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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.

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weather conditions (temperatures, precipitation levels and wind patterns), including those from long-term climate change, 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 to which we recover interest costs through retail rates collected from customers;

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

•	deterioration in the creditworthiness of our customers;

•	the outcome of legal proceedings and other contingencies;

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

•	declining energy demand related to customer energy efficiency and/or conservation measures;

•	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, financing costs and commodity costs and regulatory discretion over authorized return on investment;

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

•	the effect on any or all of the foregoing, resulting from changes in general economic or political factors;

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

•	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 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 electric and natural gas distribution systems or other operations and may require us to purchase replacement power;

•	wildfires, including those caused by our transmission or electric distribution systems that may result in public injuries or property damage;

•	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 or regional 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;

•	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 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;

•	adverse impacts to our Alaska operations 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 extensive cost of replacement power (diesel);

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

•	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;

•	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;

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

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

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

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

•	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, loss 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;

•	non-regulated activities may increase earnings volatility;

•	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 distribution systems through accelerated adoption of distributed generation or electric-powered transportation or on our energy supply sources, such as campaigns to halt coal-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities;

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

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

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

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

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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 that is a wholly-owned subsidiary 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 dam 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 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)	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.

•	We will 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 will 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 will 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) employed by our customers over the next 20 years and the load impacts of increased prices. See "Item 7. Management Discussion and Analysis – 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 – 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 will remain a cost effective and reliable source of power to meet future customer needs.

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

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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 will 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 will continue to be relatively stable due to robust North American supplies led by shale gas development.

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Future customer growth in our service territory will increase slightly compared to the 2014 IRP. There will be increasing interest from customers to utilize natural gas due to its abundant supply and subsequent low cost. We anticipate that increased demand in the region will primarily come from power generation as natural gas is increasingly being used to back up solar and wind technology, as well as replace retired coal plants. There is also potential for increased usage in other markets, such as transportation and as an industrial feedstock.

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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 Asian and European markets. This could alter the price of natural gas and/or transportation, constrain existing pipeline networks, stimulate development of new pipeline resources, and change flows of natural gas across North America.

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(1)	There has been a trending decline in use per customer during the three-year period primarily due to weather fluctuations but also due in part to energy efficiency measures adopted by customers.

(2)

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.

(3)

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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(1)	Normal hydroelectric generation is defined as the energy output of the plant during a year with average inflows to the reservoir.

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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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•	Salix is a wholly-owned subsidiary of Avista Capital that explores markets that could be served with LNG.

•	Equity investments are primarily in an emerging technology venture capital fund.

•	Equity investments are primarily in emerging technology venture capital funds and companies, including an investment in a technology company that delivers scalable smart grid solutions to global partners and customers, and a predictive data science company.

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

•	Notes receivable and other assets are primarily long-term notes receivable made to a company focused on spurring economic development throughout Washington State.

•	AM&D doing business as METALfx performs custom sheet metal fabrication of electronic enclosures, parts and systems for the computer, construction, telecom, renewable energy and medical industries. The asset balance above excludes an intercompany loan from METALfx to Avista Corp. The loan balance was $4.0 million as of December 31, 2016 and $1.0 million as of December 31, 2015.

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

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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

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

•	severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, snow and ice storms, which can 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,

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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,

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

•	increase the cost of distributing natural gas to customers.

•	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,

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•	market or other conditions may adversely affect our operations or require changes to our business strategy, which could result in a non-cash goodwill impairment charge that would reduce assets and reduce our 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 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, 2016.

(3)	The project to replace Units 1 and 2 was completed during 2016. The present capability shown is the maximum plant generation we have seen given the water we have had available, because we have not yet had peak water conditions since Units 1 and 2 went into service. As conditions change, we will test plant capability and revise this number accordingly.

(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.

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(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.

(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, 2016.

(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 - 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”),

•	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 40 percent common equity (inclusive of short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC, 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 and 2012 exclude the total assets associated with Ecova of $339.6 million and $322.7 million, respectively.

(2)	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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