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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 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;

•	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;

•	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 customer demand for utility services;

•	the effect of increased customer energy efficiency;

•	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;

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

•	volatility and illiquidity in wholesale energy markets, including the availability of willing buyers and sellers, and prices of purchased energy and demand for energy sales;

•	the outcome of pending regulatory and legal proceedings arising out of the “western energy crisis” of 2000 and 2001, including possible refunds;

•	the outcome of legal proceedings and other contingencies;

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

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•	wholesale and retail competition including alternative energy sources, suppliers and delivery arrangements and the extent that new uses for our services may materialize;

•	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, or other incidents that may cause unplanned outages at any of our generation facilities, transmission and distribution systems or other operations;

•	public injuries or damages 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 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;

•	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 climate of the Pacific Northwest, 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;

•	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 certain ratings trigger covenants in our financing arrangements and wholesale energy contracts;

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

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

•	work force issues, including changes in collective bargaining unit agreements, strikes, work stoppages or 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 the payment acceptance policies of Ecova’s client vendors that could reduce operating revenues;

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

•	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.

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•	Avista Utilities – an operating division of Avista Corp. that comprises our regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. The utility also engages in wholesale purchases and sales of electricity and natural gas.

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Ecova – an indirect subsidiary of Avista Corp. (79.0 percent owned as of December 31, 2012) provides energy efficiency and cost management programs and services for multi-site customers and utilities throughout North America. Ecova’s service lines include expense management services for utility and telecom needs as well as strategic energy management and efficiency services that include procurement, conservation, performance reporting, financial planning, facility optimization and continuous monitoring, and energy efficiency program management for commercial enterprises and utilities.

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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.

•	native load of 1,579 MW,

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•	long-term wholesale obligations of 236 MW, and

•	short-term wholesale obligations of 670 MW.

•	company-owned or controlled electric generation of 1,755 MW,

•	long-term hydroelectric contracts with certain Public Utility Districts (PUDs) of 152 MW,

•	long-term thermal generation contract with Lancaster Plant of 270 MW,

•	other long-term wholesale contracts of 133 MW, and

•	short-term wholesale purchases of 750 MW.

•	the combined cycle combustion turbine (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,

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•	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)	System load is reduced in 2013 because a large industrial customer will begin generating electricity to meet a portion of its own load after June 30, 2013. The full impact of this load change culminates in 2014 when load is reduced for 12 calendar months.

(2)	The forecast assumes near normal hydroelectric generation (decline in 2015 and 2016 is due to changes in contracts with PUDs).

(3)	Includes our long-term contract with the Lancaster Plant. Excludes 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.

(4)	Northeast CT and Rathdrum CT. The combined maximum capacity of the Northeast CT and Rathdrum CT is 243 MW, with estimated available energy production as indicated for each year.

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•	A contract for the 105 MW Palouse Wind, LLC project, which provides a new resource to serve our customers’ increasing energy needs. Commercial operations began on December 13, 2012.

•	An additional 42 aMW of wind or other renewable beginning in 2021.

•	Energy efficiency measures are expected to save 310 aMW of cumulative energy over the 20-year IRP timeframe. This aggressive effort could reduce load growth to half of what it would be without these measures.

•	750 MW of new natural gas-fired generation facilities are anticipated in two or three increments between 2018 and 2031.

•	Grid modernization programs are projected to save 5 aMW of energy by 2013.

•	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, and

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

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(1)	Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures).

(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).

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(1)	Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).

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•	emerging technology venture capital funds, and

•	residual ownership of a fuel cell business that was previously a subsidiary of the Company.

•	retail electricity and natural gas sales,

•	the cost of natural gas supply,

•	the cost of power supply, and

•	damages 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 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,

•	forced 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.

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•	refund proceedings in California and the Pacific Northwest,

•	market conduct investigations by the FERC, and

•	complaints filed by various parties related to alleged misconduct by parties in western power markets.

•	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, 2012.

(3)	The present capability of Cabinet Gorge is limited by our water rights. This output level reflects the maximum capability within our water rights. When river flows exceed these water rights limits, we are permitted to increase flow through the plant resulting in up to 265 MW.

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

(5)	There are currently four units at the Nine Mile plant; however, the present capability is limited due to a mechanical failure of Units 1 and 2. A project is underway to replace these units and restore capability. The nameplate rating of the two remaining units is 18 MW.

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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.

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(1)	Spokane Energy was consolidated effective January 1, 2010. See "Note 3 of the Notes to Consolidated Financial Statements."

(2)	See Exhibit 12 for computations.

(3)	Includes an immaterial correction of an error related to the reclassification of certain operating expenses from other expense-net to other operating expenses. This correction did not have an impact on net income or earnings per share. See "Note 1 of the Notes to Consolidated Financial Statements" for further information regarding this reclassification.

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•	Avista Utilities – an operating division of Avista Corp. that comprises our regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. The utility also engages in wholesale purchases and sales of electricity and natural gas.

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Ecova – an indirect subsidiary of Avista Corp. (79.0 percent owned as of December 31, 2012) provides energy efficiency and cost management programs and services for multi-site customers and utilities throughout North America. Ecova's service lines include expense management services for utility and telecom needs as well as strategic energy management and efficiency services that include procurement, conservation, performance reporting, financial planning, facility optimization and continuous monitoring, and energy efficiency program management for commercial enterprises and utilities.

•	weather conditions,

•	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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•	provide for recovery of operating costs and capital investments, and

•	provide the opportunity to improve our earned returns as allowed by regulators.

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

•	the level of hydroelectric generation,

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

•	the net value from optimization activities related to our generating resources, and

•	retail loads.

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•	the number of customers,

•	current rates,

•	meter reading dates,

•	actual native load for electricity, and

•	actual throughput for natural gas.

•	required to write off regulatory assets, and

•	precluded from the future deferral of costs not recovered through rates when such costs are incurred, even if we expect to recover such costs in the future.

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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, and

•	assumed rate of increase in employee compensation.

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*	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 which have not previously been made the basis of any application under the Mortgage, or

•	an equal principal amount of retired First Mortgage Bonds which have not previously been made the basis of any application under the Mortgage, or

•	deposit of cash.

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

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

•	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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(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, 2012.

(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. Future capital lease obligations are not material.

(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)	Represents our estimated cash contributions to the pension plan through 2016. We cannot reasonably estimate pension plan contributions beyond 2016 at this time and have excluded them from the table above.

(6)	Certain shares acquired under Ecova’s employee stock incentive plan are redeemable at the option of the shareholder.

(7)	Represents a commitment to fund a limited partnership venture fund commitment made by a subsidiary of Avista Capital.

(8)	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 expected to be completed in 2014.

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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, and

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

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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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•	facilitates internal and external communications regarding climate change issues,

•	analyzes policy impacts, 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

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•	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).

•	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 unconventional 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,

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•	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, and

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

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

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•	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.

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

•	pension and other postretirement benefit plan obligations,

•	contingent liabilities,

•	recoverability of regulatory assets, and

•	unbilled revenues.

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•	electric thermal production - 33 years,

•	hydroelectric production - 73 years,

•	electric transmission - 51 years,

•	electric distribution - 38 years, and

•	natural gas distribution property - 49 years.

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(1)	Generally, the AFUDC rate changes effective January 1 of every year, however this rate was effective from January 1, 2010 to November 30, 2010. Effective December 1, 2010, the rate was changed to 7.91%.

(1)	Includes an immaterial correction of an error related to the reclassification of certain operating expenses from other expense-net to utility and non-utility other operating expenses and utility taxes other than income taxes. This correction did not have an impact on net income or earnings per share. See further discussion of this reclassification below under "Immaterial Correction of an Error".

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

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

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

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•	required to write off its regulatory assets, and

•	precluded from the future deferral of costs 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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•	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

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•	other wholesale transactions to capture the value of generation and transmission resources and fuel delivery capacity contracts.

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

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•	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,

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•	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

•	energy marketing and trading companies.

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(1)	Included in other property and investments-net on the Consolidated Balance Sheets. Accumulated depreciation was $23.4 million as of December 31, 2012 and $20.3 million as of December 31, 2011 for Ecova and $13.7 million as of December 31, 2012 and $13.1 million as of December 31, 2011 for the other businesses.

•	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)	The fund primarily invests in derivatives linked to commodity indices to gain exposure to the commodity markets. The fund manager fully collateralizes these positions with debt securities.

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

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(1)	Ecova files its own tax return and its deferred tax assets and liabilities cannot be netted with Avista Corp.'s deferred income tax assets and liabilities. This balance is included in other deferred charges on the Consolidated Balance Sheet at December 31, 2012.

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(1)	The annual costs will change in proportion to the percentage of output allocated to Avista Utilities in a particular year. Amounts represent the operating costs for 2012. Debt service costs are included in annual costs.

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(1)	In December 2010, $66.7 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due 2032, which had been held by Avista Corp. since 2008, were refunded by a new bond issue (Series 2010A). The new bonds were not offered to the public and were purchased by Avista Corp. due to

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(2)

In December 2010, $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds, (Avista Corporation Colstrip Project) due 2034, which had been held by Avista Corp. since 2009, were refunded by a new bond issue (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, the 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 Sheet.

(3)	In November 2012, the Company issued $80.0 million of 4.23 percent First Mortgage Bonds due in 2047.

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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 Utilities 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 Utilities 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.

(2)	A derivative contract was reclassified from Level 2 to Level 3 during 2011 due to a particular unobservable input becoming more significant to the fair value measurement. There were not any reclassifications between Level 1 and Level 2. The Company's policy is to reclassify identified items as of the end of the reporting period.

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(1)	There were no shares excluded from the calculation because they were antidilutive. All stock options had exercise prices which were less than the average market price of Avista Corp. common stock during the respective period.

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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 that have prior regulatory precedence.

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

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

(5)

The UTC and the IPUC issued accounting orders authorizing Avista Utilities 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 Utilities 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.

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

•	the level of hydroelectric generation,

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

•	retail loads.

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(1)	Intersegment eliminations reported as operating revenues and resource costs represent intercompany purchases and sales of electric capacity and energy. Intersegment eliminations reported as interest expense represent intercompany interest.

(2)	Including interest expense to affiliated trusts.

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(3)	Includes an immaterial correction of an error related to the reclassification of certain operating expenses from other expense-net to utility and non-utility other operating expenses and utility taxes other than income taxes. This correction did not have an impact on net income or earnings per share. See Note 1 for further information regarding this reclassification.

(1)	Includes an immaterial correction of an error related to the reclassification of certain operating expenses from other expense-net to other operating expenses. This correction did not have an impact on net income or earnings per share. See Note 1 for further information regarding this reclassification.

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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 9, 2013, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 30, 2012, relating to its Annual Meeting of Shareholders held on May 10, 2012.

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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 9, 2013, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 30, 2012, relating to its Annual Meeting of Shareholders held on May 10, 2012.

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

(b)	Security ownership of management:

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•	on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 9, 2013, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 30, 2012, relating to its Annual Meeting of Shareholders held on May 10, 2012.

(c)	Changes in control:

(d)	Securities authorized for issuance under equity compensation plans as of December 31, 2012:

(1)

Excludes unvested restricted shares and performance share awards granted under Avista Corp.’s Long Term Incentive Plan. At December 31, 2012, 117,118 Restricted Share awards were outstanding. Performance share awards may be paid out at zero shares at a minimum achievement level; 359,700 shares at target level; or 719,400 shares at a maximum level. Because there is no exercise price associated with restricted shares or performance 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 9, 2013, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 30, 2012, relating to its Annual Meeting of Shareholders held on May 10, 2012.

•	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 9, 2013, from such Proxy Statement; and

•	prior to such date, from the Registrant's definitive Proxy Statement, dated March 30, 2012, relating to its Annual Meeting of Shareholders held on May 10, 2012.

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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. The Company does not currently have any officers that these agreements apply to.

(8)	Applies to executive officers appointed after February 4, 2011. The Company does not currently have any officers that these plans apply to.

(9)	Applies to awards in 2010.

(10)	Applies to awards in 2011.

(11)	Applies to awards in 2012.