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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.

•	weather conditions (temperatures, precipitation levels and wind patterns) which affect both energy demand and electric generating capability, including the effect of precipitation and temperature on hydroelectric resources, the effect of wind patterns on wind-generated power, weather-sensitive customer demand, and similar effects 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 and other capital market conditions and the global economy;

•	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 we recover interest costs through utility operations;

•	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;

•	external pressure to meet financial goals that can lead to short-term or expedient decisions that reduce the likelihood of long-term objectives being met;

•	deterioration in the creditworthiness of our customers;

•	the outcome of pending legal proceedings arising out of the “western energy crisis” of 2000 and 2001, specifically related to the Pacific Northwest refund proceedings;

•	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 and/or conservation measures;

•	changes in the long-term global and our utilities' service area climates, which can affect, among other things, customer demand patterns and the volume and timing of streamflows to our hydroelectric resources;

•	changes in industrial, commercial and residential growth and demographic patterns in our service territory or changes in demand by significant customers;

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•	state and federal regulatory 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 and commodity costs and discretion over allowed return on investment;

•	possibility that our integrated resource plans for electric and natural gas will not be acknowledged by the state commissions;

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volatility and illiquidity in wholesale energy markets, including 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 counterparties 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 obsolescence of our power supply resources;

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

•	explosions, fires, accidents, mechanical breakdowns or other incidents that may impair assets and may disrupt operations of any of our generation facilities, transmission and distribution systems or other operations and may require us to purchase replacement power;

•	public injuries or damage arising from or allegedly arising from our operations;

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

•	terrorist attacks, cyber attacks or other malicious acts that may disrupt or cause damage to our utility assets or to the national economy in general, including any effects of terrorism, cyber attacks 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;

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

•	third party construction of buildings, billboard signs or towers within our rights of way, or placement of fuel receptacles 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 disruptions to the supply chain;

•	increasing health care costs and the resulting effect on employee injury costs and health insurance provided to our employees and retirees;

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

•	compliance with extensive federal, state and local legislation and regulation, 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;

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

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

•	changes in the costs to operate and maintain current production technology or to implement new information technology systems that impede our ability to complete such projects timely and effectively;

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

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

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

•	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;

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

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

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

•	political pressures or regulatory practices that could constrain or place additional cost burdens on our energy supply sources, such as campaigns to halt coal-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities;

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

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

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

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Avista Utilities – an operating division of Avista Corp. (not a subsidiary) that comprises our regulated utility operations in the Pacific Northwest. Avista Utilities generates, transmits and distributes electricity and distributes natural gas, serving electric and natural gas customers in eastern Washington and northern Idaho and natural gas customers in parts of Oregon. We also supply electricity to a small number of customers in Montana, most of whom are our employees who operate our 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 our load-serving obligation.

•	AEL&P - a utility providing electric services in Juneau, Alaska and the primary operating subsidiary of AERC. We acquired AERC on July 1, 2014, and as of that date, AERC became a wholly-owned subsidiary of Avista Corp. See "Note 4 of the Notes to Consolidated Financial Statements" for further discussion regarding this acquisition.

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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 applying an upstream regulation calculation to median natural water flow information. 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.

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

•	a 15 percent interest in a twin-unit, coal-fired boiler generating facility, Colstrip 3 & 4, located in southeastern Montana,

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

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

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

•	two small natural gas-fired generating facilities (Boulder Park 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)	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.

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•	We have adequate resources between our owned and contractually controlled generation, combined with conservation and market purchases, to meet customer needs through 2020.

•	565 MW of additional generation capacity is required for the period 2020 through 2034.

•	We expect to meet or exceed the renewable energy requirements of the Washington state Energy Independence Act through the 20-year IRP time frame with a combination of qualifying hydroelectric upgrades, the 30-year PPA with Palouse Wind, the Kettle Falls GS and selective REC purchases.

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Load growth is expected to be approximately 0.6 percent, a decline from the growth of 1.0 percent forecasted in 2013. This delays the need for a new natural gas-fired resource by one year. The decrease in expected load growth is primarily due to energy efficiency programs (using less energy to perform activities) over the next 20 years and the load impacts of increased prices. See "Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations – Forecasted Customer and Load Growth and Economic Conditions and Utility Load Growth" for further discussion regarding utility customer growth, load growth, and the general economic conditions in our service territory. The estimates of future load growth in the IRP and at "Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations – Forecasted Customer and Load Growth and Economic Conditions and Utility Load Growth" differ slightly due to the timing of when the two estimates were prepared and due to the time period that each estimate is focused on.

•	Colstrip remains a cost effective and reliable source of power to meet future customer needs.

•	Energy efficiency offsets more than half of projected load growth through the 20-year IRP time frame.

•	Demand response (temporarily reducing the demand for energy) was eliminated from the Preferred Resource Strategy due to higher estimated costs.

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•	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 have sufficient natural gas transportation resources well into the future with resource needs not occurring during the 20 year planning horizon in Washington, Idaho, or Oregon.

•	Natural gas commodity prices continue to be relatively stable due to robust North American supplies led by shale gas development; and

•	As forecasted demand is relatively flat, we will monitor actual demand for signs of increased growth which could accelerate resource needs.

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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 historic indicate warmer than average temperatures). In 2015, we switched to a rolling 20-year average for calculating cooling degree days, whereas in prior years we used a 30-year rolling average.

(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 historic indicate warmer than average temperatures). In 2015, we switched to a rolling 20-year average for calculating heating degree days, whereas in prior years we used a 30-year rolling average.

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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).

(2)	In 2015, we switched to a rolling 20-year average for calculating heating degree days, whereas in prior years we used a 30-year rolling average.

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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.

•	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.

•	our obligation to serve our retail customers at rates set through the regulatory process - 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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•	severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, snow and ice storms, that can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies and support services;

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

•	unplanned outages at generating plants,

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•	fuel cost and availability, including delivery constraints,

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

•	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, and

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

•	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,

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•	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, and

•	require construction of specific types of generation plants at higher cost.

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

•	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, and

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•	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 our Company.

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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, 2015.

(3)	There are four units at the Nine Mile plant; however, Units 1 and 2 are not operating due to a mechanical failure. A project is underway to replace these units and restore capability. The present capability disclosed above represents the capability of the two operating units, which have a nameplate rating of 18 MW combined.

(4)

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.

(5)	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.

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(6)	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, 2015.

(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 the Company's outstanding long-term debt and committed line of credit agreements (see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Level Summary and 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”),

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certain requirements under the OPUC approval of the AERC acquisition. The OPUC does not permit one-time or special dividends from AERC to Avista Corp. and does not permit Avista Utilities' total equity to total capitalization to be less than 40 percent, without approval from the OPUC. However, the OPUC approval does allow for regular distributions of AERC earnings to Avista Corp. as long as AERC remains sufficiently capitalized and insured, and

•	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).

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(1)	The total assets at year-end for the years 2013 to 2011 exclude the total assets associated with Ecova of $339.6 million, $322.7 million and $292.9 million, respectively.

(2)	The total assets and total long-term debt and capital leases for 2014 through 2011 were adjusted due to the adoption of ASU No. 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." See "Note 2 of the Notes to Consolidated Financial Statements" for further discussion of the adoption of this ASU.

(3)	See Exhibit 12 for computations.

(1)	The results for the year ended December 31, 2014 include the net gain on sale of Ecova of $69.7 million.

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•	weather conditions (temperatures, precipitation levels and wind patterns) which affect energy demand and electric generation, including the effect of precipitation and temperature on hydroelectric resources, the effect of wind patterns on wind-generated power, weather-sensitive customer demand, and similar impacts on supply and demand in the wholesale energy markets,

•	regulatory decisions, allowing our utility to recover costs, including purchased power and fuel costs, on a timely basis, and to earn a reasonable return on investment,

•	the price of natural gas in the wholesale market, including the effect on the price of fuel for generation, and

•	the price of electricity in the wholesale market, including the effects of weather conditions, natural gas prices and other factors affecting supply and demand.

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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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•	a decrease in power supply costs of approximately $24.0 million caused by the continuing decline in the price of natural gas used to run our natural gas-fired generation and lower contract costs associated with a new PPA from Chelan PUD,

•	updated information related to federal tax adjustments and state allocations,

•	the delay in the expected completion date of the Nine Mile hydroelectric generation project upgrade from late 2015 to late 2016, and

•	a delay of the start date to begin amortization of existing electric meters from 2016 to a future year, associated with our proposed AMI project.

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•	the discontinuation of the after-the-fact earnings test (provision for earnings sharing) that was originally agreed to as part of the settlement of our 2012 electric and natural gas general rate cases, and

•	the implementation of electric and natural gas Fixed Cost Adjustment mechanisms, as discussed below.

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

•	the level and availability of hydroelectric generation,

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

•	retail loads.

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•	If we have a decoupling rebate balance for the prior year and earn in excess of a 7.32 percent ROR, the rebate to customers would be increased by 50 percent of the earnings in excess of the 7.32 percent ROR.

•	If we have a decoupling rebate balance for the prior year and earn a 7.32 percent ROR or less, only the base amount of the rebate to customers would be made.

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If we have a decoupling surcharge balance for the prior year and earn in excess of a 7.32 percent ROR, the surcharge to customers would be reduced by 50 percent of the earnings in excess of the 7.32 percent ROR (or eliminated). If 50 percent of the earnings in excess of the 7.32 percent ROR exceeds the decoupling surcharge balance, the dollar amount that exceeds the surcharge balance would create a rebate balance for customers.

•	If we have a decoupling surcharge balance for the prior year and earn a 7.32 percent ROR or less, the base amount of the surcharge to customers would be made.

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a $5.7 million increase in retail electric revenues due to an increase in revenue per MWh (increased revenues $21.0 million), partially offset by a decrease in total MWhs sold (decreased revenues $15.3 million). The increase in revenue per MWh was primarily due to a general rate increase in Washington. The decrease in total MWhs sold was primarily the result of weather that was significantly warmer than normal and warmer than the prior year, which decreased the electric heating load in the first quarter. Compared to 2014, residential electric use per customer decreased 5 percent and commercial use per customer decreased 2 percent. Heating degree days in Spokane were 14 percent below normal and 10 percent below 2014. The impact from reduced heating loads was partially offset by increased cooling loads in the summer. Year-to-date cooling degree days were 141 percent above normal and 28 percent above the prior year.

•	a $10.9 million decrease in wholesale electric revenues due to a decrease in sales volumes (decreased revenues $21.9 million), partially offset by an increase in sales prices (increased revenues $11.0 million). The fluctuation in volumes and prices was primarily the result of our optimization activities.

•	a $0.9 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 2015, $50.0 million of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For 2014, $67.4 million of these sales were made to our natural gas operations.

•	a $4.7 million increase in electric revenue due to decoupling, which reflected decreased heating loads in the first and fourth quarters, partially offset by increased cooling loads in the second and third quarters.

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a $1.9 million decrease in the provision for earnings sharing, primarily due to a decrease of $5.3 million for our Idaho electric operations, partially offset by an increase of $3.4 million for our Washington electric operations. In 2014, we recorded a provision for earnings sharing of $7.5 million for Idaho electric customers with $5.6 million representing our estimate for 2014 and $1.9 million representing an adjustment of our 2013 estimate.

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a $16.4 million decrease in retail natural gas revenues due to a decrease in volumes (decreased revenues $23.6 million), partially offset by higher retail rates (increased revenues $7.2 million). Higher retail rates were due to PGAs implemented in November 2014, which passed through higher costs of natural gas, and general rate cases. This was partially offset by PGA rate decreases implemented in November 2015, which passed through lower costs. We sold less retail natural gas in 2015 as compared to 2014 primarily due to weather that was warmer than normal and warmer than the prior year. Compared to 2014, residential use per customer decreased 9 percent and commercial use per customer decreased 9 percent. Heating degree days in Spokane were 14 percent below historical average for 2015, and 10 percent below 2014. Heating degree days in Medford were 15 percent below historical average for 2015, and 4 percent above 2014.

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a $23.9 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $90.4 million), partially offset by an increase in volumes (increased revenues $66.5 million). In 2015, $57.0 million of these sales were made to our electric generation operations and are included as intracompany revenues and resource costs. In 2014, $74.7 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 $6.0 million increase for natural gas decoupling revenues due primarily to significantly warmer than normal weather and the impact on heating loads.

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•	a $18.3 million decrease in power purchased due to a decrease in the volume of power purchases (decreased costs $23.6 million), partially offset by an increase in wholesale prices (increased costs $5.3 million). The fluctuation in volumes and prices was primarily the result of our overall optimization activities.

•	a $14.2 million increase from amortizations and deferrals of power costs due to the following.

•	increases to expense in 2015:

•	a $5.8 million surcharge to customers of previously deferred power costs in Idaho through the PCA.

•	an $11.3 million deferral in Washington and a $2.0 million deferral in Idaho for probable future benefit to customers due to actual power supply costs being below the amount included in base retail rates.

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•	a $2.0 million deferral in Washington of RECs for probable future benefit to customers.

•	decreases to expense in 2015:

•	an $8.0 million refund to Washington customers through an ERM rebate.

•	a $5.4 million refund to Washington customers through a REC rebate.

•	a $4.4 million increase in fuel for generation primarily due to an increase in thermal generation (due in part to decreased hydroelectric generation), partially offset by a decrease in natural gas fuel prices.

•	a $10.0 million decrease in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.

•	a $7.7 million decrease in other electric resource costs primarily due to the benefit from a capacity contract of Spokane Energy, which was mostly deferred for probable future benefit to customers through the ERM and PCA.

•	a $66.1 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $138.3 million), partially offset by an increase in total therms purchased (increased costs $72.2 million). Total therms purchased increased due to an increase in wholesale sales, partially offset by a decrease in retail sales.

•	a $21.8 million increase from amortizations and deferrals of natural gas costs. This reflects lower natural gas prices and the deferral of lower costs for future rebate to customers.

•	a $35.1 million decrease in intracompany resource costs (which has the effect of increasing overall net resource costs).

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a $14.8 million increase in retail electric revenue primarily due to general rate increases and a change in revenue mix (which increased revenue by $25.2 million), partially offset by a decrease in volumes (which decreased revenue by $10.4 million). The decrease in residential volumes was primarily due to warmer weather in the fourth quarter, partially offset by customer growth. The decrease in total MWhs sold to industrial customers was primarily due to the expiration and replacement of a contract with one of our largest industrial customers in Idaho, effective July 1, 2013. The change resulting from this new contract did not impact gross margin because any change in revenues and expenses was tracked through the PCA in Idaho at 100 percent until such time as the contract was included in the Company’s base rates,

•	a $10.6 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $17.6 million), partially offset by a decrease in sales volumes (decreased revenues $7.0 million). The fluctuation in volumes and prices was primarily the result of our optimization activities during the period,

•	a decrease of $42.9 million in sales of natural gas fuel as part of thermal generation resource optimization activities. For 2014, $67.4 million of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For 2013, $102.4 million of these sales were made to our natural gas operations,

•	an $8.6 million decrease in other electric revenues primarily due to the receipt of $11.7 million of revenue from the Bonneville Power Administration in 2013 for past use of our electric transmission system, and

•	a $5.5 million increase in the provision for earnings sharing for Idaho electric customers primarily due to the 2014 provision for earnings sharing including a $1.9 million adjustment of our 2013 estimate.

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a $1.3 million decrease in retail natural gas revenues due to a decrease in volumes (decreased revenues by $20.0 million), partially offset by general rate increases and higher PGA rates, which passed through costs of natural gas (increased revenues by $18.7 million). We had decreased volumes primarily due to weather that was warmer than normal and warmer than the prior year during the fourth quarter,

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an increase of $33.5 million in wholesale natural gas revenues due to an increase in prices (increased revenues by $24.8 million) and an increase in volumes (increased revenues by $8.7 million). In 2014, $74.7 million of wholesale sales were made to our electric generation operations and are included as intracompany revenues and resource costs. In 2013, $49.5 million of these sales were made to our electric generation operations, and

•	a $0.2 million reduction to revenue in 2014 for the provision for earnings sharing for Idaho natural gas customers, compared to a reduction to revenue of $0.4 million in 2013.

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•	a decrease of $5.0 million in power purchased due to a decrease in the volume of power purchases, partially offset by an increase in wholesale prices. The fluctuation in volumes and prices was primarily the result of our overall optimization activities during the year. The decrease in volumes purchased was also due to increased hydroelectric generation,

•	a decrease to 2014 electric resource costs of $6.5 million for amortizations and deferrals of power costs, compared to a decrease of $14.2 million for 2013.

•	increases to expense in 2014:

•	a $1.6 million deferral in Idaho and a $4.2 million deferral in Washington for probable future benefit to customers due to actual power supply costs being below the amount included in retail rates.

•	decreases to expense in 2014:

•	a $2.3 million refund to Idaho customers of previously deferred power costs through the PCA rebate.

•	an $8.5 million refund to Washington customers through an ERM rebate.

•	a $1.6 million deferral of RECs for probable future benefit to Washington customers.

•	a decrease of $17.2 million for fuel for generation primarily due to a decrease in natural gas generation,

•	a decrease of $39.6 million in other fuel costs due to the resource optimization process, and

•	an increase of $44.6 million in natural gas purchased due to an increase in the price of natural gas and a slight increase in total therms purchased. Total therms purchased increased due to an increase in wholesale sales as part of the natural gas procurement and resource optimization process, mostly offset by a decrease in retail sales.

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•	$2.3 million (net of tax) of corporate costs, including costs associated with exploring strategic opportunities, compared to $2.4 million in 2014,

•	net losses on investments (net of tax) of $0.4 million for 2015, compared to net gains of $0.2 million for 2014,

•	net income at METALfx of $1.5 million for 2015, compared to net income of $0.9 million for 2014.

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Regulatory accounting, which requires that certain costs and/or obligations be reflected as deferred charges on our Consolidated Balance Sheets and are not reflected in our Consolidated Statements of Income until the period during which matching revenues are recognized. We also have decoupling revenue deferrals. As opposed to cost deferrals which are not recognized in the Consolidated Statements of Income until they are included in rates, decoupling revenue is 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 to certain limitations, and a regulatory asset/liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative regulatory revenue program, like decoupling, the revenue must be collected from customers within 24 months of the deferral to qualify for recognition in the current period Consolidated Statement of Income. Any amounts included in the Company's decoupling program that won't be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. This could ultimately result in more decoupling revenue being collected from customers over the life of the decoupling program than what is deferred and recognized in the current period financial statements. We make estimates regarding the amount of revenue that will be collected with 24 months of deferral. We also make the assumption that there are regulatory precedents for many of our regulatory items and that we will be allowed recovery of these costs via retail rates in future periods. If we were no longer allowed to apply regulatory accounting or no longer allowed recovery of these costs, we could be required to recognize significant write-offs of regulatory assets and liabilities in the Consolidated Statements of Income. See "Notes 1 and 20 of the Notes to Consolidated Financial Statements" for further discussion of our regulatory accounting policy.

•

Utility energy commodity derivative asset and liability accounting, where we estimate the fair value of outstanding commodity derivatives and we 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. This accounting treatment is supported by accounting orders issued by the UTC and IPUC. If we were no longer allowed to apply regulatory accounting or no longer allowed recovery of these costs, we could be required to recognize significant changes in fair value of these energy commodity derivatives on a regular basis in the Consolidated Statements of Income, which could lead to significant fluctuations in net income. See "Notes 1 and 6 of the Notes to Consolidated Financial Statements" for further discussion of our energy derivative accounting policy.

•

Interest rate derivative asset and liability accounting, where we estimate the fair value of outstanding interest rate swaps, and U.S. Treasury lock agreements and offset the derivative asset or liability with a regulatory asset or liability. This is similar to the treatment of energy commodity derivatives described above. Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt. If we no longer applied regulatory accounting or were no longer allowed recovery of these costs, we could be required to recognize significant changes in fair value of these interest rate

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•	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 for 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. If the loss recognition criteria are met, liabilities are accrued or assets are reduced. However, no assurance can be given to the ultimate outcome of any particular contingency. See "Notes 1 and 19 of the Notes to Consolidated Financial Statements" for further discussion of our commitments and contingencies.

•

Discontinued operations, related to the accounting and financial statement presentation for Ecova following its disposition in 2014. In accordance with GAAP, this transaction caused Ecova to be accounted for as a discontinued operation. Ecova's revenues and expenses are included in the Consolidated Statements of Income in discontinued operations (as a single line item, net of tax). The gain, net of tax, recognized on the sale of Ecova is also included in discontinued operations. All tables throughout the Notes to Consolidated Financial Statements that present Consolidated Statements of Income information were revised to only include amounts from continuing operations. In addition, we are presenting earnings per share calculations for continuing and discontinued operations.

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

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

•	the actual return on pension plan assets,

•	expected return on pension plan assets,

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•	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.

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

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

•	low availability of 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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•	issuance and sale of $100.0 million of Avista Corp. first mortgage bonds in December 2015,

•	cash settlement of interest rate swaps in conjunction with the execution of the purchase agreement for the Avista Corp. first mortgage bonds which resulted in the payment of $9.3 million,

•	payment of $2.9 million for the redemption and maturity of long-term debt,

•	cash dividends paid increased to $82.4 million (or $1.32 per share) for 2015 from $78.3 million (or $1.27 per share) for 2014,

•	issuance of $1.6 million of common stock (net of issuance costs), and

•	repurchase of $2.9 million of our common stock.

•	issuance of $150.0 million of long-term debt ($60.0 million of Avista Corp. first mortgage bonds, $75.0 million of AEL&P first mortgage bonds and a $15.0 million AERC unsecured note representing a term loan),

•	a decrease of $66.0 million in short-term borrowings on Avista Corp.’s committed line of credit,

•	a decrease of $46.0 million on Ecova's committed line of credit with $6.0 million in payments throughout the year and $40.0 million related to the close of the Ecova sale,

•	payment of $40.0 million for the redemption and maturity of long-term debt (primarily related to AEL&P paying off its existing debt),

•	cash payments of $54.2 million to noncontrolling interests and $20.9 million to stock option holders and redeemable noncontrolling interests of Ecova related to the Ecova sale in 2014,

•	issuance of $4.1 million of common stock (net of issuance costs) excluding issuances related to the acquisition of AERC. We issued $150.1 million of common stock to AERC shareholders, and this is reflected as a non-cash financing activity,

•	repurchase of $79.9 million of our common stock during 2014 using the proceeds from our sale of Ecova, and

•	a $16.2 million increase in cash related to the fluctuation in the balance of customer fund obligations at Ecova.

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

•	an equal principal amount of retired first mortgage bonds at each entity which have not previously been made the basis of any application under the Mortgages, 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, 2015.

(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 adjustment mechanisms.

(3)	Includes the interest component of the lease obligation.

(4)	Represents operational 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. On March 30, 2015, Avista Corp. provided a cancellation notice, effective May 31, 2015, to one of its information technology service providers. New contracts were entered into to replace the cancelled contract. The replacement contracts result in similar amount of expense each year; however, this resulted in a significant decrease in future information technology contractual commitments because the new contracts do not have minimum committed spending in them and are primarily time and materials contracts.

(6)	Represents our estimated cash contributions to pension plans and other postretirement benefit plans through 2020. We cannot reasonably estimate pension plan contributions beyond 2020 at this time and have excluded them from the table above.

(7)	Primarily relates to long-term debt and capital lease maturities and the related interest. AERC 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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(8)	Primarily relates to operating lease commitments and a commitment to fund a limited liability company in exchange for equity ownership, made by a subsidiary of Avista Capital.

•	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.

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•	assumptions relating to weather and economic and competitive conditions,

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

•	internal business plans,

•	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; and

•	require construction of specific types of generation plants at higher cost.

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•	facilitates internal and external communications regarding climate change issues,

•	analyzes policy effects, anticipates opportunities and evaluates strategies for Avista Corp., and

•	develops recommendations on climate related policy positions and action plans.

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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, 2015 and December 31, 2014 reflects the offsetting of $34.0 million and $28.9 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,

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•	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 delivery of either electricity or natural gas and financial transactions represent derivative instruments with no physical delivery, such as futures, swaps, options, or forward contracts.

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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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•	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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•	the number of customers,

•	current rates,

•	meter reading dates,

•	actual native load for electricity,

•	actual throughput for natural gas, and

•	electric line losses and natural gas system losses.

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(1)

During the second quarter of 2014, the Company received $15.0 million in gross proceeds related to the settlement of its California wholesale power markets litigation. The gross proceeds effectively settled all outstanding receivables and payables at Avista Energy (which had been fully reserved against since 2001). As a result of the settlement, the Company reversed $15.0 million of the allowance, which was recorded as a reduction to non-utility other operating expenses on the Consolidated Statements of Income, and the remainder of the receivables, payables and allowance of $24.5 million were removed from the Consolidated Balance Sheets (and had no effect on net income).

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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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(a)	These amounts were included as part of net income from discontinued operations for all periods presented (see Note 5 for additional details).

(b)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 10 for additional details).

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(1)	During the second quarter of 2015, the Company recorded a reduction to goodwill of approximately $0.3 million due to income tax related adjustments. After consideration of the goodwill adjustment in the second quarter of 2015, the transaction resulted in a total amount of goodwill of $52.4 million. The goodwill associated with this acquisition is not deductible for tax purposes.

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(1)	AERC was acquired on July 1, 2014; therefore, all the revenues and net income for the second half of 2014 and all of 2015 are actual amounts that are included in Avista Corp.'s overall results. All revenue and net income amounts prior to July 1, 2014 are supplemental pro forma amounts and are excluded from Avista Corp.'s overall results.

(2)

This adjustment is to treat all transaction costs as if they occurred on January 1, 2013 and to remove them from the periods in which they actually occurred. The transaction costs were expensed and presented in the Consolidated Statements of Income in other operating expenses within utility operating expenses. Since the start of the transaction through December 31, 2015, Avista Corp. has expensed $3.0 million (pre-tax) in total transaction fees. In addition to the amounts expensed, through December 31, 2015, Avista Corp. has included $0.4 million in fees associated with the issuance of common stock for the transaction as a reduction to common stock. These fees do not impact the supplemental pro forma information above.

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(1)	Of this total amount, approximately $16.8 million was held in escrow for 15 months from the transaction closing date for any indemnity claims and an additional $1.0 million was held in escrow pending resolution of adjustments to working capital. Both of these escrow accounts were resolved during 2015.

(2)	Of the total gross proceeds and total net proceeds received, approximately $229.9 million and $205.4 million was received in 2014, respectively, with the remainder being received in 2015.

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(1)	This represents the gross gain recorded to discontinued operations. The total gain net of taxes and transactions expenses is $74.8 million, of which $69.7 million was recognized during 2014.

(2)

Avista Corp.'s portion of the total transaction expenses was $9.1 million (including amounts which were withheld from the transaction net proceeds) and this was recognized during the second and third quarters of 2014 and the third and fourth quarters of 2015. All transaction expenses paid on the Ecova sale (including Avista Corp.'s portion and the portion attributable to the minority interest holders of Ecova) were $11.1 million, of which $5.5 million was withheld from the net proceeds and the remainder was paid during the second and third quarters of 2014. The transaction expenses were for legal, accounting and other consulting fees, and the accelerated employee benefits related to employee stock options which were settled in accordance with the Ecova equity plan.

(3)	The tax benefit during 2015 primarily resulted from the reversal of a valuation allowance against net operating losses at Ecova because the net operating losses were deemed realizable under the current tax code.

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(1)	Physical transactions represent commodity transactions in which Avista Utilities will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of gain or loss but with no physical delivery of the commodity, such as futures, swaps, options, or forward contracts.

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•	relating directly to it,

•	caused by market price changes, and

•	relating to other market participants that have a direct or indirect relationship with such counterparty.

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(1)	Included in other property and investments-net on the Consolidated Balance Sheets. Accumulated depreciation was $10.6 million as of December 31, 2015 and $10.8 million as of December 31, 2014 for the other businesses. The decrease in accumulated depreciation for the other businesses was due to the sale of certain assets which were nearing the end of their useful lives.

•	restore coal ash containment ponds at Colstrip,

•	cap a landfill at the Kettle Falls Plant,

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

•	dispose of PCBs in certain transformers.

•	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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•	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.

(2)	This category includes private equity funds that invest primarily in U.S. companies.

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(1)

Effective December 31, 2015, the Company adopted ASU 2015-17 “Income Taxes (Topic 740) - Balance Sheet Classification of Deferred Taxes,” which requires entities to present DTAs and DTLs as noncurrent in a classified balance sheet versus the previous accounting guidance which required separate presentation of current and noncurrent DTAs and DTLs. The Company has elected to adopt this standard on a prospective basis; therefore, the Consolidated Balance Sheet as of December 31, 2014 has not been adjusted to match the current period presentation. See "Note 2 of the Notes to Consolidated Financial Statements" for further discussion of this ASU.

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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 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 December 2015, Avista Corp. issued $100.0 million of first mortgage bonds to five institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.37 percent and mature in 2045. The total net proceeds from the sale of the new bonds were used to repay a portion of the borrowings outstanding under the Company’s $400.0 million committed line of credit and for general corporate purposes.

(3)	Upon settlement of interest rate swaps, these are recorded as a regulatory asset or liability and included as part of long-term debt above. They are amortized as a component of interest expense over the life of the associated debt and included as a part of the Company's cost of debt calculation for ratemaking purposes.

(1)	The capital lease obligation amount is equal to the amount of AIDEA's revenue bonds outstanding.

(2)	These amounts are included in utility plant in service on the Consolidated Balance Sheet.

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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 trading securities and are included in other property and investments-net 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.

•	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.

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certain requirements under the Public Utility Commission of Oregon (OPUC) approval of the AERC acquisition. As of July 1, 2015 (one year following the acquisition date), the OPUC does not permit one-time or special dividends from AERC to Avista Corp. and does not permit Avista Utilities' total equity to total capitalization to be less than 40 percent, without approval from the OPUC. However, the OPUC approval does allow for regular distributions of AERC earnings to Avista Corp. as long as AERC remains sufficiently capitalized and insured.

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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.

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(5)

The UTC and the IPUC issued accounting orders authorizing Avista Corp. to offset 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 settlement. The orders provide for Avista Corp. to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases.

(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)

For interest rate swap agreements, each period Avista Utilities records all mark-to-market gains and losses as assets and liabilities and records offsetting regulatory assets and liabilities, such that there is no income statement impact. This is similar to the treatment of energy commodity derivatives described above. Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt.

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

(9)	Consists of a regulatory liability recorded for the cumulative retained earnings of Spokane Energy that the Company will flow through regulatory accounting mechanisms in future periods. During 2015, Spokane Energy was dissolved and the fixed rate electric capacity contract that was held at Spokane Energy was transferred to Avista Corp.

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

•	the level and availability of hydroelectric generation,

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

•	retail loads.

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(1)	Intersegment eliminations reported as operating revenues and resource costs represent intercompany purchases and sales of electric capacity and energy between Avista Utilities and Spokane Energy (included in other). Intersegment eliminations reported as interest expense and net income (loss) attributable to Avista Corp. shareholders represent intercompany interest.

(2)	Including interest expense to affiliated trusts.

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(3)	The capital expenditures for the other businesses are included as other capital expenditures on the Consolidated Statements of Cash Flows. The remainder of the balance included in other capital expenditures on the Consolidated Statements of Cash Flows for 2014 and 2013 are related to Ecova.

(4)

The total assets balances as of December 31, 2014 and December 31, 2013 were updated to reflect the adoption of FASB ASU No. 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" as of December 31, 2015, which resulted in the reclassification of long-term debt issuance costs from an asset to a reduction of long-term debt. See Note 2 of the Notes to Consolidated Financial Statements for further discussion of the adoption of this ASU.

(5)	The total assets as of December 31, 2013 exclude the total assets associated with Ecova of $339.6 million.

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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 12, 2016, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015.

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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 12, 2016, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015.

(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 12, 2016, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015; reference also being made to Schedules 13G, as amended, in 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).

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(b)	Security ownership of management:

•	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 12, 2016, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015.

(c)	Changes in control:

(d)	Securities authorized for issuance under equity compensation plans as of December 31, 2015:

(1)

Excludes unvested restricted shares and performance share awards granted under Avista Corp.’s Long Term Incentive Plan. At December 31, 2015, 106,091 Restricted Share awards were outstanding. Performance and market-based share awards may be paid out at zero shares at a minimum achievement level; 335,584 shares at target level; or 671,168 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 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 12, 2016, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015.

•	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 12, 2016, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015.

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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 James M. Kensok, David J. Meyer, Kelly O. Norwood, Jason R. Thackston, Dennis P. Vermillion and Roger D. Woodworth.

(6)	Applies to Marian M. Durkin, Karen S. Feltes, Scott L. Morris, and Mark T. Thies.

(7)	Applies to executive officers appointed after October 1, 2010. This applies to Kevin J. Christie, Ryan L. Krasselt, Ed D. Schlect and Heather L. Rosentrater.

(8)	Applies to executive officers appointed after February 4, 2011. This applies to Kevin J. Christie, Ryan L. Krasselt, Ed D. Schlect and Heather L. Rosentrater.