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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;

•	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 and operating costs and discretion over allowed return on investment;

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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 on wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities;

•	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;

•	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;

•	the potential effects of legislation or administrative rulemaking, 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;

•	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;

•	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;

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

•	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;

•	growth or decline of our customer base and the extent to which new uses for our services may materialize or existing uses may decline;

•	the ability to comply with the terms of the licenses for our hydroelectric generating facilities at cost-effective levels;

•	severe weather or natural disasters 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, avalanches or other incidents that may impair assets and may disrupt operations of any of our generation facilities, transmission and distribution systems or other operations;

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

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

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

•	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;

•	cyber attacks 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;

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

•	changes in the costs to implement new information technology systems and/or obstacles that impede our ability to complete such projects timely and effectively;

•	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;

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

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

•	deterioration in the creditworthiness of our customers;

•	potential decline in our credit ratings, with effects including impeded access to capital markets, higher interest costs, and restrictive covenants in our financing arrangements and wholesale energy contracts;

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

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

•	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;

•	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 technologies, possibly making some of the current technology obsolete;

•	changes in tax rates and/or policies;

•	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 that we recover interest costs through utility operations;

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•	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;

•	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;

•	compliance with extensive federal, state and local legislation and regulation, including numerous environmental, health, safety and other laws and regulations that affect our operations and costs;

•	our ability to fully collect the indemnification escrow amounts because of information that was covered under management's representations and warranties related to the Ecova sale which could be inaccurate or incomplete at the time of sale, or because of new information which could be identified subsequent to the sale date, and

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adverse impacts to our Alaska operations because a majority of the hydroelectric power generation for such operations is provided by a single facility that is subject to a long-term power purchase agreement; hence any issues that negatively affect this facility’s ability to generate or transmit power, the cost and ability to replace power in the event of an extended outage, any decrease in the demand for the power generated by this facility or any loss by our subsidiary of its contractual rights with respect thereto or other adverse effect thereon could negatively affect our Alaska operations' financial results.

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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 gas customers in eastern Washington and northern Idaho and gas customers in parts of Oregon. We also supply electricity to a small number of customers in Montana, most of whom are employees who operate our Noxon Rapids generating facility. Avista Utilities also engages in wholesale purchases and sales of electricity and natural gas.

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Alaska Electric Light and Power Company - the primary operating subsidiary of Alaska Energy and Resources Company (AERC), which provides electric services in the City and Borough of Juneau, Alaska. We completed our acquisition of AERC on July 1, 2014, and as of that date, AERC is 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 generation and transmission resources and fuel delivery (transport) capacity contracts.

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•	native load of 1,715 MW,

•	long-term wholesale obligations of 221 MW, and

•	short-term wholesale obligations of 287 MW.

•	company-owned or controlled electric generation of 1,667 MW,

•	long-term hydroelectric contracts with certain Public Utility Districts (PUDs) of 154 MW,

•	long-term thermal generation contract with Lancaster Plant of 280 MW,

•	other long-term wholesale contracts of 191 MW, and

•	short-term wholesale purchases of 302 MW.

(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

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

•	a 15 percent interest in a twin-unit, coal-fired boiler generating facility, the Colstrip 3 & 4 Generating Project (Colstrip) 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 currently 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 (decline in 2016 is due to changes in contracts with PUDs).

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(3)

Includes our long-term contract with the owner of the Lancaster Plant. 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. We generally dispatch thermal resources when operating costs are lower than short-term wholesale market prices. The decreases in availability during 2016 and 2018 at these facilities are related to scheduled maintenance at Colstrip.

(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.

•	In our IRP in 2011, we had certain recommendations for new renewable resources. These have been met with a 30-year PPA with Palouse Wind and the Kettle Falls GS being qualified as a renewable energy resource under the Washington state Energy Independence Act.

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Load growth is expected to be approximately 1 percent, a decline from the growth of 1.6 percent forecasted in 2011. 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. See "Item 7. Management Discussion and Analysis – 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.

•	Demand response (temporarily reducing the demand for energy) is included in the Preferred Resource Strategy for the first time and could provide 19 MW of peak energy reduction in the 2022 to 2027 time frame.

•	575 MW of additional natural gas-fired generation facilities are required between 2020 and 2033.

•	Transmission upgrades will be needed to deliver the energy from new generation resources to the distribution lines serving customers. We will continue to participate in regional efforts to expand the region’s transmission system.

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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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(1)	This provision for earnings sharing is specifically related to the Idaho general rate case which was settled in March 2013. See "Item 7. Management's Discussion and Analysis - Idaho General Rate Cases" for further discussion of this provision.

(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).

(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).

(4)	The 30-year average heating and cooling degree days fluctuated in 2013 due to a change in our methodology for calculating the amount. In 2013, we have switched to a rolling 30-year average whereas in prior years we only received updated 30-year average data on a periodic basis.

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(1)	This provision for earnings sharing is specifically related to the Idaho general rate case which was settled in March 2013. See "Item 7. Management's Discussion and Analysis - Idaho General Rate Cases" for further discussion of this provision.

(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).

(3)	The 30-year average heating degree days fluctuated in 2013 due to a change in our methodology for calculating the amount. In 2013, we have switched to a rolling 30-year average whereas in prior years we only received updated 30-year average data on a periodic basis.

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•	certain retail electricity and natural gas sales,

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•	the cost of natural gas supply,

•	the cost of power supply, and

•	damage to facilities.

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•	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.

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•	blackouts or disruptions to distribution, transmission or transportation systems,

•	unplanned outages at generating plants,

•	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, and

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

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•	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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(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, 2014.

(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, 2014.

(3)	AEL&P does not own this generating facility but has a power purchase agreement 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 - AEL&P Overview."

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

•	the success of our business strategies, and

•	general economic and competitive conditions.

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

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

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

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certain requirements under the OPUC approval of the AERC acquisition. After the initial year, 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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