beyond our control because of weather, customer choices, prevailing economic conditions and other factors,

•	some of our energy supply cost is fixed by the nature of the energy-producing assets or through contractual arrangements (however, a significant portion of our energy resource costs are not fixed), and

•	the potential non-performance by commodity counterparties, which could lead to replacement of the scheduled energy or natural gas at higher prices.

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(1)	Nameplate rating, also referred to as “installed capacity,” is the manufacturer’s assigned power capability under specified conditions.

(2)	Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2019.

(3)

For Cabinet Gorge, we have water rights permitting generation up to 265 MW. However, if natural stream flows will allow for generation above our water rights, we are able to generate above our water rights. If natural stream flows only allow for generation at or below 265 MW, we are limited to generation of 265 MW. The present capability disclosed above represents the capability based on maximum stream flow conditions when we are allowed to generate above our water rights.

(4)	These generating stations can operate as separate single-cycle plants or combined-cycle with the natural gas plant providing exhaust heat to the wood boiler to increase efficiency.

(5)	Jointly owned; data refers to our 15 percent interest.

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(1)	Nameplate rating, also referred to as “installed capacity,” is the manufacturer’s assigned power capability under specified conditions.

(2)	Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2019.

(3)	AEL&P does not own this generating facility but has a PPA under which it has the right to purchase, and the obligation to pay for (whether or not energy is received), all of the capacity and energy of this facility. See further information at "Part 1. Item 1. Business – Alaska Electric Light and Power Company."

•	our results of operations, cash flows and financial condition,

•	the success of our business strategies, and

•	general economic and competitive conditions.

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•	certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding),

•	certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements (see "Item 7. Management's Discussion and Analysis - Capital Resources" for compliance with these covenants),

•	the hydroelectric licensing requirements of section 10(d) of the FPA (see “Note 1 of Notes to Consolidated Financial Statements”), and

•	certain requirements under the OPUC approval of the AERC acquisition in 2014. The OPUC's AERC acquisition order requires Avista Utilities to maintain a capital structure of no less than 35 percent common equity (inclusive of short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC.

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(1)

Effective, January 1, 2019, we adopted ASC 842 which resulted in the reclassification of the Snettisham lease from long-term debt, to lease liabilities in 2019. The Snettisham lease amount is included here to maintain comparability to prior years and be consistent with our credit facility covenant calculations. In addition, other operating leases were recorded on the Consolidated Balance Sheet as of January 1, 2019 and are included here. See "Note 5 of the Notes to Consolidated Financial Statements" for further discussion and for the amounts recorded in 2019.

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•	seek recovery of operating costs and capital investments, and

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

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(1)	Due to declining wholesale natural gas prices that occurred since the 2017 PGAs were filed and went into effect, we filed, and the respective commissions approved, out of cycle PGAs to reduce customer rates and pass through expected lower costs during the winter heating months, rather than waiting until the next scheduled PGA.

•	short-term wholesale market prices and sales and purchase volumes,

•	the level, availability and optimization of hydroelectric generation,

•	the level and availability of thermal generation (including changes in fuel prices),

•	retail loads, and

•	sales of surplus transmission capacity.

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(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.

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

(b)

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

•	a $0.7 million decrease in retail electric revenues due to a decrease in revenue per MWh (decreased revenues $7.3 million), partially offset by an increase in total MWhs sold (increased revenues $6.6 million).

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

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The increase in total retail MWhs sold was the result of weather that was cooler than the prior year during the first and fourth quarter heating seasons (which increased electric heating loads), and residential and commercial customer growth. Compared to 2018, residential electric use per customer increased 2 percent and commercial use per customer was consistent between years. Heating degree days in Spokane were 3 percent above normal and 11 percent above 2018. Cooling degree days in Spokane were 8 percent below normal and 6 percent below the prior year.

•	an $11.8 million decrease in wholesale electric revenues due to a decrease in sales volumes (decreased revenues $22.2 million), partially offset by an increase in sales prices (increased revenues $10.4 million). The fluctuation in volumes and prices was primarily the result of our optimization activities.

•	a $14.2 million decrease in sales of fuel due to a decrease in sales of natural gas fuel as part of thermal generation resource optimization activities. For 2019, $48.0 million of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For 2018, $30.6 million of these sales were made to our natural gas operations.

•	a $3.8 million increase in electric revenue due to decoupling and was primarily the result of lower amortizations of prior year decoupling surcharge balances.

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a $14.3 million increase in other electric revenues primarily related to federal income tax law changes that lowered the corporate tax rate from 35 percent to 21 percent. During the first quarter of 2018, our customers' rates had the 35 percent corporate tax rate built in from prior general rate cases and we were collecting this amount through retail revenues. At the same time, we were deferring the difference between the 35 percent and the 21 percent through other revenues. Effective May 1, 2018 in Washington and June 1, 2018 in Idaho, base rates reflect the lower 21 percent corporate tax. At that time, we began returning the deferred amounts to customers through other revenue. The tax amounts included in other revenue was partially offset by the accrual for customer refunds associated with the 2015 Washington general rate case.

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(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.

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

(b)

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

•	a $5.4 million increase in retail natural gas revenues due to an increase in volumes (increased revenues $32.3 million), partially offset by lower retail rates (decreased revenues $26.9 million).

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Retail natural gas sales increased in 2019 as compared to 2018 due to cooler weather during the heating season, and residential and commercial customer growth. Compared to 2018, residential use per customer increased 9 percent and commercial use per customer increased 12 percent. Heating degree days in Spokane were 3 percent above normal for 2019, and 11 percent above 2018. Heating degree days in Medford were 3 percent above normal for 2019, and 7 percent above 2018.

◦	Lower retail rates were due to PGAs and rate decreases associated with the lower corporate tax rate and decoupling rate decreases (as our decoupling surcharges were larger in prior years, which resulted in higher surcharge rates in 2018 as compared to rebates in 2019), partially offset by general rate increases in Washington (effective May 1, 2018) and Idaho (effective January 1, 2019).

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a $2.1 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $21.9 million), partially offset by an increase in volumes (increased revenues $19.8 million). In 2019, $65.4 million of these sales were made to our electric generation operations and are included as intracompany revenues and resource costs. In 2018, $44.7 million of these sales were made to our electric generation operations. Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.

•	a $4.9 million increase in natural gas revenue due to decoupling primarily related to amortizations of prior year decoupling balances.

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an $8.8 million increase in other natural gas revenues primarily related to federal income tax law changes that lowered the corporate tax rate from 35 percent to 21 percent. During the first quarter of 2018, our customers' rates had the 35 percent corporate tax rate built in from prior general rate cases and we were collecting this amount through retail revenues. At the same time, we were deferring the difference between the 35 percent and the 21 percent through other revenues. Effective May 1, 2018 in Washington and June 1, 2018 in Idaho, base rates reflect the lower 21 percent corporate tax. At that time, we began returning the deferred amounts to customers through other revenue.

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•	a $2.0 million decrease in power purchased due to a decrease in the volume of power purchases (decreased costs $26.8 million), partially offset by an increase in wholesale prices (increased costs $24.8 million). The fluctuation in volumes and prices was primarily the result of our optimization activities.

•	an $11.1 million increase in fuel for generation primarily due to an increase in thermal generation resulting from lower hydroelectric generation, as well as an increase in natural gas fuel prices.

•	a $7.2 million decrease in other fuel costs.

•	a $19.6 million decrease from amortizations and deferrals of power costs (included in other resource costs in the graph above). This change was primarily the result of higher net power supply costs.

•	a $1.8 million decrease in other regulatory amortizations (included in other resource costs in the graph above).

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•	a $48.2 million increase in natural gas purchased due to an increase in total therms purchased (increased costs $34.7 million) and an increase in the price of natural gas (increased costs $13.5 million).

•	a $38.6 million decrease from amortizations and deferrals of natural gas costs (included in other resource costs in the graph above).

•	a $3.5 million increase in other regulatory amortizations (included in other resource costs in the graph above).

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Regulatory accounting, in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 980, Regulated Operations, among other things, requires that costs and/or obligations that are probable of recovery through rates charged to our customers, but are not yet reflected in rates, not be reflected in our Consolidated Statements of Income until the period in which they are reflected in rates and matching revenues are recognized. Meanwhile, these costs and/or obligations are deferred and reflected on our Consolidated Balance Sheets as regulatory assets or liabilities. The provisions of the accounting guidance may result in recognition of revenues and expenses in time periods that are different than non-rate-regulated enterprises. In addition, regulatory accounting requires that decoupling revenue, unlike deferred costs, be recognized in the Consolidated Statements of Income during the period in which it occurs (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject

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Interest rate swap derivative asset and liability accounting, where we estimate the fair value of outstanding interest rate swap derivatives and offset the derivative asset or liability with a regulatory asset or liability. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. We record this offset because, based on the prior practice of the regulatory commissions, we assume that we will be allowed recovery through the ratemaking process. If we concluded that recovery of interest rate swap related payments were no longer probable, we would be required to derecognize the related regulatory assets and liabilities and we could be required to recognize significant changes in fair value or settlements of these interest rate swap derivatives on a regular basis in the Consolidated Statements of Income, which could lead to significant fluctuations in net income.

•	Pension Plans and Other Postretirement Benefit Plans, discussed in further detail below.

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Contingencies, related to unresolved regulatory, legal and tax issues as to which there is inherent uncertainty for the ultimate outcome of the respective matter. We accrue a loss contingency if it is probable that an asset is impaired or a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. We also disclose losses that do not meet these conditions for accrual, if there is a reasonable possibility that a potential loss may be incurred. For all material contingencies, we have made a judgment as to the probability of a loss occurring and as to whether or not the amount of the loss can be reasonably estimated. However, no assurance can be given as to the ultimate outcome of any particular contingency. See "Notes 1 and 21 of the Notes to Consolidated Financial Statements" for further discussion of our commitments and contingencies.

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•	employee demographics (including age, compensation and length of service by employees),

•	the amount of cash contributions we make to the pension plan,

•	the actual return on pension plan assets,

•	expected return on pension plan assets,

•	discount rate used in determining the projected benefit obligation and pension costs,

•	assumed rate of increase in employee compensation,

•	life expectancy of participants and other beneficiaries, and

•	expected method of payment (lump sum or annuity) of pension benefits.

(a)	The SERP has no plan assets. The plan assets in this disclosure are for the pension plan only.

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*	Changes in the expected return on plan assets would not affect our projected benefit obligation.

•	increases in demand (due to either weather or customer growth),

•	lower streamflows for hydroelectric generation,

•	unplanned outages at generating facilities, and

•	failure of third parties to deliver on energy or capacity contracts.

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(1)

Effective, January 1, 2019, we adopted ASC 842 which resulted in the reclassification of the Snettisham lease from long-term debt, to lease liabilities in 2019. The Snettisham lease amount is included here for this calculation. In addition, other operating leases were recorded on the Consolidated Balance Sheet as of January 1, 2019 and are included here for this calculation. See "Note 5 of the Notes to Consolidated Financial Statements" for further discussion and for the amounts recorded in 2019.

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•	66-2/3 percent of the cost or fair value (whichever is lower) of property additions of that entity which have not previously been made the basis of any application under that entity's Mortgage, or

•	an equal principal amount of retired first mortgage bonds of that entity which have not previously been made the basis of any application under that entity's Mortgage, or

•	deposit of cash.

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(1)	Standard & Poor’s lowest “investment grade” credit rating is BBB-.

(2)	Moody’s lowest “investment grade” credit rating is Baa3.

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(1)	Represents our estimate of interest payments on long-term debt, which is calculated based on the assumption that all debt is outstanding until maturity. Interest on variable rate debt is calculated using the rate in effect at December 31, 2019.

(2)	Energy purchase contracts were entered into as part of the obligation to serve our retail electric and natural gas customers’ energy requirements. As a result, costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost deferral and recovery mechanisms.

(3)	Primarily relates to an operating lease with the State of Montana for about $4.0 million annually and expires in 2046. See "Note 5 of the Notes to Consolidated Financial Statements" for further discussion of this and our other leases.

(4)	Represents operating agreements, settlements and other contractual obligations for our generation, transmission and distribution facilities. These costs are generally recovered through base retail rates.

(5)	Includes information service contracts which are recorded to other operating expenses in the Consolidated Statements of Income.

(6)

Represents our estimated cash contributions to pension plans and other postretirement benefit plans through 2024. We have only included pension and other postretirement funding through 2029 as we cannot reasonable estimate the amounts beyond that time period. This is consistent with the time period presented in "Note 11 of the Notes to Consolidated Financial Statements." This amount is above our contractually obligated amount.

(7)

Represents the net mark-to-market fair value of outstanding unsettled interest rate swap derivatives as of December 31, 2019. The values in the table above will change each period depending on fluctuations in market interest rates and could become either assets or liabilities. Also, the amounts in the table above are not reflective of cash collateral of $6.8 million that is already posted with counterparties against the outstanding interest rate swap derivatives.

(8)	Primarily relates to long-term debt and finance lease maturities and the related interest. AEL&P contractual commitments also include contractually required capital project funding and operating and maintenance costs associated with the Snettisham hydroelectric project. These costs are generally recovered through base retail rates.

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(9)	Primarily relates to venture fund commitments, and a commitment to fund a limited liability company in exchange for equity ownership, made by a subsidiary of Avista Capital. Also, there is a long-term debt maturity and the related interest associated with AERC.

•	localized and system-wide demand for energy,

•	type, capacity, location and availability of generation resources, and

•	variety and circumstances of market participants.

•	transmit power and energy to or for wholesale purchasers and sellers,

•	enlarge or construct additional transmission capacity for the purpose of providing these services, and

•	transparently price and offer transmission services without favor to any party, including the merchant functions of the utility.

•	other utilities,

•	federal power marketing agencies,

•	energy marketing and trading companies,

•	independent power producers,

•	financial institutions, and

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•	commodity brokers.

•	assumptions relating to weather and economic and competitive conditions,

•	internal analysis of company-specific data, such as energy consumption patterns,

•	internal business plans,

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•	an assumption that we will incur no material loss of retail customers due to self-generation or retail wheeling, and

•	an assumption that demand for electricity and natural gas as a fuel for mobility will for now be immaterial.

•	increase the operating costs of generating plants;

•	increase the lead time and capital costs for the construction of new generating plants;

•	require modification of our existing generating plants;

•	require existing generating plant operations to be curtailed or shut down;

•	reduce the amount of energy available from our generating plants;

•	restrict the types of generating plants that can be built or contracted with;

•	require construction of specific types of generation plants at higher cost; and

•	increase costs of distributing, or limit our ability to distribute, electricity and/or natural gas.

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•	facilitates internal and external communications regarding climate change and related issues,

•	analyzes policy effects, anticipates opportunities and evaluates strategies for the Company,

•	develops recommendations on climate-related policy positions and action plans, and

•	provides direction and oversight with respect to the Company’s clean energy goals.

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•	communication and involvement with local business leaders and community organizations,

•	providing customers with a multitude of limited income initiatives, including energy fairs, senior outreach and low income workshops, mobile outreach strategy and a Low Income Rate Assistance Plan,

•	tailoring our internal company initiatives to focus on choices for our customers, to increase their overall satisfaction with the Company, and

•	engaging in the legislative process in a manner that fosters the interests of our customers and the communities we serve.

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(1)	There are offsetting regulatory assets and liabilities for these items on the Consolidated Balance Sheets in accordance with regulatory accounting practices.

(2)	The balance as of December 31, 2019 and December 31, 2018 reflects the offsetting of $6.8 million and $0.5 million, respectively, of cash collateral against the net derivative positions where a legal right of offset exists.

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(1)	These balances include the fixed rate long-term debt of Avista Corp., AEL&P and AERC.

•	transacting through clearinghouse exchanges,

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

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

•	actively monitoring current credit exposures,

•	asserting our collateral rights with counterparties, and

•	carrying out transaction settlements timely and effectively.

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

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•

We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•	We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•

We read relevant regulatory orders issued by the Commissions for the Company and other public utilities in the Company’s jurisdictions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on the precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness.

•	We inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company’s future rates, evaluating the evidence in relation to management’s assertions, as applicable.

•

We inquired of management about property, plant, and equipment that may be abandoned. We inspected the capital-projects budget and construction-work-in-process listings and inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of their useful life. We inspected minutes of the Board of Directors and regulatory orders and other filings with the Commissions, evaluating the evidence in relation to management’s assertions, as applicable, regarding probability of an abandonment.

•	We obtained an analysis from management regarding probability of recovery for regulatory assets or probability of either refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order in order to assess management’s assertion that amounts are probable of recovery and/or that a future refund or reduction in rates is not probable.

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•	determining the market value of energy commodity derivative assets and liabilities,

•	pension and other postretirement benefit plan obligations,

•	contingent liabilities,

•	goodwill impairment testing,

•	recoverability of regulatory assets, and

•	unbilled revenues.

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(1)	For 2017 income tax benefits were calculated using a 35 percent income tax rate; however, due to the TCJA enactment, beginning on January 1, 2018 income tax benefits are calculated using a 21 percent tax rate.

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

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

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

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•	required to write off its regulatory assets, and

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

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•	the number of customers,

•	current rates,

•	meter reading dates,

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•	actual native load for electricity,

•	actual throughput for natural gas, and

•	electric line losses and natural gas system losses.

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(a)

At December 31, 2018, the finance lease ROU assets were included in "Net utility property" on the 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 Consolidated Balance Sheet such that their presentation as of December 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 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 Consolidated Balance Sheet such that their presentation as of December 31, 2019 is consistent with operating leases.

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(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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(1)

At December 31, 2018, the finance lease ROU assets were included in "Net utility property" on the 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 Consolidated Balance Sheet such that their presentation as of December 31, 2019 is consistent with operating leases.

(2)	Included in other property and investments-net and other non-current assets on the Consolidated Balance Sheets. Accumulated depreciation was $5.4 million as of December 31, 2019 and $12.4 million as of December 31, 2018 for the other businesses.

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•	restore coal ash containment ponds and coal holding areas at Colstrip,

•	cap a landfill at the Kettle Falls Plant, and

•	remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease.

•	removal and disposal of certain transmission and distribution assets, and

•	abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities.

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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

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•	properties are externally appraised on an annual basis by independent appraisers, additional appraisals may be performed as warranted by specific asset or market conditions,

•	property valuations are reviewed quarterly and adjusted as necessary, and

•	loans are reflected at fair value.

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(1)	This category invests in multiple strategies to diversify risk and reduce volatility. The strategies include: (a) event driven, relative value, convertible, and fixed income arbitrage, (b) distressed investments, (c) long/short equity and fixed income, and (d) market neutral strategies.

(1)	The balanced index fund for 2019 and 2018 is a single mutual fund that includes a percentage of U.S. equity and fixed income securities and International equity and fixed income securities.

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•	A permanent reduction in the statutory corporate tax rate from 35 percent to 21 percent, beginning with tax years after 2017;

•

Statutory provisions requiring that excess deferred taxes associated with public utility property be normalized using the ARAM or the Reverse South Georgia Method for determining the timing of the return of excess deferred taxes to customers. Excess deferred taxes result from revaluing deferred tax assets and liabilities based on the newly enacted tax rate instead of the previous tax rate, which, for most rate-regulated utilities like Avista Utilities and AEL&P, results in a net benefit to customers that will be deferred as a regulatory liability and passed through to customers over future periods;

•	Repeal of the corporate AMT;

•	Bonus depreciation (expensing of capital investment on an accelerated basis) was removed as a deduction for property predominantly used in certain rate-regulated businesses (like Avista Utilities and AEL&P), but is still allowed for the Company's non-regulated businesses; and

•	NOL carryback deductions were eliminated, but carryforward deductions are allowed indefinitely with some annual limitations versus the previous 20-year limitation.

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(1)

In December 2010, $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due in 2032 and 2034, respectively, which had been held by Avista Corp. since 2008 and 2009, respectively, were refunded by new variable rate bond issues (Series 2010A and Series 2010B). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, these bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s Consolidated Balance Sheets.

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(2)

In November 2019, the Company issued and sold $180.0 million of 3.43 percent first mortgage bonds due in 2049 pursuant to a bond purchase agreement with institutional investors in the private placement market. The total net proceeds from the sale of the bonds were used to repay maturing long-term debt of $90.0 million, repay a portion of the outstanding balance under Avista Corp.'s $400.0 million committed line of credit and for other general corporate purposes. In connection with the issuance and sale of the first mortgage bonds, the Company cash settled six interest rate swap derivatives (notional aggregate amount of $70.0 million) and paid a net amount of $13.3 million. See note 7 for a discussion of interest rate swap derivatives.

(3)

Effective January 1, 2019, due to the adoption of the new lease standard (ASU 2016-02), capital leases will now be defined as finance leases and are presented in "Other current liabilities" and "Other non-current liabilities and deferred credits" on the Consolidated Balance Sheet such that their presentation as of December 31, 2019 is consistent with operating leases. See Notes 2 and 5 for further discussion of the new lease standard.

•	66-2/3 percent of the cost or fair value (whichever is lower) of property additions of that entity which have not previously been made the basis of any application under that entity's Mortgage, or

•	an equal principal amount of retired first mortgage bonds of that entity which have not previously been made the basis of any application under that entity's Mortgage, or

•	deposit of cash.

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(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 Consolidated Balance Sheets.

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(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.

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•	certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding),

•	certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements,

•	the hydroelectric licensing requirements of section 10(d) of the FPA (see Note 1), and

•	certain requirements under the OPUC approval of the AERC acquisition in 2014. The OPUC's AERC acquisition order requires Avista Utilities to maintain a capital structure of no less than 35 percent common equity (inclusive of short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC.

(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 11 for additional details).

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

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(1)	Earning a return includes either interest on the regulatory asset/liability or a return on the investment as a component of rate base at the allowed rate of return.

(2)	Expected recovery is pending regulatory treatment including regulatory assets and liabilities with prior regulatory precedence.

(3)	Remaining amortization period varies depending on timing of underlying transactions.

(4)	As the Company has historically recovered and currently recovers its pension and other postretirement benefit costs related to its regulated operations in retail rates, the Company records a regulatory asset for that portion of its pension and other postretirement benefit funding deficiency.

(5)

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 losses result in adjustments to retail rates through PGAs, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. The resulting regulatory assets associated with energy commodity derivative instruments have been concluded to be probable of recovery through future rates.

(6)

For the Company’s Washington jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. In the Company’s other regulatory jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding debt when no new debt was issued in connection with the debt repurchase. These costs are recovered through retail rates as a component of interest expense.

(7)

In March 2016, the WUTC granted the Company's Petition for an Accounting Order to defer and include in a regulatory asset the undepreciated value of its existing Washington electric meters for the opportunity for later recovery. This accounting treatment is related to the Company's plan to replace approximately 253,000 of its existing electric meters with new two-way digital meters and the related software and support services through its AMI project in Washington State. In September 2017, the WUTC also approved the Company's request to defer the undepreciated net book value of existing natural gas ERTs (consistent with the accounting treatment for the electric meters) that will be retired as part of the AMI project. Replacement of the meters and natural gas ERTs began in the second half of 2018. The other piece of abandoned plant, relates to the Company's decision to replace a three-phase transformer at one of its generating facilities with three separate single-phase transformers. The Company expects to receive full recovery of the cost of the three-phase transformer; therefore, it has recorded the remaining net book value as a regulatory asset.

(8)

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

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(9)	This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant.

(10)

The amount pending recovery represents amounts due back to customers and resulted from the TCJA, which changed the federal income tax rate from 35 percent to 21 percent. The Company revalued all deferred income taxes as of December 31, 2017. The Company expects the amounts for utility plant items for Avista Utilities to be returned to customers over a period of approximately 36 years. The Company expects the AEL&P amounts to be returned to customers over a period of approximately 40 years. The regulatory liability attributable to non-plant excess deferred taxes is approximately $11.1 million and $18.5 million (among all jurisdictions) as of December 31, 2019 and December 31, 2018, respectively. The return of this amount to customers will be determined by final orders from the WUTC, IPUC and OPUC during 2019 and 2020. See Note 11 for additional discussion regarding the new federal income tax law.

(11)	See Note 1 for a description of a reclassification associated with this regulatory asset, which is being amortized based on the underlying utility plant assets and the life of utility plant.

•	short-term wholesale market prices and sales and purchase volumes,

•	the level, availability and optimization of hydroelectric generation,

•	the level and availability of thermal generation (including changes in fuel prices),

•	retail loads, and

•	sales of surplus transmission capacity.

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(1)	Intersegment eliminations reported as interest expense represent intercompany interest. Intersegment eliminations reported as assets represent intersegment accounts receivable.

(2)	Other operating expenses for Avista Utilities for 2019, 2018 and 2017 include merger transaction costs which are separately disclosed on the Consolidated Statements of Income.

(3)	Including interest expense to affiliated trusts.

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

(5)	Effective January 1, 2018, the Company adopted ASU No. 2017-07, which resulted in a $7.7 million reclassification of the non-service cost component of pension and other postretirement benefit costs for 2017. The costs were reclassified from utility other operating expenses to other expense (income) - net on the Consolidated Statements of Income.

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•	on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 11, 2020, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 29, 2019, relating to its Annual Meeting of Shareholders held on May 9, 2019.

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•	on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 11, 2020, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 29, 2019, relating to its Annual Meeting of Shareholders held on May 9, 2019.

(a)	Security ownership of certain beneficial owners (owning 5 percent or more of Registrant’s voting securities):

•	on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 11, 2020, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 29, 2019, relating to its Annual Meeting of Shareholders held on May 9, 2019; reference also being made to Schedules 13G, as amended, on file with the SEC with respect to the Registrant's voting securities (the information contained in such schedules 13G, as amended, not being incorporated herein by reference).

(b)	Security ownership of management:

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•	on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 11, 2020, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 29, 2019, relating to its Annual Meeting of Shareholders held on May 9, 2019.

(c)	Changes in control:

(d)	Securities authorized for issuance under equity compensation plans as of December 31, 2019:

(1)

Excludes unvested restricted shares and performance share awards granted under Avista Corp.’s Long-Term Incentive Plan. At December 31, 2019, 93,351 Restricted Share awards were outstanding. Performance and market-based share awards may be paid out at zero shares at a minimum achievement level; 267,025 shares at target level; or 534,050 shares at a maximum level. Because there is no exercise price associated with restricted shares or performance and market-based share awards, such shares are not included in the weighted-average price calculation.

(2)	Includes the Long-Term Incentive Plan approved by shareholders in 1998 (amended in 2016) and the Non-Employee Director Stock Plan approved by shareholders in 1996. In February 2005, the Board of Directors elected to terminate the Non-Employee Director Stock Plan.

•	on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 11, 2020, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 29, 2019, relating to its Annual Meeting of Shareholders held on May 9, 2019.

•	on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 11, 2020, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 29, 2019, relating to its Annual Meeting of Shareholders held on May 9, 2019.

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(a)	1. Financial Statements (Included in Part II of this report):

(a)	2. Financial Statement Schedules:

(a)	3. Exhibits:

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(1)	Incorporated herein by reference.

(2)	Filed herewith.

(3)	Management contracts or compensatory plans filed as exhibits to this Form 10-K pursuant to Item 15(b).

(4)	Furnished herewith.

(5)	Applies to Kevin J. Christie, Bryan A. Cox, Marian M. Durkin, Karen S. Feltes, Gregory C. Hesler, Latisha D. Hill, James M. Kensok, Ryan L. Krasselt, David J. Meyer, Scott L. Morris, Heather L. Rosentrater, Edward D. Schlect, Jason R. Thackston, Mark T. Thies, and Dennis P. Vermillion.

(6)	Applies to Kevin J. Christie, Bryan A. Cox, Marian M. Durkin, Karen S. Feltes, Latisha D. Hill, James M. Kensok, Ryan L. Krasselt, David J. Meyer, Scott L. Morris, Heather L. Rosentrater, Jason R. Thackston, Mark T. Thies, and Dennis P. Vermillion.

(7)	Applies to Scott L. Morris and Karen S. Feltes.

(8)	Applies to Kevin J. Christie, Bryan A. Cox, Marian M. Durkin, Gregory C. Hesler, Latisha D. Hill, James M. Kensok, Ryan L. Krasselt, David J. Meyer, Heather L. Rosentrater, Edward D. Schlect, Jason R. Thackston, Mark T. Thies, and Dennis P. Vermillion.

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