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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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(1)	The total assets at year-end for the years 2013 to 2010 exclude the total assets associated with Ecova of $339.6 million, $322.7 million, $292.9 million and $221.1 million, respectively.

(2)	See Exhibit 12 for computations.

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

•	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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•	Avista Corp. issued 4,501,441 shares of common stock for a total fair value of $150.1 million to acquire AERC.

•	In September 2014, AEL&P issued $75.0 million of 4.54 percent first mortgage bonds due in 2044 to two institutional investors in a private placement transaction. The proceeds from the AEL&P bonds were used to repay approximately $38.0 million of existing AEL&P debt, with the remainder of the proceeds and cash on-hand being paid as a cash dividend of $50.0 million to Avista Corp.

•	In December 2014, AERC entered into a 3.85 percent $15.0 million term loan agreement which matures in December 2019. The proceeds from this term loan were paid as a cash dividend to Avista Corp.

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•	seek recovery of operating costs and capital investments, and

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

(1)

The new retail rates that became effective on January 1, 2014 were temporary rates, and on January 1, 2015, electric and natural gas base rates were scheduled to revert back to 2013 levels absent any intervening action from the UTC. The original settlement agreement had a provision that we would not file a general rate case in Washington seeking new rates to take effect before January 1, 2015. In November 2014, the UTC approved a settlement agreement to our Washington general rate cases which were originally filed in February 2014 with rates effective on January 1, 2015 (see further discussion below).

(2)	In its Order, the UTC found that much of the approved base rate increase was justified by the planned capital expenditures necessary to upgrade and maintain our utility facilities. If these capital projects are not completed to a

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•	If we have a decoupling rebate balance for the prior year and earn in excess of a 7.32 percent rate of return (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.

•	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 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.

•	the ongoing and multi-year redevelopment of the Little Falls hydroelectric plant on the Spokane River,

•	the continuing rehabilitation of the Nine Mile hydroelectric plant on the Spokane River,

•	information technology upgrades that include the replacement of our customer information and work management systems (which were implemented in February 2015),

•	the ongoing project to systematically replace portions of Aldyl-A natural gas distribution pipe, and

•	technology investments for deploying Advanced Metering Infrastructure in Washington, including installation of advanced meters, beginning in 2016.

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•	the delay of the beginning of the amortization of the 2013 previously deferred operations and maintenance costs pertaining to the Colstrip and Coyote Springs 2 thermal generating facilities from 2015 to 2016, and

•	deferred accounting, for later review and recovery, of the majority of the costs associated with Project Compass, which was implemented in February 2015.

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(1)	As it relates to the 2012 Oregon PGA, we requested that the PGA be implemented in two steps. The first step, implemented on November 1, 2012, was a decrease of 7.5 percent. The second step was an additional decrease of 0.8 percent, effective on January 1, 2013, to provide customers the net savings related to our purchase of the Klamath Falls Lateral transmission pipeline.

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

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•	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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Utility operating revenues, which are generally recorded when service is rendered or energy is delivered to customers. Each month-end we estimate the amount of energy delivered to customers since the date of the last meter reading and a corresponding unbilled revenue amount is estimated and recorded. The critical estimates and assumptions in this calculation include a daily estimated allocation between billed and unbilled revenues for that day's energy usage based on our meter reading schedule and billing cycle day schedule, estimated adjustments due to variances in the meter reading schedule and estimates of electric line losses and natural gas system losses due to leakage. Changes to any one of these assumptions and estimates can result in material differences in the amount of unbilled revenue. See "Note 1 of the Notes to Consolidated Financial Statements" for further discussion of our utility operating revenue policy.

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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 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 22 of the Notes to Consolidated Financial Statements" for further discussion of our regulatory accounting policy.

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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.

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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 derivatives on a regular basis in the Consolidated Statements of Income, which could lead to significant fluctuations in net income.

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

•	Goodwill, 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 20 of the Notes to Consolidated Financial Statements" for further discussion of our commitments and contingencies.

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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.

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

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

•	the return on pension plan assets.

•	expected return on pension plan assets,

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

•	assumed rate of increase in employee compensation,

•	life expectancy of participants and other beneficiaries, and

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

*	Changes in the expected return on plan assets would not have an effect on our total pension liability.

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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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•	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.

•	the ongoing and multi-year redevelopment of the Little Falls hydroelectric plant on the Spokane River,

•	the continuing rehabilitation of the Nine Mile hydroelectric plant on the Spokane River,

•	information technology upgrades that include the replacement of our customer information and work management systems (which were implemented in February 2015),

•	the ongoing project to systematically replace portions of Aldyl-A natural gas distribution pipe, and

•	technology investments for deploying Advanced Metering Infrastructure in Washington, including installation of advanced meters, beginning in 2016.

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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, 2014.

(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 as well as information technology contracts associated with the replacement of our customer information and work management systems, which are capital expenditures and were completed in February 2015.

(6)	Represents our estimated cash contributions to pension plans and other postretirement benefit plans through 2019. We cannot reasonably estimate pension plan contributions beyond 2019 at this time and have excluded them from the table above.

(7)	Represents the contractually required capital project funding associated with the Snettisham hydroelectric project. These costs are generally recovered through base retail rates.

(8)	Represents a commitment to fund a limited liability company in exchange for equity ownership, made by a subsidiary of Avista Capital.

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•	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

•	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,

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

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

•	increase the operating costs of generating plants;

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

•	require modification of our existing generating plants;

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

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

•	restrict the types of generating plants that can be built or contracted with; 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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•	Commodity prices for electric power and natural gas

•	Credit related to the wholesale energy market

•	Interest rates on long-term and short-term debt

•	Foreign exchange rates between the U.S. dollar and the Canadian dollar

•	imbalances between available power supply resources and our load obligations,

•	substitution of resources to achieve economic dispatch from available power supply choices, and

•	our objective to optimize the value of specific power resource facilities.

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•	demand for electricity,

•	adequacy of generating reserve margins,

•	scheduled and unscheduled outages of generating facilities,

•	availability of streamflows for hydroelectric generation,

•	price and availability of fuel for thermal generating plants,

•	disruptions to or constraints on transmission facilities,

•	the number of market participants and the willingness of market participants to trade, and

•	weather (including temperature fluctuations and generation resulting from wind).

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•	demand for natural gas, including natural gas as fuel for electric generation,

•	actual and expected changes in the North American natural gas supply volume or source mix including the growth in new supplies such as natural gas from shale,

•	natural gas production that can be delivered to our service areas,

•	level of imports and exports, particularly from Canada by pipeline, and any taxes or restrictions that apply,

•	potential development of liquefied natural gas export facilities that compete for supplies,

•	level of storage inventories and regional accessibility,

•	global energy markets, including oil or other natural gas substitutes, such as coal,

•	availability of pipeline capacity to transport natural gas from region to region,

•	the number of market participants and the willingness of market participants to trade, and

•	weather conditions (temperatures, precipitation levels and wind patterns) which affect energy demand, including weather-sensitive customer demand, and electric generation.

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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.

•	relating directly to the counterparty,

•	caused by market price changes, and

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

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

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

•	actively monitoring current credit exposures,

•	asserting our collateral rights with counterparties, and

•	carrying out transaction settlements timely and effectively.

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•	electric and natural gas utilities,

•	electric generators and transmission providers,

•	natural gas producers and pipelines,

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

•	energy marketing and trading companies.

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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, 2014 reflects the offsetting of $28.9 million of cash collateral against the net derivative positions where a legal right of offset exists.

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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, and

•	actual throughput for natural gas.

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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 were removed from the Consolidated Balance Sheets (and had no effect on net income). See Note 20 for additional discussion of the settlement in the California wholesale power markets litigation.

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(1)	The gross realized losses for 2014 were included in the determination of the gain on the disposal of Ecova and were not the result of selling any individual securities.

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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.

•	required to write off its regulatory assets, and

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

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(1)	This entire balance was related to Ecova, which was disposed of as of June 30, 2014.

(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)	AERC was acquired on July 1, 2014 and only the supplemental revenues and net income for the period July 1, 2014 to December 31, 2014 were included in the actual results of Avista Corp. for the year ended December 31, 2014.

(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, 2014, Avista Corp. has expensed $3.0 million (pre-tax) in total transaction fees. In addition to the amounts expensed, through December 31, 2014, Avista Corp. has included $0.4 million in fees associated with the issuance of

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(1)	Of this total amount, approximately $16.8 million will be held in escrow for 15 months from the transaction closing date for any indemnity claims and an additional $1.0 million is being held in escrow pending resolution of adjustments to working capital, which is expected to be resolved in early 2015.

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(1)	This represents the gross gain recorded to discontinued operations. The gain net of taxes and transactions expenses is $69.7 million.

(2)	This represents Avista Corp.'s portion of the total transaction expenses. All transaction expenses paid on the Ecova sale were $11.0 million, of which $5.4 million were withheld from the net proceeds and the remainder were paid during the

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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 capacity contracts.

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•	wholesale market sales of surplus natural gas supplies,

•	optimization of interstate pipeline transportation capacity not needed to serve daily load, and

•	purchases and sales of natural gas to optimize use of storage capacity.

(1)	Physical transactions represent commodity transactions where Avista Utilities will take delivery of either electricity or natural gas and financial transactions represent derivative instruments with no physical delivery, such as futures, swaps or options.

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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.

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

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

•	actively monitoring current credit exposures,

•	asserting our collateral rights with counterparties,

•	carrying out transaction settlements timely and effectively, and

•	conducting transactions on exchanges with fully collateralized clearing arrangements that significantly reduce counterparty default risk.

•	electric and natural gas utilities,

•	electric generators and transmission providers,

•	natural gas producers and pipelines,

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

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•	energy marketing and trading companies.

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(1)

Included in other property and investments-net on the Consolidated Balance Sheets. Ecova was sold on June 30, 2014; therefore, there is no property and equipment associated with them as of December 31, 2014. Accumulated depreciation was $26.4 million as of December 31, 2013 for Ecova. Accumulated depreciation was $10.8 million as of December 31, 2014 and $11.4 million as of December 31, 2013 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 during 2014.

•	restore 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,

•	remove asbestos at the corporate office building, 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 investment is in derivatives linked to commodity indices to gain exposure to the commodity markets. These positions are fully collateralized with debt securities.

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

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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.

(2)

In December 2014, Avista Corp. issued $60.0 million of first mortgage bonds to three institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.11 percent and mature in 2044. 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.

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(3)	In September 2014, AEL&P issued $75.0 million of 4.54 percent first mortgage bonds due in 2044 to two institutional investors in the private placement market. The first mortgage bonds were issued under and in accordance with the AEL&P Mortgage and Deed of Trust, dated as of July 1, 2014.

(4)	In December 2014, AERC issued a $15.0 million unsecured term loan note due in 2019 to a national cooperative bank. The term note bears an interest rate of 3.85 percent.

(5)	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.

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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)

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 delivery. 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 delivery, 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.

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

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

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

•

certain requirements under the OPUC approval of the AERC acquisition. 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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(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)	This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant.

(8)	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.

(9)

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.

•	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)

The new retail rates that became effective on January 1, 2014 were temporary rates, and on January 1, 2015, electric and natural gas base rates were scheduled to revert back to 2013 levels absent any intervening action from the UTC. The original settlement agreement had a provision that the Company would not file a general rate case in Washington seeking new rates to take effect before January 1, 2015. In November 2014, the UTC approved a settlement agreement to the Company's Washington general rate cases which were originally filed in February 2014 with rates effective on January 1, 2015 (see further discussion below).

(2)	In its Order, the UTC found that much of the approved base rate increase was justified by the planned capital expenditures necessary to upgrade and maintain the Company's utility facilities. If these capital projects are not

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•	If there is a decoupling rebate balance for the prior year and Avista Corp. earns in excess of a 7.32 percent rate of return (ROR), the rebate to customers would be increased by 50 percent of the earnings in excess of the 7.32 percent ROR.

•	If there is a decoupling rebate balance for the prior year and Avista Corp. earns a 7.32 percent ROR or less, only the base amount of the rebate to customers would be made.

•	If there is a decoupling surcharge balance for the prior year and Avista Corp. earns 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 there is a decoupling surcharge balance for the prior year and Avista Corp. earns a 7.32 percent ROR or less, the base amount of the surcharge to customers would be made.

•	the ongoing and multi-year redevelopment of the Little Falls Powerhouse on the Spokane River,

•	the continuing rehabilitation of the Nine Mile Powerhouse on the Spokane River,

•	information technology upgrades that include the replacement of the Company's customer information and work management systems (which were implemented in February 2015),

•	the ongoing project to systematically replace portions of Aldyl-A natural gas distribution pipe, and

•	technology investments for deploying Advanced Metering Infrastructure in Washington, including installation of advanced meters, beginning in 2016.

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•	the delay of the beginning of the amortization of the 2013 previously deferred operations and maintenance costs pertaining to the Colstrip and Coyote Springs 2 thermal generating facilities from 2015 to 2016, and

•	deferred accounting, for later review and recovery, of the majority of the costs associated with Project Compass, which was implemented in February 2015.

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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.

(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 are related to Ecova.

(4)	The consolidated total assets presented here as of December 31, 2013 exclude total assets at 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 7, 2015, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 28, 2014, relating to its Annual Meeting of Shareholders held on May 8, 2014.

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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 7, 2015, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 28, 2014, relating to its Annual Meeting of Shareholders held on May 8, 2014.

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

(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 7, 2015, from such Proxy Statement; and

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•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 28, 2014, relating to its Annual Meeting of Shareholders held on May 8, 2014.

(c)	Changes in control:

(d)	Securities authorized for issuance under equity compensation plans as of December 31, 2014:

(1)

Excludes unvested restricted shares and performance share awards granted under Avista Corp.’s Long Term Incentive Plan. At December 31, 2014, 112,042 Restricted Share awards were outstanding. Performance and market-based share awards may be paid out at zero shares at a minimum achievement level; 345,851 shares at target level; or 691,702 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 7, 2015, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 28, 2014, relating to its Annual Meeting of Shareholders held on May 8, 2014.

•	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 7, 2015, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 28, 2014, relating to its Annual Meeting of Shareholders held on May 8, 2014.

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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 Christy M. Burmeister-Smith, Don F. Kopczynski, 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 only applies to Kevin J. Christie.

(8)	Applies to executive officers appointed after February 4, 2011. This only applies to Kevin J. Christie.