UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

(Mark One)

For the quarterly period ended March 31, 2005

OR

For the transition period from                      to                     

Commission file number 1-3701

AVISTA CORPORATION

Registrant’s telephone number, including area code: 509-489-0500
Web site: http://www.avistacorp.com

None

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ   No o

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act):

Yes þ   No o

As of May 2, 2005, 48,503,142 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

AVISTA CORPORATION

Index

CONSOLIDATED STATEMENTS OF INCOME
Avista Corporation

The Accompanying Notes are an Integral Part of These Statements.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Avista Corporation

The Accompanying Notes are an Integral Part of These Statements.

4

CONSOLIDATED BALANCE SHEETS

The Accompanying Notes are an Integral Part of These Statements.

5

CONSOLIDATED BALANCE SHEETS (continued)

The Accompanying Notes are an Integral Part of These Statements.

6

CONSOLIDATED STATEMENTS OF CASH FLOWS
Increase (Decrease) in Cash and Cash Equivalents
Avista Corporation

The Accompanying Notes are an Integral Part of These Statements.

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AVISTA CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The accompanying consolidated financial statements of Avista Corporation (Avista Corp. or the Company) for the interim periods ended March 31, 2005 and 2004 are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results of operations for those interim periods. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Consolidated Statements of Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company’s audited consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 (2004 Form 10-K). Please refer to the section “Acronyms and Terms” in the 2004 Form 10-K for definitions of terms such as capacity, energy and therm.

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corp. is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity in parts of eastern Washington and northern Idaho. In addition, Avista Utilities has electric generating facilities in western Montana and northern Oregon. Avista Utilities also provides natural gas distribution service in parts of eastern Washington, northern Idaho, as well as northeast and southwest Oregon. In April 2005, the Company completed the sale of its South Lake Tahoe, California natural gas distribution properties (see Note 12 for further information). Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility business segments. See Note 14 for business segment information.

The Company’s operations are exposed to risks including, but not limited to, the price and supply of purchased power, fuel and natural gas, regulatory recovery of power and natural gas costs and capital investments, streamflow and weather conditions, the effects of changes in legislative and governmental regulations, changes in regulatory requirements, availability of generation facilities, competition, technology and availability of funding. Also, like other utilities, the Company’s facilities and operations may be exposed to terrorism risks or other malicious acts. In addition, the energy business exposes the Company to the financial, liquidity, credit and commodity price risks associated with wholesale purchases and sales.

Basis of Reporting

The consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries. The accompanying financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants.

Use of Estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Significant estimates include determining unbilled revenues, the market value of energy commodity assets and liabilities, pension and other postretirement benefit plan obligations, contingent liabilities and recoverability of regulatory assets. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein.

Avista Utilities Operating Revenues

Operating revenues for Avista Utilities related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded.

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Avista Energy Operating Revenues

Avista Energy follows Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149, with respect to the majority of its contracts. Avista Energy reports the net margin on derivative commodity instruments held for trading as operating revenues. Revenues from contracts that are not derivatives under SFAS No. 133, as well as derivative commodity instruments not held for trading, are reported on a gross basis in operating revenues. Revenues derived from Canadian contracts through Avista Energy Canada, which are not held for trading, and are reported on gross basis in operating revenues, totaled $37.4 million and $34.7 million for the three months ended March 31, 2005 and 2004, respectively.

Other Income-Net

Other income-net consisted of the following items for the three months ended March 31 (dollars in thousands):

Stock-Based Compensation

The Company follows the disclosure only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation.” Accordingly, employee stock options are accounted for under Accounting Principle Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.” Stock options are granted at exercise prices not less than the fair value of common stock on the date of grant. Under APB No. 25, no compensation expense is recognized pursuant to the Company’s stock option plans. See Note 2 with respect to the revision of SFAS No. 123, which will result in the recognition of compensation expense beginning in 2006.

If compensation expense for the Company’s stock option plans were determined consistent with SFAS No. 123, net income and earnings per common share would have been the following pro forma amounts for the three months ended March 31:

Comprehensive Income (Loss)

The Company’s comprehensive income (loss), which is reported net of tax, is comprised of net income, foreign currency translation adjustments, changes in the unfunded accumulated benefit obligation for the pension plan, unrealized gains and losses on interest rate swap agreements, unrealized gains and losses on derivative commodity instruments and unrealized gains and losses on investments available-for-sale.

Accumulated other comprehensive income (loss), net of tax, consisted of the following as of March 31, 2005 and December 31, 2004 (dollars in thousands):

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Restricted Cash

Restricted cash includes bank deposits of $7.2 million and $21.5 million as collateral for letters of credit issued under Avista Energy’s credit agreement as of March 31, 2005 and December 31, 2004, respectively. See Note 8 for further information with respect to Avista Energy’s credit agreement. Restricted cash also includes deposits held in trust of $1.6 million for certain employees of Avista Energy as part of a bonus retention plan as of March 31, 2005 and December 31, 2004. In addition, restricted cash as of March 31, 2005 and December 31, 2004, includes $2.5 million of deposits related to forward contracts at Avista Energy. Restricted cash as of December 31, 2004 includes $0.6 million of deposits related to Avista Corp.’s interest rate swap agreements. See Note 9 for further information with respect to Avista Corp.’s interest rate swap agreements.

Assets held for sale

Assets held for sale are recorded at the lower of cost or estimated fair value less selling costs. As of March 31, 2005 assets held for sale included $13.5 million of assets related to Avista Utilities’ South Lake Tahoe natural gas distribution properties and $13.0 million of turbines and related equipment. As of December 31, 2004 assets held for sale included $15.2 million of assets related to Avista Utilities’ South Lake Tahoe natural gas distribution properties and $13.3 million of turbines and related equipment. Liabilities held for sale were not significant as of March 31, 2005 and December 31, 2004.

Goodwill

Goodwill arising from acquisitions represents the excess of the purchase price over the estimated fair value of net assets acquired. The Company evaluates goodwill for impairment using a discounted cash flow model on at least an annual basis or more frequently if impairment indicators arise. Goodwill is included in non-utility properties and investments-net on the Consolidated Balance Sheets and totaled $6.2 million ($5.2 million in the Other business segment and $1.0 million in Energy Marketing and Resource Management) as of March 31, 2005 and December 31, 2004. The Company completed its annual evaluation of goodwill for potential impairment during the three months ended March 31, 2005 and determined that goodwill was not impaired.

Regulatory Deferred Charges and Credits

The Company prepares its consolidated financial statements in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” The Company prepares its financial statements in accordance with SFAS No. 71 because (i) the Company’s rates for regulated services are established by or subject to approval by an independent third-party regulator; (ii) the regulated rates are designed to recover the Company’s cost of providing the regulated services; and (iii) 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 the Company’s costs. SFAS No. 71 requires the Company to reflect the impact of regulatory decisions in its financial statements. SFAS No. 71 requires that certain costs and/or obligations (such as incurred power and natural gas costs not currently recovered through rates, but expected to be recovered in the future) are reflected as deferred charges on the Consolidated Balance Sheets. These costs and/or obligations are not reflected in the statement of income until the period during which matching revenues are recognized. If at some point in the future the Company determines that it no longer meets the criteria for continued application of SFAS No. 71 with respect to all or a portion of the Company’s regulated operations, the Company could be required to write-off its regulatory assets. The Company could also be 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.

The Company’s primary regulatory assets include power and natural gas deferrals (see “Power Cost Deferrals and Recovery Mechanisms” and “Natural Gas Cost Deferrals and Recovery Mechanisms” below for further information), investment in exchange power, regulatory asset for deferred income taxes, unamortized debt expense, regulatory asset for consolidation of variable interest entity, demand side management programs, conservation programs and the provision for postretirement benefits. Those items without a specific line on the Consolidated Balance Sheets are included in other regulatory assets. Other regulatory assets consisted of the following as of March 31, 2005 and December 31, 2004 (dollars in thousands):

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Regulatory liabilities include utility plant retirement costs. Deferred credits include, among other items, regulatory liabilities created when the Centralia Power Plant was sold, regulatory liabilities offsetting net energy commodity derivative assets (see Note 4 for further information) and the gain on the general office building sale/leaseback, which is being amortized over the life of the lease, and are included on the Consolidated Balance Sheets as other current liabilities and other non-current liabilities and deferred credits.

Natural Gas Benchmark Mechanism

The Idaho Public Utilities Commission (IPUC), Washington Utilities and Transportation Commission (WUTC) and Oregon Public Utility Commission (OPUC) approved Avista Utilities’ Natural Gas Benchmark Mechanism in 1999. The mechanism eliminated the majority of natural gas procurement operations within Avista Utilities and placed responsibility for natural gas procurement operations with Avista Energy, the Company’s non-regulated subsidiary. The ownership of the natural gas assets remained with Avista Utilities; however, the assets were managed by Avista Energy through an Agency Agreement. Avista Utilities has always managed natural gas procurement for its California operations, which the Company sold in April 2005 (see Note 12).

In the first quarter of 2002, the IPUC and the OPUC approved the continuation of the Natural Gas Benchmark Mechanism and related Agency Agreement through March 31, 2005. Effective April 1, 2005, the Natural Gas Benchmark Mechanism and Related Agency Agreement were terminated and the management of natural gas procurement functions was moved from Avista Energy back to Avista Utilities. This was required for Washington customers by WUTC orders issued over one year earlier, in February 2004, and Avista Utilities’ resulting transition plan approved by the WUTC in April 2004. The Company also elected to move these functions back to Avista Utilities for Idaho and Oregon natural gas customers.

In accordance with SFAS No. 71, profits recognized by Avista Energy on natural gas sales to Avista Utilities, including gains and losses on natural gas contracts, are not eliminated in the consolidated financial statements. This is due to the fact that Avista Utilities expects to recover the costs of natural gas purchases to serve retail customers and for fuel for electric generation through future retail rates.

Power Cost Deferrals and Recovery Mechanisms

Avista Utilities defers the recognition in the income statement of certain power supply costs as approved by the WUTC. Deferred power supply costs are recorded as a deferred charge on the Consolidated Balance Sheets for future review and the opportunity for recovery through retail rates. The power supply costs deferred include certain differences between actual power supply costs incurred by Avista Utilities and the costs included in base retail rates. This difference in power supply costs primarily results from changes in short-term wholesale market prices, changes in the level of hydroelectric generation and changes in the level of thermal generation (including changes in fuel prices). Avista Utilities accrues interest on deferred power costs in the Washington jurisdiction at a rate, which is adjusted semi-annually, of 8.3 percent as of March 31, 2005. Total deferred power costs for Washington customers were $107.1 million and $113.2 million as of March 31, 2005 and December 31, 2004, respectively.

In Washington, the Energy Recovery Mechanism (ERM) allows Avista Utilities to increase or decrease electric rates periodically with WUTC approval to reflect changes in power supply costs. The ERM provides for Avista Utilities to incur the cost of, or receive the benefit from, the first $9.0 million in annual power supply costs above or below the amount included in base retail rates. Under the ERM, 90 percent of annual power supply costs exceeding or below the initial $9.0 million are deferred for future surcharge or rebate to Avista Utilities’ customers. The remaining 10 percent of power supply costs are an expense of, or benefit to, the Company.

Under the ERM, Avista Utilities makes an annual filing to provide the opportunity for the WUTC and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. The ERM provides for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by WUTC order. Avista Utilities made its annual filing with the WUTC on March 30, 2005 related to $10.8 million of deferred power costs incurred for 2004.

Avista Utilities has a power cost adjustment (PCA) mechanism in Idaho that allows it to modify electric rates periodically with IPUC approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the authorized level of net power supply expense approved in the last Idaho general rate case. Avista Utilities accrues interest on deferred power costs in the Idaho jurisdiction at a rate, which is adjusted annually, of 2.0 percent on current year deferrals and 4.0 percent on carryover balances as of

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March 31, 2005. Total deferred power costs for Idaho customers were $7.7 million and $9.5 million as of March 31, 2005 and December 31, 2004, respectively.

Natural Gas Cost Deferrals and Recovery Mechanisms

Under established regulatory practices in each respective state, Avista Utilities is allowed to adjust its natural gas rates periodically (with regulatory approval) to reflect increases or decreases in the cost of natural gas purchased. Differences between actual natural gas costs and the natural gas costs already included in retail rates are deferred and charged or credited to expense when regulators approve inclusion of the cost changes in rates. Total deferred natural gas costs were $23.1 million and $28.6 million as of March 31, 2005 and December 31, 2004, respectively. This includes deferred natural gas costs related to California operations, which is classified as an asset held for sale.

Reclassifications

Certain prior period amounts were reclassified to conform to current statement format. These reclassifications were made for comparative purposes and to conform to changes in accounting standards and have not affected previously reported total net income or stockholders’ equity.

NOTE 2. NEW ACCOUNTING STANDARDS

In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, “Consolidation of Variable Interest Entities,” which was revised in December 2003 (collectively referred to as FIN 46). In general, a variable interest entity does not have equity investors with voting rights or it has equity investors that do not provide sufficient financial resources for the entity to support its activities. Variable interest entities are commonly referred to as special purpose entities or off-balance sheet structures; however, FIN 46 applies to a broader group of entities. FIN 46 requires a variable interest entity to be consolidated by the primary beneficiary of that entity. The primary beneficiary is subject to a majority of the risk of loss from the variable interest entity’s activities or it is entitled to receive a majority of the entity’s residual returns. FIN 46 also requires disclosure of variable interest entities that a company is not required to consolidate but in which it has a significant variable interest. The consolidation requirements of FIN 46 applied immediately to variable interest entities created after January 31, 2003 and applied to certain existing variable interest entities for the first fiscal year or interim period ending after December 15, 2003. Application for all other types of entities was required for periods ending after March 15, 2004. Please refer to the 2004 Form 10-K for the effects of the application of FIN 46 prior to the first quarter of 2004.

The implementation of FIN 46, as revised in December 2003, resulted in the Company including a partnership as well as several low-income housing project investments held in the Other business segment in its consolidated financial statements beginning in the first quarter of 2004. This resulted in a charge of $0.5 million recorded as a cumulative effect of accounting change for the three months ended March 31, 2004.

In December 2004, the FASB issued SFAS No. 123R, “Accounting for Stock-Based Compensation,” which supersedes APB No. 25 and its related implementation guidance. This statement establishes revised standards for the accounting for transactions in which the Company exchanges its equity instruments for goods or services with a primary focus on transactions in which the Company obtains employee services in share-based payment transactions. The statement requires that the compensation cost relating to share-based payment transactions be recognized in financial statements based on the fair value of the equity or liability instruments issued. In April 2005, the Securities and Exchange Commission issued a rule, which delays the Company’s implementation of the provisions of this statement from the third quarter of 2005 to the first quarter of 2006. The Company expects to record compensation expense (net of tax) of approximately $0.3 million in 2006 related to the periodic vesting of stock options granted to employees in prior years. As the Company is not currently granting stock options to employees, the prospective provisions of this statement are not expected to have a material effect on the Company’s future financial condition, results of operations or cash flows.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” This interpretation clarifies that the term “conditional asset retirement obligation” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the Company. The Company will be required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. This interpretation also clarifies when the Company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The Company will be required to adopt this interpretation by the end of 2005. The Company is evaluating the impact this statement will have on its financial condition and results of operations.

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NOTE 3. ACCOUNTS RECEIVABLE SALE

Avista Receivables Corporation (ARC) is a wholly owned, bankruptcy-remote subsidiary of Avista Corp. formed for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On March 22, 2005, Avista Corp., ARC and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment was to extend the termination date from May 29, 2005 to March 21, 2006. Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 million of those receivables. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. On a consolidated basis, the amount of such fees is included in operating expenses of Avista Corp. As of March 31, 2005 and December 31, 2004, $85.0 million and $72.0 million in accounts receivables were sold, respectively, under this revolving agreement.

NOTE 4. UTILITY ENERGY COMMODITY DERIVATIVE ASSETS AND LIABILITIES

SFAS No. 133, as amended by SFAS No. 138 and SFAS No. 149, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires the recording of all derivatives as either assets or liabilities on the balance sheet measured at estimated fair value and the recognition of the unrealized gains and losses. In certain defined conditions, a derivative may be specifically designated as a hedge for a particular exposure. The accounting for derivatives depends on the intended use of the derivatives and the resulting designation.

Avista Utilities enters into forward contracts to purchase or sell energy. Under these forward contracts, Avista Utilities commits to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. Certain of these forward contracts are considered derivative instruments. Avista Utilities also records derivative commodity assets and liabilities for over-the-counter and exchange-traded derivative instruments as well as certain long-term contracts. These contracts are entered into as part of Avista Utilities’ management of its loads and resources as discussed in Note 5. In conjunction with the issuance of SFAS No. 133, the WUTC and the IPUC issued accounting orders authorizing Avista Utilities to offset any 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 and the PCA mechanism.

Prior to the adoption of SFAS No. 149 on July 1, 2003, Avista Utilities elected the normal purchases and sales exception for substantially all of its contracts for both capacity and energy under SFAS No. 133. As such, Avista Utilities was not required to record these contracts as derivative commodity assets and liabilities. Under SFAS No. 149, substantially all new forward contracts to purchase or sell power and natural gas used for generation, which were entered into on or after July 1, 2003, are recorded as assets or liabilities at market value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives under SFAS No. 133 are generally accounted for at cost until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other than temporary. Utility energy commodity derivatives consisted of the following as of March 31, 2005 and December 31, 2004 (dollars in thousands):

Current utility energy commodity derivative assets are included in other current assets on the Consolidated Balance Sheets. Current utility energy commodity derivative liabilities and the offsetting net current regulatory liability are included in other current liabilities on the Consolidated Balance Sheets. The offsetting net non-current regulatory liability is included in other non-current liabilities and deferred credits on the Consolidated Balance Sheets.

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NOTE 5. ENERGY COMMODITY TRADING

The Company’s energy-related businesses are exposed to risks relating to, but not limited to, changes in certain commodity prices, interest rates, foreign currency and counterparty performance. In order to manage the various risks relating to these exposures, Avista Utilities utilizes derivative instruments, such as forwards, futures, swaps and options, and Avista Energy engages in the trading of such instruments. Avista Utilities and Avista Energy use a variety of techniques to manage risks for their energy resources and wholesale energy market activities. The Company has risk management policies and procedures to manage these risks, both qualitative and quantitative, for Avista Utilities and Avista Energy. The Company’s Risk Management Committee establishes the Company’s risk management policies and procedures and monitors compliance. The Risk Management Committee is comprised of certain Company officers and other individuals and is overseen by the Audit Committee of the Company’s Board of Directors.

Avista Utilities

Avista Utilities engages in an ongoing process of resource optimization, which involves the pursuit of economic resources to serve load obligations and using existing resources to capture available economic value. Avista Utilities sells and purchases wholesale electric capacity and energy to and from utilities and other entities as part of the process of acquiring resources to serve its retail and wholesale load obligations. These transactions range from a term as short as one hour up to long-term contracts that extend beyond one year. Avista Utilities makes continuing projections of (1) future retail and wholesale loads based on, among other things, forward estimates of factors such as customer usage and weather as well as historical data and contract terms and (2) resource availability based on, among other things, estimates of streamflows, generating unit availability, historic and forward market information and experience. On the basis of these continuing projections, Avista Utilities makes purchases and sales of energy on an annual, quarterly, monthly, daily and hourly basis to match expected resources to expected energy requirements. Resource optimization also includes transactions such as purchasing fuel to run thermal generation and, when economic, selling fuel and substituting electric wholesale market purchases for the operation of Avista Utilities’ own resources, as well as other wholesale transactions to capture the value of available generation and transmission resources. This optimization process includes entering into financial and physical hedging transactions as a means of managing risks.

Avista Utilities manages the impact of fluctuations in electric energy prices by measuring and controlling the volume of energy imbalance between projected loads and resources and through the use of derivative commodity instruments for hedging purposes. Load/resource imbalances within a rolling 18-month planning horizon are compared against established volumetric guidelines and management determines the timing and specific actions to manage the imbalances. Management also assesses available resource decisions and actions that are appropriate for longer-term planning periods. Avista Energy was responsible for the daily management of natural gas supplies to meet the requirements of Avista Utilities’ customers in the states of Washington, Idaho and Oregon. Effective April 1, 2005, the management of natural gas procurement functions was moved from Avista Energy back to Avista Utilities. This was required for Washington customers by WUTC orders issued over one year earlier, in February 2004, and Avista Utilities’ resulting transition plan approved by the WUTC in April 2004. The Company also elected to move these functions back to Avista Utilities for Idaho and Oregon natural gas customers. As part of the transition plan, Avista Utilities began procuring natural gas for load service during the second half of 2004 and the first quarter of 2005. This procurement process includes entering into financial and physical hedging transactions as a means of managing risks. Avista Utilities has always managed natural gas procurement for its California operations, which the Company sold in April 2005 (see Note 12).

Avista Energy

Avista Energy is an electricity and natural gas marketing, trading and resource management business. Avista Energy focuses on optimization of combustion turbines and hydroelectric assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric transmission and natural gas transportation arrangements. Avista Energy is also involved in trading electricity and natural gas, including derivative commodity instruments. Avista Energy purchases natural gas and electricity from producers and energy marketing and trading companies. Its customers include commercial and industrial end-users, electric utilities, natural gas distribution companies, and energy marketing and trading companies.

Avista Energy’s marketing and energy risk management services are provided through the use of a variety of derivative commodity contracts to purchase or supply natural gas and electric energy at specified delivery points and at specified future dates. Avista Energy trades natural gas and electricity derivative commodity instruments on national exchanges and through other exchanges and brokers, and therefore can experience net open positions in

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terms of price, volume, and specified delivery point. The open positions expose Avista Energy to the risk that fluctuating market prices may adversely impact its financial condition or results of operations. However, the net open positions are actively managed with policies designed to limit the exposure to market risk and requiring daily reporting to management of potential financial exposure.

Avista Energy measures the risk in its electric and natural gas portfolio daily utilizing a Value-at-Risk (VAR) model, which monitors its risk in comparison to established thresholds. VAR measures the expected portfolio loss under hypothetical adverse price movements over a given time interval within a given confidence level. Avista Energy also measures its open positions in terms of volumes at each delivery location for each forward time period. The permissible extent of open positions is included in the risk management policy and is measured with stress tests and VAR modeling.

Derivative commodity instruments sold and purchased by Avista Energy include: forward contracts, which involve physical delivery of an energy commodity; futures contracts, which involve the buying or selling of natural gas or electricity at a fixed price; over-the-counter swap agreements, which require Avista Energy to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity; and options, which mitigate price risk by providing for the right, but not the requirement, to buy or sell energy-related commodities at a fixed price. Foreign currency risks are primarily related to Canadian exchange rates and are managed using standard instruments available in the foreign currency markets.

Avista Energy’s derivative commodity instruments accounted for under SFAS No. 133 are subject to mark-to-market accounting, under which changes in the market value of outstanding electric, natural gas and related derivative commodity instruments are recognized as unrealized gains or losses in the Consolidated Statements of Income in the period of change. Market prices are utilized in determining the value of electric, natural gas and related derivative commodity instruments, which are reported as assets and liabilities on the Consolidated Balance Sheets. These market prices are used through 36 months. For longer-term positions and certain short-term positions for which market prices are not available, a model to estimate forward price curves is utilized. Avista Energy reports the net margin on derivative commodity instruments held for trading as operating revenues. Revenues from contracts that are not derivatives under SFAS No. 133, as well as derivative commodity instruments not held for trading, are reported on a gross basis in operating revenues. Costs from contracts, which are not derivatives under SFAS No. 133 and derivative instruments not held for trading, are reported on a gross basis in resource costs. Contracts in a receivable position, as well as the options held, are reported as assets. Similarly, contracts in a payable position, as well as options written, are reported as liabilities. Net cash flows are recognized in the period of settlement.

Avista Energy has implemented hedge accounting in accordance with SFAS No. 133. Specific natural gas and electric trading derivative contracts have been designated as hedging instruments in cash flow hedging relationships. The hedge strategies represent cash flow hedges of the variable price risk associated with expected purchases of natural gas and sales of electricity. These designated hedging instruments represent hedges of variable price exposures generated from certain contracts, which do not qualify as derivatives under SFAS No. 133. For all derivatives designated as cash flow hedges, Avista Energy documents the relationship between the hedging instrument and the hedged item (forecasted purchases and sales of power and natural gas), as well as the risk management objective and strategy for using the hedging instrument. Avista Energy assesses whether a change in the value of the designated derivative is highly effective in achieving offsetting cash flows attributable to the hedged item, both at the inception of the hedge and on an ongoing basis. Any changes in the fair value of the designated derivative that are effective are recorded in accumulated other comprehensive income or loss, while changes in fair value that are not effective are recognized currently in earnings as operating revenues. Amounts recorded in accumulated other comprehensive income or loss are recognized in earnings during the period that the hedged items are recognized in earnings.

The following table presents activity related to Avista Energy’s hedge accounting during the three months ended March 31 (dollars in thousands):

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The following table presents the net gain (loss), net of tax, related to Avista Energy’s cash flow hedges as of March 31, 2005 and December 31, 2004 (dollars in thousands):

Avista Energy expects to recognize a loss of $1.4 million in earnings during the next 12 months, related to amounts currently in accumulated other comprehensive loss. The actual amounts that will be recognized in earnings during the next 12 months will vary from the expected amounts as a result of changes in market prices. The maximum term of the designated hedging instruments was 12 months.

Contract Amounts and Terms Under Avista Energy’s derivative instruments, Avista Energy either (i) as “fixed price payor,” is obligated to pay a fixed price or a fixed amount and is entitled to receive the commodity or a fixed amount, (ii) as “fixed price receiver,” is entitled to receive a fixed price or a fixed amount and is obligated to deliver the commodity or pay a fixed amount, (iii) as “index price payor,” is obligated to pay an indexed price or an indexed amount and is entitled to receive the commodity or a variable amount or (iv) as “index price receiver,” is entitled to receive an indexed price or amount and is obligated to deliver the commodity or pay a variable amount.

The contract or notional amounts and terms of Avista Energy’s derivative commodity instruments outstanding as of March 31, 2005 are set forth below (in thousands of mmBTUs and MWhs):

The weighted average term of Avista Energy’s electric derivative commodity instruments as of March 31, 2005 was approximately 8 months. The weighted average term of Avista Energy’s natural gas derivative commodity instruments as of March 31, 2005 was approximately 6 months.

Estimated Fair Value The estimated fair value of Avista Energy’s derivative commodity instruments outstanding as of March 31, 2005, and the average estimated fair value of those instruments held during the three months ended March 31, 2005, are set forth below (dollars in thousands):

The change in the estimated fair value position of Avista Energy’s energy commodity portfolio, net of reserves for credit and market risk for the three months ended March 31, 2005 was an unrealized loss of $17.5 million and is included in the Consolidated Statements of Income in operating revenues. The change in the fair value position for the three months ended March 31, 2004 was an unrealized gain of $6.6 million.

NOTE 6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

The Company has a defined benefit pension plan covering substantially all of its regular full-time employees at Avista Utilities and Avista Energy. Individual benefits under this plan are based upon the employee’s years of service and average compensation as specified in the plan. The Company’s funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not

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more than the maximum amounts that are currently deductible for income tax purposes. The Company made $15 million in cash contributions to the pension plan in 2004. The Company expects to contribute approximately $15 million to the pension plan in 2005 ($3.75 million was contributed during the three months ended March 31, 2005).

The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services.

The Company uses a December 31 measurement date for its pension and postretirement plans.

The following table sets forth the components of net periodic benefit costs for the three months ended March 31 (dollars in thousands):

NOTE 7. LONG-TERM DEBT

The following details the interest rate and maturity dates of long-term debt outstanding as of March 31, 2005 and December 31, 2004 (dollars in thousands):

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In January and February 2005, the Company redeemed the following debt securities: $5.0 million of Secured Medium-Term Notes scheduled to mature in 2018; $11.0 million of Secured Medium-Term Notes scheduled to mature in 2023; $5.0 million Unsecured Medium-Term Notes scheduled to mature in 2022; and $5.0 million of Unsecured Medium-Term Notes scheduled to mature in 2023. In accordance with regulatory accounting practices, the total net premium on the redemption of debt of $0.8 million will be amortized over the average remaining maturity of outstanding debt.

NOTE 8. SHORT-TERM BORROWINGS

On December 17, 2004, the Company entered into a five-year committed line of credit with various banks in the amount of $350.0 million with an expiration date of December 16, 2009. This committed line of credit replaced a $350.0 million committed line of credit with a 364-day term that had an expiration date of May 5, 2005. As of March 31, 2005 and December 31, 2004, the Company had $74.0 million and $68.0 million, respectively, of borrowings outstanding under this committed line of credit. The Company can request the issuance of up to $150.0 million in letters of credit under the committed line of credit. As of March 31, 2005 and December 31, 2004, there were $26.1 million and $32.8 million in letters of credit outstanding, respectively. The committed line of credit is secured by $350.0 million of non-transferable First Mortgage Bonds of the Company issued to the agent bank. Such First Mortgage Bonds would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.

The committed line of credit agreement contains customary covenants and default provisions, including covenants not to permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 70 percent at the end of any fiscal quarter. As of March 31, 2005, the Company was in compliance with this covenant with a ratio of 59.4 percent. The committed line of credit also has a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the twelve-month period ending March 31, 2005 to be greater than 1.6 to 1. As of March 31, 2005, the Company was in compliance with this covenant with a ratio of 2.45 to 1.

On July 23, 2004, Avista Energy and its subsidiary, Avista Energy Canada, as co-borrowers, amended its committed credit agreement with a group of banks in the aggregate amount of $110.0 million to extend the expiration date to July 22, 2005. This committed credit facility provides for the issuance of letters of credit to secure contractual obligations to counterparties. This facility is guaranteed by Avista Capital and secured by the assets of Avista Energy and Avista Energy Canada. The maximum amount of credit extended by the banks for the issuance of letters of credit is the subscribed amount of the facility less the amount of outstanding cash advances, if any. The maximum amount of credit extended by the banks for cash advances is $30.0 million. No cash advances were outstanding as of March 31, 2005 and December 31, 2004. Letters of credit in the aggregate amount of $77.5 million and $91.3 million were outstanding as of March 31, 2005 and December 31, 2004, respectively. The cash deposits of Avista Energy at the respective banks collateralized $7.2 million and $21.5 million of these letters of credit as of March 31, 2005 and December 31, 2004, respectively, which is reflected as restricted cash on the Consolidated Balance Sheets.

The Avista Energy credit agreement contains customary covenants and default provisions, including covenants to maintain “minimum net working capital” and “minimum net worth,” as well as a covenant limiting the amount of indebtedness that the co-borrowers may incur. The credit agreement also contains covenants and other restrictions related to Avista Energy’s trading limits and positions, including VAR limits, restrictions with respect to changes in risk management policies or volumetric limits, and limits on exposure related to hourly and daily trading of electricity. Also, a reduction in the credit rating of Avista Corp. would represent an event of default under Avista Energy’s credit agreement. These covenants, certain counterparty agreements and current market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively limit the amount of cash dividends that are available for distribution to Avista Capital and ultimately to Avista Corp. Avista Energy was in compliance with the covenants of its credit agreement as of March 31, 2005.

Avista Energy is currently negotiating a renewal of its credit facility and anticipates it will be in place by the July 22, 2005 expiration date of the current credit agreement.

NOTE 9. INTEREST RATE SWAP AGREEMENTS

In July, August and December 2004, Avista Corp. entered into three forward-starting interest rate swap agreements, totaling $200.0 million, to manage the risk that changes in interest rates may affect the amount of future interest payments. These interest rate swap agreements relate to the anticipated issuances of debt to fund debt that matures in

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2007 and 2008. Under the terms of these agreements, the value of the interest rate swaps are determined based upon Avista Corp. paying a fixed rate and receiving a variable rate based on LIBOR for a term of seven years beginning in 2007 and a term of ten years beginning in 2008. The interest rate swap agreements provide for mandatory cash settlement of these contracts in 2008 and 2009. These interest rate swap agreements are considered hedges against fluctuations in future cash flows associated with changes in interest rates in accordance with SFAS No. 133. As of March 31, 2005, Avista Corp. had a derivative liability of $6.0 million. An unrealized gain of $0.3 million (net of taxes of $0.2 million) was recorded in other comprehensive loss for the three months ended March 31, 2005. As of March 31, 2005, there was an unrealized loss of $3.9 million recorded as accumulated other comprehensive loss on the Consolidated Balance Sheets. The Company may request regulatory accounting orders to defer the impact of unrealized gains and losses. If such accounting orders were obtained, the Company would record a regulatory asset or liability, which would eliminate the effect of any unrealized gains and losses on these interest rate swap agreements in the Consolidated Statements of Comprehensive Income. If regulatory accounting orders are not obtained prior to the mandatory cash settlements in 2008 and 2009, the amount included in accumulated other comprehensive income or loss at the cash settlement date will be reclassified to unamortized debt expense in accordance with regulatory accounting practices under SFAS No. 71. This gain or loss will be amortized over the remaining life of the forecasted debt issued.

Rathdrum Power, LLC (RP LLC), an unconsolidated entity that is 49 percent owned by Avista Power, operates a 270 MW natural gas-fired combustion turbine plant in northern Idaho (Lancaster Project). Avista Power’s investment in RP LLC, which is included in non-utility properties and investments-net on the Consolidated Balance Sheets is accounted for under the equity method and totaled $18.7 million as of March 31, 2005. As of March 31, 2005, RP LLC had $114.6 million of debt outstanding that is not included in the consolidated financial statements of the Company. There is no recourse to the Company with respect to this debt. RP LLC has entered into two interest rate swap agreements, maturing in 2006, to manage the risk that changes in interest rates may affect the amount of future interest payments. RP LLC agreed to pay fixed rates of interest with the differential paid or received under the interest rate swap agreements recognized as an adjustment to interest expense. These interest rate swap agreements are considered hedges against fluctuations in future cash flows associated with changes in interest rates in accordance with SFAS No. 133. The fair value of the interest rate swap agreements was determined by reference to market values obtained from various third party sources. As of March 31, 2005, there was an unrealized loss of $0.4 million recorded as accumulated other comprehensive loss on the Consolidated Balance Sheets.

NOTE 10. EARNINGS PER COMMON SHARE

The following table presents the computation of basic and diluted earnings per common share for the three months ended March 31 (in thousands, except per share amounts):

Total stock options outstanding that were not included in the calculation of diluted earnings per common share were 729,100 and 765,800 for the three months ended March 31, 2005 and 2004, respectively. These stock options were excluded from the calculation because they were antidilutive based on the fact that the exercise price of the stock options was higher than the average market price of Avista Corp. common stock during the respective period.

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NOTE 11. COMMITMENTS AND CONTINGENCIES

In the course of its business the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. With respect to these proceedings, the Company intends to vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter. In addition to issues specifically identified in this Note and with respect to matters that affect the regulated utility operations, the Company intends to seek, to the extent appropriate, regulatory approval of recovery of incurred costs through the ratemaking process.

Federal Energy Regulatory Commission Inquiry

On April 19, 2004, the Federal Energy Regulatory Commission (FERC) issued an order approving the contested Agreement in Resolution of Section 206 Proceeding (Agreement in Resolution) reached by Avista Corp. doing business as Avista Utilities, Avista Energy and the FERC’s Trial Staff with respect to an investigation into the activities of Avista Utilities and Avista Energy in western energy markets during 2000 and 2001. In the Agreement in Resolution, the FERC Trial Staff stated that its investigation found: (1) no evidence that any executives or employees of Avista Utilities or Avista Energy knowingly engaged in or facilitated any improper trading strategy; (2) no evidence that Avista Utilities or Avista Energy engaged in any efforts to manipulate the western energy markets during 2000 and 2001; and (3) that Avista Utilities and Avista Energy did not withhold relevant information from the FERC’s inquiry into the western energy markets for 2000 and 2001. As part of the Agreement in Resolution, Avista Utilities agreed to continue to record conversations of energy traders for two years and to improve its account settlement process. Avista Utilities and Avista Energy agreed to maintain an annual training program on the applicable FERC Code of Conduct for all employees engaged in the trading of electric energy and capacity. The Agreement in Resolution imposes no monetary remedies or penalties against Avista Utilities or Avista Energy. On May 19, 2004, the City of Tacoma and California Parties (the Office of the Attorney General, the California Public Utilities Commission (CPUC), and the California Electricity Oversight Board, filing jointly) filed requests for rehearing with respect to the FERC’s April 19, 2004 order. On September 28, 2004, the State of Montana filed a motion to intervene in these proceedings. On April 19, 2005, the FERC denied the rehearing requests of the City of Tacoma and California Parties, and denied the State of Montana’s motion to intervene. The City of Tacoma and California Parties have 60 days to appeal the FERC’s decisions. Based on the FERC’s order approving the Agreement in Resolution and the FERC’s denial of rehearing requests and motion to intervene, the Company does not expect that this proceeding will have any material adverse effect on its financial condition, results of operations or cash flows.

Class Action Securities Litigation

On September 27, 2002, Ronald R. Wambolt filed a class action lawsuit in the United States District Court for the Eastern District of Washington against Avista Corp., Thomas M. Matthews, the former Chairman of the Board, President and Chief Executive Officer of the Company, Gary G. Ely, the current Chairman of the Board, President and Chief Executive Officer of the Company, and Jon E. Eliassen, the former Senior Vice President and Chief Financial Officer of the Company. In October and November 2002, Gail West, Michael Atlas and Peter Arnone filed similar class action lawsuits in the same court against the same parties. On February 3, 2003, the court issued an order consolidating the complaints under the name “In re Avista Corp. Securities Litigation,” and on February 7, 2003 appointed the lead plaintiff and co-lead counsel. On August 19, 2003, the plaintiffs filed their consolidated amended class action complaint in the same court against the same parties. In their complaint, the plaintiffs continue to assert violations of the federal securities laws in connection with alleged misstatements and omissions of material fact pursuant to Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. The plaintiffs allege that the Company did not have adequate risk management processes, procedures and controls. The plaintiffs further allege that the Company engaged in unlawful energy trading practices and allegedly manipulated western power markets. The plaintiffs assert that alleged misstatements and omissions regarding these matters were made in the Company’s filings with the Securities and Exchange Commission and other information made publicly available by the Company, including press releases. The class action complaint asserts claims on behalf of all persons who purchased, converted, exchanged or otherwise acquired the Company’s common stock during the period between November 23, 1999 and August 13, 2002. The Company filed a motion to dismiss this complaint in October 2003 and the plaintiffs filed an answer to this motion in January 2004. Arguments before the Court on the motion were held on March 19, 2004. On April 15, 2004, the Court called for additional briefing on what effect, if any, the FERC proceedings (see “Federal Energy Regulatory Commission Inquiry” above) have on this case. On July 30, 2004, the Court denied the Company’s motion to dismiss this complaint, holding, among other things, that the FERC proceedings may ultimately have some evidentiary value relevant to the disclosure issues raised in this case, but they

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do not preclude the resolution of those issues by the Court. In November 2004, the Company filed its answer to the complaint denying the plaintiffs’ allegations. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Counterparty Defaults

In 2001, Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) defaulted on payment obligations to the California Power Exchange (CalPX) and the California Independent System Operator (CalISO). As a result, the CalPX and the CalISO failed to pay various energy sellers, including Avista Energy. Both PG&E and the CalPX declared bankruptcy in 2001. In March 2002, SCE paid its defaulted obligations; however the funds SCE paid the CalPX have yet to be released to energy sellers. In April 2004, PG&E paid its defaulted obligations into an escrow fund in accordance with its bankruptcy reorganization. Funds held by the CalPX and in the PG&E escrow fund are not subject to release until the FERC issues an order directing such release in the California Refund Proceeding (see discussion below). As of March 31, 2005, Avista Energy’s accounts receivable outstanding related to defaulting parties in California were fully offset by reserves for uncollected amounts and funds collected from defaulting parties. Avista Energy continues to defend itself in the California Refund Proceeding and pursue recovery of the defaulted obligations. Because the resolution of these defaulted obligations by counterparties remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability for potential refunds beyond the defaulted obligations. However, based on information currently known to the Company’s management, the Company does not expect that the resolution of these defaulted obligations will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

California Refund Proceeding

In July 2001, the FERC ordered an evidentiary hearing to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the CalISO and the CalPX during the period from October 2, 2000 to June 20, 2001 in the California power market. The refunds were based on the development of a mitigated market clearing price methodology. If the refunds required by the formula would cause a seller to recover less than its actual costs for the refund period, the FERC has held that the seller would be allowed in the future to document these costs and limit its refund liability commensurately. The FERC administrative law judge’s findings were certified in December 2002. In March 2003, the FERC reviewed the administrative law judge’s rulings, adopting many of his findings. The CalISO continues its efforts to prepare revised settlement statements based on newly recalculated costs and charges for spot market sales to California during the refund period and currently estimates that it will make its compliance filing showing “who owes what to whom” by October 1, 2005. In January 2005, Avista Energy made filings responding to the FERC’s invitation to comment on the proper approach governing revenue shortfall studies that the FERC has determined may be filed by sellers in these proceedings. Avista Energy is currently awaiting the FERC’s action on that issue.

In addition, in June 2003, the FERC issued an order to review bids above $250 per MW made by participants in the short-term energy markets operated by the CalISO and the CalPX from May 1, 2000 to October 2, 2000. Market participants with bids above $250 per MW during the period described above have been required to demonstrate why their bidding behavior and practices did not violate applicable market rules. If violations were found to exist, the FERC would require the refund of any unjust profits and could also enforce other non-monetary penalties, such as the revocation of market-based rate authority. Avista Energy was subject to this review. In May 2004, the FERC provided notice that Avista Energy was no longer subject to this investigation. In March 2005, the California Parties appealed the FERC’s decision before the United States Court of Appeals for the Ninth Circuit. In addition, many of the other orders that the FERC has issued in the California refund proceedings are now on appeal before the Ninth Circuit. Some of those issues have been consolidated as a result of a case management conference conducted in September 2004. In October 2004, the Ninth Circuit ordered that briefing proceed in two rounds. The first round is limited to three issues: (1) which parties are subject to the FERC’s refund jurisdiction in light of the exemption for government-owned utilities in section 201(f) of the Federal Power Act (FPA); (2) the temporal scope of refunds under section 206 of the FPA; and (3) which categories of transactions are subject to refunds. Oral argument on those issues took place in April 2005. The second round of issues and their corresponding briefing schedules have not yet been set by Ninth Circuit Court of Appeals. Because the resolution of the California refund proceeding remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability.

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However, based on information currently known to the Company’s management, the Company does not expect that the California refund proceeding will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Pacific Northwest Refund Proceeding

In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market sales in the Pacific Northwest between December 25, 2000 to June 20, 2001 were just and reasonable. During the hearing, Avista Utilities and Avista Energy vigorously opposed claims that Pacific Northwest markets were dysfunctional, that rates for spot market sales were unjust and unreasonable and that the imposition of refunds would be appropriate. In September 2001, the FERC’s Administrative Law Judge presiding over the evidentiary hearing issued a decision favorable to the Company’s position and recommended that the FERC not order refunds and instead dismiss the entire proceeding. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of refunds. In November 2003, the FERC affirmed its order. Seven petitions for review, including one filed by Puget Sound Energy, Inc. (Puget), are now pending before the United States Court of Appeals for the Ninth Circuit. Opening briefs were filed in January 2005. Puget’s brief is directed to the procedural flaws in the underlying docket. Puget argues that because its complaint was withdrawn as a matter of law in July 2001, the FERC erred in relying on it to serve as the basis to initiate the preliminary investigation into whether refunds for individually negotiated bilateral transactions in the Pacific Northwest were appropriate. In February 2005, intervening parties, including Avista Energy and Avista Utilities, filed in support of Puget. Briefing is expected to be completed in May 2005. Because the resolution of the Pacific Northwest refund proceeding remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that the Pacific Northwest refund proceeding will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Reliant Energy, Inc. and Duke Energy Corporation Cross-Complaints

In April 2002, several subsidiaries of Reliant Energy, Inc. (Reliant) and Duke Energy Corporation (Duke) filed cross-complaints against Avista Energy and numerous other participants in the California energy markets. The cross-complaints seek indemnification for any liability that may arise from original complaints filed against Reliant and Duke with respect to charges of unlawful and unfair business practices in the California energy markets under California law. In June 2002, Avista Energy filed motions to dismiss the cross-complaints. In the meantime, the U.S. District Court remanded the case to California State Court, which remand is itself the subject of an appeal to the United States Court of Appeals for the Ninth Circuit. In December 2004, the Ninth Circuit issued its opinion affirming the U.S. District Court’s remand of these cases to California State Court, and a rehearing request was denied on March 3, 2005. On March 10, 2005, the Ninth Circuit’s mandate, remanding the case to state court, was issued. Although cross-defendant Powerex Corp. filed a motion to recall mandate, asking that the Ninth Circuit recall its mandate until a petition for certiorari seeking review of this case by the United States Supreme Court is filed and ruled upon by the Supreme Court, the Ninth Circuit denied the request. Once the case is returned to the California State Court, Avista Energy intends to re-file the motion to dismiss, which was previously filed in U.S. District Court in June 2002, as a demurrer in California State Court. At this time, the Company cannot predict the outcome of the cross-complaints or the original complaints filed against Reliant and Duke or provide an estimate of any potential liability to Avista Energy with respect to the cross-complaints. However, based on information currently known to the Company’s management, the Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

California Attorney General Complaint

In May 2002, the FERC conditionally dismissed a complaint filed in March 2002 by the Attorney General of the State of California (California AG) that alleged violations of the Federal Power Act by the FERC and all sellers (including Avista Corp. and its subsidiaries) of electric power and energy into California. The complaint alleged that the FERC’s adoption and implementation of market-based rate authority was flawed and, as a result, individual sellers were liable for sales of energy at rates that were “unjust and unreasonable.” In May 2002, the FERC issued an order dismissing the complaint but directing sellers to re-file certain transaction summaries. It was not clear that Avista Corp. and its subsidiaries were subject to this directive but the Company took the conservative approach and re-filed certain transaction summaries in June and July of 2002. In July 2002, the California AG requested a

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rehearing on the FERC order, which request was denied in September 2002. Subsequently, the California AG filed a Petition for Review of the FERC’s decision with the United States Court of Appeals for the Ninth Circuit. In September 2004, the United States Court of Appeals for the Ninth Circuit upheld the FERC’s market-based rate authority, but found the requirement that all sales at market-based rates be contained in quarterly reports filed with the FERC to be integral to a market-based rate tariff. The California AG has interpreted the decision as providing authority to the FERC to order refunds in the California refund proceeding for an expanded refund period. The Court’s decision leaves to the FERC the determination as to whether refunds are appropriate. In October 2004, Avista Energy joined with others in seeking rehearing of the Court’s decision to remand the case back to the FERC for further proceedings. The Ninth Circuit has yet to rule on the request for rehearing. Based on information currently known to the Company’s management, the Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Port of Seattle Complaint

In May 2003, a complaint was originally filed by the Port of Seattle in the United States District Court for the Western District of Washington against numerous companies, including Avista Corp., Avista Energy, Inc. and Avista Power, LLC (collectively the Avista defendants), seeking compensatory and treble damages for alleged violations of the Sherman Act and the Racketeer Influenced and Corrupt Organization Act by transmitting, via wire communications, false information intended to increase the price of power, knowing that others would rely upon such information. The complaint alleged that the defendants and others knowingly devised and attempted to devise a scheme to defraud and to obtain money and property from electricity customers throughout the Western Electricity Coordinating Council (WECC), by means of false and fraudulent pretenses, representations and promises. The alleged purpose of the scheme was to artificially increase the price that the defendants received for their electricity and ancillary services, to receive payments for services they did not provide and to manipulate the price of electricity throughout the WECC. In August 2003, the Avista defendants filed a motion to dismiss this complaint. A transfer order was granted, which moved this case to the United States District Court for the Southern District of California to consolidate it with other pending actions. Arguments with respect to the motions to dismiss filed by the Avista defendants and other defendants were heard on March 26, 2004. On May 12, 2004, the United States District Court for the Southern District of California granted motions to dismiss filed by the Avista defendants, as well as other defendants, with respect to this complaint. The Court dismissed the complaint because it determined that it was without jurisdiction to hear the plaintiff’s claims, based on, among other things, the exclusive jurisdiction of the FERC and the filed-rate doctrine. On May 27, 2004, the Port of Seattle filed an appeal with the United States Court of Appeals for the Ninth Circuit. This matter has been briefed and awaits oral argument. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Wah Chang Complaint

On May 5, 2004, Wah Chang, a division of TDY Industries, Inc. (a subsidiary of Allegheny Technologies, Inc.), filed a complaint in the United States District Court for the District of Oregon against numerous companies, including Avista Corp., Avista Energy and Avista Power. The complaint seeks compensatory and treble damages for alleged violations of the Sherman Act, the Racketeer Influenced and Corrupt Organization Act, as well as violations of Oregon state law. According to the complaint, from September 1997 to September 2002, the plaintiff purchased electricity from PacifiCorp pursuant to a contract that was indexed to the spot wholesale market price of electricity. The plaintiff alleges that the defendants, acting in concert among themselves and/or with Enron Corporation and certain affiliates thereof (collectively, Enron) and others, engaged in a scheme to defraud electricity customers by transmitting false market information in interstate commerce in order to artificially increase the price of electricity provided by them, to receive payment for services not provided by them and to otherwise manipulate the market price of electricity, and by executing wash trades and other forms of market manipulation techniques and sham transactions. The plaintiff also alleges that the defendants, acting in concert among themselves and/or with Enron and others, engaged in numerous practices involving the generation, purchase, sale, exchange, scheduling and/or transmission of electricity with the purpose and effect of causing a shortage (or the appearance of a shortage) in the generation of electricity and congestion (or the appearance of congestion) in the transmission of electricity, with the ultimate purpose and effect of artificially and illegally fixing and raising the price of electricity in California and throughout the Pacific Northwest. As a result of the defendants’ alleged conduct, the plaintiff allegedly suffered damages of not less than $30 million through the payment of higher electricity prices. In September 2004, this case

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was transferred to the United States District Court for the Southern District of California for consolidation with other pending actions. In October 2004, the Avista defendants joined with other defendants in filing a joint motion to dismiss the complaint. In February 2005, the Court dismissed the complaint because it determined that it was without jurisdiction to hear the plaintiff’s complaint, based on, among other things, the exclusive jurisdiction of the FERC and the filed-rate doctrine. In March 2005, Wah Chang filed an appeal with the United States Court of Appeals for the Ninth Circuit. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

City of Tacoma Complaint

On June 7, 2004, the City of Tacoma, Department of Public Utilities, Light Division, a Washington municipal corporation (Tacoma Power), filed a complaint in the United States District Court for the Western District of Washington against over fifty companies, including Avista Corp., Avista Energy and Avista Power. According to the complaint, Tacoma Power distributes electricity to customers in Tacoma, and Pierce County, Washington, generates electricity at several facilities in western Washington and purchases power under supply contracts and in the Northwest spot market. Tacoma Power’s complaint seeks compensatory and treble damages from alleged violations of the Sherman Act. Tacoma Power alleges that the defendants, acting in concert, engaged in a pattern of activities that had the purpose and effect of creating the impressions that the demand for power was higher, the supply of power was lower, or both, than was in fact the case. This allegedly resulted in an artificial increase of the prices paid for power sold in California and elsewhere in the western United States during the period from May 2000 through the end of 2001. Due to the alleged unlawful conduct of the defendants, Tacoma Power allegedly paid an amount estimated to be $175.0 million in excess of what it would have paid in the absence of such alleged conduct. In September 2004, this case was transferred to the United States District Court for the Southern District of California for consolidation with other pending actions. In February 2005, the Court granted the defendants’ motion to dismiss this complaint for similar reasons to those expressed by the Court in the Wah Chang complaint described above. In March 2005, Tacoma Power filed an appeal with the United States Court of Appeals for the Ninth Circuit. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Public Utility District No. 1 of Snohomish County

On November 5, 2004, Public Utility District No. 1 of Snohomish County filed a Petition For a Writ of Certiorari with the United States Supreme Court, requesting the Court to consider whether the filed rate doctrine applies for market-based rates so as to preempt state law antitrust and consumer fraud actions based upon alleged fraud and manipulation of electricity markets operated under market-based rate tariffs. This petition seeks review of the decision of the United States Court of Appeals for the Ninth Circuit on September 10, 2004, which held that the filed rate doctrine and field and conflict preemptions bar such actions. Seventeen states have urged the United States Supreme Court to grant the petition. On February 22, 2005, the Court invited the Solicitor General to provide the Court with the views of the United States. Although, this case does not directly involve Avista Corp. and its subsidiaries, the outcome could have a bearing on pending litigation and regulatory proceedings affecting Avista Corp. and its subsidiaries discussed above.

State of Montana Proceedings

On June 30, 2003, the Attorney General of the State of Montana (Montana AG) filed a complaint in the Montana District Court on behalf of the people of Montana and the Flathead Electric Cooperative, Inc. against numerous companies, including Avista Corp. The complaint alleges that the companies illegally manipulated western electric and natural gas markets in 2000 and 2001. This case was subsequently moved to the United States District Court for the District of Montana; however, it has since been remanded back to the Montana District Court. No further action has been made with respect to this complaint.

The Montana AG also petitioned the Montana Public Service Commission (MPSC) to fine public utilities $1,000 a day for each day it finds they engaged in alleged “deceptive, fraudulent, anticompetitive or abusive practices” and order refunds when consumers were forced to pay more than just and reasonable rates. On February 12, 2004, the MPSC issued an order initiating investigation of the Montana retail electricity market for the purpose of determining

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whether there is evidence of unlawful manipulation of that market. The Montana AG has requested specific information from Avista Energy and Avista Corp. regarding their transactions within the State of Montana during the period from January 1, 2000 through December 31, 2001.

Because the resolution of these proceedings remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that these proceedings will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Montana Public School Trust Fund Lawsuit

In October 2003, a lawsuit was filed by Richard Dolan and Denise Hayman in the United States District Court for the District of Montana against all private owners of hydroelectric dams in Montana, including Avista Corp. The lawsuit alleges that the hydroelectric facilities are located on state-owned riverbeds and the owners have never paid compensation to the state’s public school trust fund. The lawsuit requests lease payments dating back to the construction of the respective dams and also requests damages for trespassing and unjust enrichment. An Amended Complaint adding Great Falls Elementary School District No. 1 and Great Falls High School District 1A was filed on January 16, 2004. On February 2, 2004, the Company filed its motion to dismiss this lawsuit; PacifiCorp and PPL Montana, as the other named defendants also filed a motion to dismiss, or joined therein. On May 10, 2004, the Montana AG filed a complaint on behalf of the state to join in this lawsuit to allegedly protect and preserve state lands/school trust lands from use without compensation. On July 19, 2004, the defendants (including Avista Corp.) filed a motion to dismiss the Montana AG’s complaint. On September 29, 2004, the Court granted the motion to dismiss filed with respect to plaintiffs Richard Dolan, Denise Hayman and the school districts. However, the motion to dismiss the Montana AG’s complaint was denied, citing, among other things, that the FERC does not have exclusive jurisdiction over this matter. Subsequently, in response to the motions of the defendants, the federal magistrate judge on January 19, 2005, filed recommendations that the federal court order on the merits be vacated based on lack of jurisdiction of the Court. On November 12, 2004, the defendants (including Avista Corp.) filed a petition for declaratory relief in Montana State Court requesting the resolution of the controversy that the plaintiffs raised in federal court. On November 24, 2004, the Montana AG filed an answer, counterclaim and motion for summary judgment. The defendants have filed responses to the Montana AG’s motion for summary judgment. The Montana State Court has scheduled a hearing in June 2005 on the motions. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Colstrip Generating Project Complaint

In May 2003, various parties (all of which are residents or businesses of Colstrip, Montana) filed a consolidated complaint against the owners of the Colstrip Generating Project (Colstrip) in Montana District Court. Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrip. The plaintiffs allege damages to buildings as a result of rising ground water, as well as damages from contaminated waters leaking from the lakes and ponds of Colstrip. The plaintiffs are seeking punitive damages, an order by the court to remove the lakes and ponds and the forfeiture of all profits earned from the generation of Colstrip. The Company intends to work with the other owners of Colstrip in defense of this complaint. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Environmental Protection Agency Administrative Compliance Order

In December 2003, PPL Montana, LLC, as operator of Colstrip, received an Administrative Compliance Order (ACO) from the Environmental Protection Agency (EPA) pursuant to the Clean Air Act (CAA). The ACO alleges that Colstrip Units 3 & 4 have been in violation of the CAA permit at Colstrip since 1980. The permit required Colstrip to submit for review and approval by the EPA an analysis and proposal for reducing emissions of nitrogen oxides to address visibility concerns if, and when, EPA promulgates Best Available Retrofit Technology requirements for nitrogen oxide emissions. The EPA is asserting that regulations it promulgated in 1980 triggered this requirement. Avista Utilities and PPL Montana, LLC believe that the ACO is unfounded and PPL Montana,

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LLC is discussing the matter with the EPA. The ACO does not expressly seek penalties, and it is unclear at this time what, if any, additional control technology the EPA may consider to be required. Accordingly, the costs to install any additional controls for nitrogen oxides, if required, cannot be estimated at this time. In addition, the Montana Department of Environmental Quality (Montana DEQ) is questioning whether the permit limits for sulfur dioxide emissions from Colstrip Units 3 & 4 are too high under provisions of the CAA that limit allowable emissions from sources built after 1978. The owners of Colstrip are engaged in settlement negotiations on these matters with the EPA, the Montana DEQ and the Northern Cheyenne Tribe. Because the resolution of this issue remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this issue will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Colstrip Royalty Claim

The Western Energy Company (WECO) supplies coal to the owners of Colstrip Units 3 & 4 under a Coal Supply Agreement and a Transportation Agreement. The Minerals Management Service (MMS) of the United States Department of the Interior issued an order to WECO to pay additional royalties concerning coal delivered to Colstrip Units 3 & 4 via the conveyor belt (approximately 4.46 miles long). The owners of Colstrip Units 3 & 4 take delivery of the coal at the western end (beginning) of the conveyor belt. The order asserts that additional royalties are owed MMS as a result of WECO not paying royalties in connection with revenue received by WECO from the owners of Colstrip Units 3 & 4 under the Transportation Agreement during the period October 1, 1991 through December 31, 2001. WECO’s appeal to the MMS was substantially denied in March 2005; WECO has now appealed the order to the Board of Land Appeals of the U.S. Department of the Interior. The entire appeal process could take several years to resolve. The owners of Colstrip Units 3 & 4 are monitoring the appeal process between WECO and MMS.

WECO has indicated to the owners of Colstrip Units 3 & 4 that if WECO is unsuccessful in the appeal process, WECO will seek reimbursement of any royalty payments by passing these costs through the Coal Supply Agreement. The owners of Colstrip Units 3 & 4 advised WECO that their position would be that these claims are not allowable costs per the Coal Supply Agreement nor the Transportation Agreement in the event the owners of Colstrip Units 3 & 4 were invoiced for these claims. Because the resolution of this issue remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this issue will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Hamilton Street Bridge Site

A portion of the Hamilton Street Bridge Site in Spokane, Washington (including a former coal gasification plant site that operated for approximately 60 years until 1948) was acquired by the Company through a merger in 1958. The Company no longer owns the property. In January 1999, the Company received notice from the State of Washington’s Department of Ecology (DOE) that it had been designated as a potentially liable party (PLP) with respect to any hazardous substances located on this site, stemming from the Company’s past ownership of the former gas plant site. In its notice, the DOE stated that it intended to complete an on-going remedial investigation of this site, complete a feasibility study to determine the most effective means of halting or controlling future releases of substances from the site, and to implement appropriate remedial measures. The Company responded to the DOE acknowledging its listing as a PLP, but requested that additional parties also be listed as PLPs. In the spring of 1999, the DOE named two other parties as additional PLPs.

The DOE, the Company and another PLP, Burlington Northern & Santa Fe Railway Co. (BNSF), signed an Agreed Order in March 2000 that provided for the completion of a remedial investigation and a feasibility study. The work to be performed under the Agreed Order includes three major technical parts: completion of the remedial investigation; performance of a focused feasibility study; and implementation of an interim groundwater monitoring plan. During the second quarter of 2000, the Company received comments from the DOE on its initial remedial investigation, and then submitted another draft of the remedial investigation, which was accepted as final by the DOE. After responding to comments from the DOE, the feasibility study was accepted by the DOE during the fourth quarter of 2000. After receiving input from the Company and the other PLPs, the final Cleanup Action Plan (CAP) was issued by the DOE in August 2001. In September 2001, the DOE issued an initial draft Consent Decree for the PLPs to review. During the first quarter of 2002, the Company and BNSF signed a cost sharing agreement. In September 2002, the Company, BNSF and the DOE finalized the Consent Decree to implement the CAP. The third

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PLP has indicated it will not sign the Consent Decree. It is currently estimated that the Company’s share of the costs will be less than $1.0 million. The Engineering and Design Report for the CAP was submitted to the DOE in January 2003 and approved by the DOE in May 2003. Work under the CAP commenced during the second quarter of 2003. In September 2004, a Site Preparation Agreement was reached with the third PLP with respect to the logistics of the CAP. Under this agreement, the third PLP will have the site preparation completed by mid-2005 and work under the CAP will be completed by late 2005.

Spokane River

In March 2001, the DOE informed Avista Development, a subsidiary of Avista Capital, of a health advisory concerning PCBs found in fish caught in a portion of the Spokane River. In June 2001, Avista Development received official notice that it had been designated as a PLP with respect to contaminated sites on the Spokane River. The DOE discovered PCBs in fish and sediments in the Spokane River in the 1970s and 1980s. In the 1990s, the DOE performed subsequent sampling of the river and identified potential sources of the PCBs, including the Spokane Industrial Park (SIP) and a number of other entities in the area. The SIP, renamed Pentzer Development Corporation (Pentzer Development) in 1990, operated a wastewater treatment plant at the site until it was closed in December 1993. The SIP’s treatment plant discharged to the Spokane River under the terms of a National Pollutant Discharge Elimination System permit issued by the DOE. Pentzer Development sold the property in 1996 and merged with Avista Development in 1998. Avista Development filed a response to this notice in August 2001. In December 2001, the DOE confirmed Avista Development’s status as a PLP and named at least two other PLPs in this matter. In April 2003, the DOE released its study of wastewater and sludge handling from facilities owned by a fourth PLP. The DOE study indicated that the fourth PLP continued to discharge PCBs into the Spokane River. The DOE issued the fourth PLP a final notice of participation as a PLP on April 30, 2003.

During the fourth quarter of 2002, Avista Development and one other PLP, Kaiser Aluminum & Chemical Corporation (Kaiser), finalized the Consent Decree and Scope of Work for the remedial investigation and feasibility study of the site, which was formally entered into Spokane County Superior Court in January 2003. The other PLPs have not been participating in the process. As directed by Avista Development and Kaiser, the field-work for the remedial investigation began in April 2003 and was completed by the end of 2003 with a draft remedial investigation report and feasibility study technical memorandum submitted to the DOE in March 2004. In December 2004, the Company and Kaiser filed the draft final remedial investigation and feasibility study with the DOE. In March 2005, the DOE issued its draft Cleanup Action Plan (CAP), which was materially consistent with the draft final feasibility study filed by the Company and Kaiser. The draft CAP was open for public review and comment, along with the draft final remedial investigation and feasibility study and the state cleanup consent decree until May 6, 2005.

The Company has entered into a tentative settlement with the DOE and Kaiser relating to the remediation of the site. Under the tentative agreement, the Company will perform the selected remedial action. Kaiser, which is presently operating under bankruptcy protection, has agreed to pay the Company approximately 50 percent of the current estimate of the total costs, which will be used by the Company to fund the costs of the remediation. The tentative settlement is subject to the right of the DOE to withdraw from the settlement based on the public comments received, and the approval of both the bankruptcy court overseeing the Kaiser bankruptcy and the Spokane County Superior Court. During 2004, the Company accrued its share of the total estimated costs, which was not material to the Company’s consolidated financial condition or results of operations. Because of uncertainties with respect to, among other things, the final cost sharing agreement between the PLPs, Kaiser’s bankruptcy and the final cleanup action plan required by the DOE, the Company’s estimate of its liability could change in future periods. Based on information currently known to the Company’s management, the Company does not believe that such a change would be material to its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimate of the liability. Such a change, should it occur, could be significant.

Lake Coeur d’Alene

In July 1998, the United States District Court for the District of Idaho issued its finding that the Coeur d’Alene Tribe of Idaho (Tribe) owns, among other things, portions of the bed and banks of Lake Coeur d’Alene (Lake) lying within the current boundaries of the Coeur d’Alene Reservation. This action had been brought by the United States on behalf of the Tribe against the state of Idaho. The Company was not a party to this action. The United States District Court decision was affirmed by the United States Court of Appeals for the Ninth Circuit. The United States Supreme Court affirmed this decision in June 2001. This will result in, among other things, the Company being liable to the Tribe for compensation for the use of reservation lands under Section 10(e) of the Federal Power Act.

The Company’s Post Falls Hydroelectric Generating Station (Post Falls), a facility constructed in 1906 with a present capability of 18 MW, utilizes a dam on the Spokane River downstream of the Lake which controls the water level in

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the Lake for portions of the year (including portions of the lakebed owned by the Tribe). The Company has other hydroelectric facilities on the Spokane River downstream of Post Falls, but these facilities do not affect the water level in the Lake. The Company and the Tribe are engaged in discussions with respect to past and future compensation (which may include interest) for use of the portions of the bed and banks of the Lake, which are owned by the Tribe. If the parties cannot agree on the amount of compensation, the matter could result in litigation. The Company cannot predict the amount of compensation that it will ultimately pay or the terms of such payment. However, the Company intends to seek recovery of any amounts paid through the rate making process.

Spokane River Relicensing

The Company operates six hydroelectric plants on the Spokane River, and five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls) are under one FERC license and referred to herein as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. The license for the Spokane River Project expires in August 2007; the Company filed a Notice of Intent to Relicense in July 2002. The formal consultation process involving planning and information gathering with stakeholder groups has been underway since that time. The Company provided a draft license application for public comment in February 2005. The Company plans to file its license application with the FERC in July 2005. The Company intends to seek recovery of relicensing costs through the rate making process.

Clark Fork Settlement Agreement

Dissolved atmospheric gas levels exceed state of Idaho and federal water quality standards downstream of the Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement, the Company developed an abatement and mitigation strategy with the other signatories to the agreement and submitted the Gas Supersaturation Control Program (GSCP) in December 2002 for review and approval to the Idaho Department of Environmental Quality (DEQ) and the U.S. Fish and Wildlife Service. In February 2004, the Idaho DEQ and the U.S. Fish and Wildlife Service approved the GSCP. In January 2005, the FERC issued an order approving the GSCP. The GSCP provides for the opening and modification of one and, potentially, both of the two existing diversion tunnels built when Cabinet Gorge was originally constructed. Streamflows would be diverted to the tunnels when these flows are in excess of turbine capacity. The cost of modifying the first tunnel is currently preliminarily estimated to be $38 million (including AFUDC and inflation) and would be incurred between 2004 and 2010, with the majority of these costs being incurred in 2007 through 2009. The second tunnel would be modified only after evaluation of the performance of the first tunnel and such modifications would commence no later than 10 years following the completion of the first tunnel. It is currently preliminarily estimated that the costs to modify the second tunnel would be $26 million (including AFUDC and inflation). As part of the GSCP, the Company provides $0.5 million annually as mitigation for aquatic resources that might be adversely affected by high dissolved gas levels. Mitigation funds will continue until the modification of the second tunnel commences or if the second tunnel is not modified to an agreed upon point in time commensurate with the biological effects of high dissolved gas levels. The Company intends to seek recovery of the costs for the modification of Cabinet Gorge and the mitigation payments through the rate making process.

The operating license for the Clark Fork Project describes the approach to restore bull trout populations in the project areas. Using the concept of adaptive management and working closely with the U.S. Fish and Wildlife Service, the Company is evaluating the feasibility of fish passage. The results of these studies will help the Company and other parties determine the best use of funds toward continuing fish passage efforts or other fish population enhancement measures.

Other Contingencies

In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes that any ultimate liability arising from these actions will not have a material adverse impact on the Company’s financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

The Company’s collective bargaining agreement with the International Brotherhood of Electrical Workers represents approximately 50 percent of all Avista Utilities employees. The agreement with the local union in Washington and Idaho representing the majority (approximately 90 percent) of the bargaining unit employees expired on March 25, 2005. Two local agreements in Oregon, which cover approximately 50 employees, expired on March 31, 2005. Negotiations are currently ongoing with respect to the labor agreements that expired in March 2005 and the Company does not expect any disruption to its operations.

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NOTE 12. DISPOSITION OF SOUTH LAKE TAHOE PROPERTIES

In April 2005, Avista Corp. completed the sale of its South Lake Tahoe, California natural gas distribution properties to Southwest Gas Corporation as part of Avista Utilities’ strategy to focus on its business in the northwestern United States. The cash purchase price for the properties was approximately $15 million, subject to closing adjustments.

Total revenues for 2004 from the South Lake Tahoe region were approximately $20.3 million (or 6 percent of total natural gas revenues) and approximately 22.1 million therms were delivered (or 4 percent of total therms delivered) to South Lake Tahoe customers.

The Company has classified the assets of its South Lake Tahoe natural gas distribution properties as assets held for sale on the Consolidated Balance Sheets as of March 31, 2005 and December 31, 2004. These assets consist primarily of net utility property, accounts receivable and deferred natural gas costs.

NOTE 13. ACQUISITION OF REMAINING INTEREST IN COYOTE SPRINGS 2

In January 2005, Avista Corp. completed the acquisition of Mirant Oregon LLC’s 50 percent ownership interest in Coyote Springs 2 at a price of $62.5 million, which includes $5.0 million paid in 2004. Mirant Oregon LLC acquired its ownership interest in Coyote Springs 2 from the Company during construction in 2001.

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NOTE 14. INFORMATION BY BUSINESS SEGMENTS

The business segment presentation reflects the basis currently used by the Company’s management to analyze performance and determine the allocation of resources. Avista Utilities’ business is managed based on the total regulated utility operation. The Energy Marketing and Resource Management business segment primarily consists of electricity and natural gas marketing, trading and resource management including optimization of energy assets owned by other entities and derivative commodity instruments such as futures, options, swaps and other contractual arrangements. Avista Advantage is a provider of utility bill processing, payment and information services to multi-site customers throughout North America. The Other business segment includes other investments and operations of various subsidiaries as well as certain other operations of Avista Capital.

The following table presents information for each of the Company’s business segments (dollars in thousands):

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

Avista Corp. from time to time makes forward-looking statements such as statements regarding future financial performance, capital expenditures, dividends, capital structure and other financial items, including the underlying assumptions (many of which are based, in turn, upon further assumptions), as well as strategic goals and objectives and plans for future operations. Such statements are made both in Avista Corp.’s reports filed under the Securities Exchange Act of 1934, as amended (including this Quarterly Report on Form 10-Q), and elsewhere. Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those that are identified by the use of words such as, but not limited to, “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “projects,” “predicts,” and similar expressions.

All forward-looking statements (including those made in this Quarterly Report) are subject to a variety of risks and uncertainties and other factors, most of which are beyond the control of Avista Corp. and many of which could have a significant impact on Avista Corp.’s operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements. Such risks, uncertainties and other factors include, among others:

•	weather conditions, including the effect of precipitation and temperatures on the availability of hydroelectric resources and the effect of temperatures on customer demand;

•	changes in the utility regulatory environment in the individual states and provinces in which the Company operates as well as the United States and Canada in general, which can impact allowed rates of return, financings, or industry and rate structures;

•	the impact of regulatory decisions including FERC price controls, and including possible retroactive price caps and resulting refunds;

•	the potential effects of any legislation or administrative rulemaking passed into law, including any energy-related legislation passed into law by the United States Congress or the individual states in which the Company operates;

•	the impact from the potential formation of a Regional Transmission Organization;

•	the impact from the potential implementation of the FERC’s proposed wholesale power market rules;

•	the ability to relicense the Spokane River Project at a cost-effective level with reasonable terms and conditions;

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

•	changes in wholesale energy prices that can affect, among other things, the market value of derivative assets and liabilities and unrealized gains and losses, as well as cash requirements to purchase electricity and natural gas for retail customers;

•	changes in global energy markets that can affect, among other things, the price of natural gas purchased for retail customers and purchased as fuel for electric generation;

•	wholesale and retail competition (including, but not limited to, electric retail wheeling and transmission costs);

•	unplanned outages at any Company-owned generating facilities;

•	unanticipated delays or changes in construction costs with respect to present or prospective facilities;

•	natural disasters that can disrupt energy delivery;

•	changes in industrial, commercial and residential growth and demographic patterns in the Company’s service territory;

•	the loss of significant customers and/or suppliers;

•	failure to deliver on the part of any parties from which the Company purchases and/or sells capacity or energy;

•	changes in the creditworthiness of customers and energy trading counterparties;

•	the Company’s ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including the Company’s credit ratings, interest rate fluctuations and other capital market conditions;

•	the impact of any potential change in the Company’s credit ratings, including the effect on Avista Energy’s credit facility;

•	changes in future economic conditions in the Company’s service territory and the United States in general, including inflation or deflation and monetary policy;

•	changes in rapidly advancing technologies, possibly making some of the current technology quickly obsolete;

•	the potential for future terrorist attacks, particularly with respect to utility plant assets;

•	changes in tax rates and/or policies;

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

•	the outcome of legal and regulatory proceedings concerning the Company or affecting directly or indirectly its operations, including the potential disallowance of previously deferred costs;

•	employee issues, including changes in collective bargaining unit agreements, strikes, work stoppages or the loss of key executives, as well as the ability to recruit and retain employees;

•	changes in actuarial assumptions and the return on assets with respect to the Company’s pension plan, which can impact future funding obligations, costs and pension plan liabilities;

•	increasing health care costs and the resulting effect on health insurance premiums paid for employees and on the obligation to provide postretirement health care benefits; and

•	increasing costs of insurance, changes in coverage terms and the ability to obtain insurance.

The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. However, there can be no assurance that the Company’s expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. The Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the Company’s business or the extent to which any such factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.

The following discussion and analysis is provided for the consolidated financial condition and results of operations of Avista Corp., including its subsidiaries. This discussion focuses on significant factors concerning the Company’s financial condition and results of operations and should be read along with the consolidated financial statements.

Avista Corp. Business Segments

Avista Corp. is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. The Company has four business segments – Avista Utilities, Energy Marketing and Resource Management, Avista Advantage and Other. Avista Utilities is an operating division of Avista Corp. comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility business segments. As of March 31, 2005, the Company had common equity investments of $519.2 million and $237.1 million in Avista Utilities and Avista Capital, respectively.

The Energy Marketing and Resource Management business segment is comprised of Avista Energy, Inc. (Avista Energy) and Avista Power, LLC (Avista Power). Avista Energy is an electricity and natural gas marketing, trading and resource management business, operating primarily in the Western Electricity Coordinating Council (WECC) geographical area, which is comprised of eleven Western states and the provinces of British Columbia and Alberta, Canada. Avista Power is an investor in certain generation assets, primarily its 49 percent interest in a 270 MW natural gas-fired combined cycle combustion turbine plant in northern Idaho (Lancaster Project).

Avista Advantage, Inc. (Avista Advantage) is a provider of utility bill processing, payment and information services to multi-site customers throughout North America. Its primary product lines include consolidated billing, resource accounting, energy analysis and load profiling services.

The Other business segment includes Avista Ventures, Inc. (Avista Ventures), Pentzer Corporation (Pentzer), Avista Development and certain other operations of Avista Capital. Included in this business segment is Advanced Manufacturing and Development (AM&D) doing business as METALfx, a subsidiary of Avista Ventures that performs custom sheet metal manufacturing of electronic enclosures, parts and systems for the computer, telecom and medical industries. AM&D also provides complete fabrication and turnkey assembly for arcade games, kiosks, store fixtures and displays. Other significant investments in this segment include commercial office buildings, investments in low income housing and venture capital partnerships, the remaining investment in a previous fuel cell subsidiary of the Company, and notes receivable from the sale of property and investments.

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Executive Level Summary

Avista Corp.’s operating results and cash flows are derived primarily from Avista Utilities and Avista Energy (included in the Energy Marketing and Resource Management segment). Avista Corp. intends to continue to focus on improving earnings and operating cash flows, controlling costs and reducing debt while working to restore an investment grade credit rating.

Avista Utilities expects to continue to be among the industry leaders in performance, value and service in its electric and natural gas utility businesses. Avista Utilities expects to continue its modest, yet steady, combined growth of electric and natural gas customers of 2 to 3 percent per year primarily from economic and population growth in its service territory. As part of Avista Utilities’ strategy to focus on its business in the northwestern United States, in April 2005, the Company completed the sale of its natural gas distribution properties in South Lake Tahoe, California (see “Note 12 of the Notes to Consolidated Financial Statements”).

It is Avista Utilities’ strategy to own or to have contracts that provide a sufficient amount of electric resources to meet its retail and wholesale energy requirements under a range of operating conditions. The availability of Avista Utilities’ hydroelectric generation is significantly affected by precipitation, temperatures and other variables. Avista Utilities’ hydroelectric generation was 95 percent of normal in 2004. Based on forecasts as of April 8, 2005, Avista Utilities expects hydroelectric generation will be approximately 83 percent of normal in 2005 assuming normal precipitation for the remainder of the year. This expectation may change based upon precipitation, temperatures and other variables. The earnings impact of below normal hydroelectric generation is mitigated through power cost deferral and recovery mechanisms in Washington and Idaho. The expected reduction in hydroelectric generation is estimated to have a negative effect on operating cash flows of approximately $25 million from the amount originally forecasted, with approximately $2.5 million impacting pre-tax earnings. Avista Utilities believes that it has adequate liquidity through cash flows generated from operations and funds available under its committed line of credit to meet increased cash requirements for purchased power or fuel as a result of reduced hydroelectric generation.

Customer loads and resulting revenues are also significantly affected by weather, which causes changes in energy usage from season to season and from month to month within a season. Avista Utilities normally experiences its highest retail energy sales during the heating season in the first and fourth quarters of the year. Total heating degree days at Spokane, Washington for the three months ended March 31, 2005 (93 percent of normal) were less than the three months ended March 31, 2004 (97 percent of normal). As such, electric and natural gas loads and revenues were negatively affected by weather when comparing results for 2005 and 2004.

As is the case with most regulated entities, Avista Utilities generally has ongoing regulatory proceedings. Avista Utilities received the following base rate increases in 2004 and 2005: Idaho electric and natural gas in September 2004; Washington natural gas in November 2004; and Idaho electric in April 2005 for the addition of the remaining interest in Coyote Springs 2. The base rate increases implemented in 2004 have increased revenues and net income for the three months ended March 31, 2005 as compared to the three months ended March 31, 2004 and should result in increased net income for the remainder of 2005 as compared to 2004. In March 2005, Avista Utilities filed a request with the WUTC to increase its base electric and natural gas rates. Avista Utilities will continue to file for rate adjustments to provide recovery of its costs and to more closely align earned returns with those allowed by regulatory agencies in each jurisdiction.

Avista Utilities’ net income increased for the three months ended March 31, 2005 as compared to the three months ended March 31, 2004 primarily due to the general rate increases, customer growth and decreased electric resource costs. This was partially offset by decreased use per customer in the Washington and Idaho service territory as a result of warmer weather. The Company expects Avista Utilities’ net income for 2005 to increase as compared to 2004 primarily due to the continued effect of general rate increases, subject to the influence of weather.

The Company has management succession plans that work towards ensuring that executive officer and key management positions can be appropriately filled as vacancies occur. The Company has taken similar steps in key technical and craft areas.

Avista Energy focuses on optimization of combustion turbines and hydroelectric assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric transmission and natural gas transportation arrangements. Avista Energy is also involved in trading electricity and natural gas, including derivative commodity instruments. Avista Energy Canada, Ltd. (Avista Energy Canada) is a wholly owned subsidiary of Avista Energy that provides natural gas services to approximately 250 industrial and commercial customers that represent over 400

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sites in British Columbia, Canada. In addition to earnings and resulting cash flows from settled or realized transactions, Avista Energy records unrealized or mark-to-market adjustments for the change in the value of derivative commodity instruments. Avista Energy’s marketing, trading and resource management activities are driven by its base of knowledge and experience in the operation of both electric energy and natural gas physical systems in the WECC, as well as its relationship-focused approach with its customers.

Avista Energy is subject to certain regulatory proceedings that remain unresolved; however, Avista Energy believes that it has adequate reserves established for refunds that may be ordered. The wholesale power markets in which Avista Energy operates continue to change with respect to market participants involved, level of activity, volatility in market prices, liquidity, regulatory imposed price caps and counterparty credit issues.

Avista Energy and the Energy Marketing Resource Management segment incurred a net loss for the three months ended March 31, 2005 compared to net income for the three months ended March 31, 2004. This net loss was primarily related to losses in Avista Energy’s natural gas portfolio.

Avista Advantage remains focused on increasing revenues, controlling operating expenses, continuously enhancing client satisfaction and developing complementary value-added services in a competitive market. During the first quarter of 2005, Avista Advantage acquired TelAssess, Inc. Although not a significant financial transaction, this acquisition provides Avista Advantage with a foundation to expand beyond utility bill information services to provide similar services relating to telecom billing. The Company expects that net income for Avista Advantage for 2005 will increase as compared to 2004 based on increased revenues and stabilizing operating expenses from processing efficiencies.

Over time as opportunities arise, the Company plans to continue to dispose of assets and phase out operations in the Other business segment. The Company expects the net loss in the Other business segment to be less for fiscal year 2005 as compared to 2004 due to decreased losses from asset impairments and write-offs.

During the first quarter of 2005, positive cash flows from operations and an overall reduction in the Company’s consolidated cash position were used to fund the majority of Avista Corp.’s cash requirements, including utility capital expenditures, dividends and debt redemptions. During the remainder of 2005, the Company expects cash flows from operations and Avista Corp.’s five-year $350.0 million committed line of credit to provide adequate resources to fund capital expenditures, maturing long-term debt (excluding $54.6 million of WP Funding LP debt maturing in October 2005 for which the Company is currently evaluating its options) and other contractual commitments. However, if market conditions warrant such actions, the Company may issue securities to fund these obligations, refinance existing debt and repurchase long-term debt scheduled to mature in future years to reduce its overall debt service costs, as well as to manage the risk associated with future changes in interest rates on debt maturities scheduled for 2007 and 2008.

Avista Utilities – Electric Resources

As of March 31, 2005, Avista Utilities’ facilities had a total net capability of approximately 1,800 MW, of which 54 percent was hydroelectric and 46 percent was thermal. In addition to company owned resources, Avista Utilities has a number of long-term power purchase and exchange contracts that increase its available resources. See “Note 5 of the Notes to Consolidated Financial Statements” for information with respect to Avista Utilities’ resource optimization process.

Avista Utilities – Regulatory Matters

General Rate Cases

Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which it provides service.

On March 30, 2005, Avista Utilities filed a request with the WUTC to increase its base electric rates by 12.5 percent and its base natural gas rates by 1.8 percent. This request is designed to increase its annual electric and natural gas revenues by $35.8 million and $2.9 million, respectively. Avista Utilities’ request is based on a proposed rate of return of 9.67 percent, including a return on common equity of 11.5 percent with an authorized equity level of 44 percent. In the general rate case filing, Avista Utilities has also requested modification of the Energy Recovery Mechanism (ERM) as described at “Power Cost Deferrals and Recovery Mechanisms” below. The WUTC has up to 11 months to review the general rate case filing.

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In January 2005, the WUTC issued its final order with respect to a natural gas general rate case filed by Avista Utilities in Washington. The final order authorized, among other things, an increase in natural gas rates of 3.9 percent, which is designed to increase annual revenues by $5.4 million. The final order authorized an overall rate of return of 8.68 percent. The natural gas rate increase was implemented in November 2004 resulting from a settlement agreement reached among the Company, the staff of the WUTC and the Northwest Industrial Gas Users in October 2004. The increase was approved by the WUTC in November 2004 on a “subject to refund” basis to allow the non-settling parties the opportunity to further review the case.

In October 2004, the IPUC issued its final order with respect to electric and natural gas general rate cases filed by Avista Utilities in Idaho. The final order authorized, among other things, Avista Utilities to increase its electric base rates by 16.9 percent, which is designed to increase annual revenues by $24.7 million, and increase its natural gas base rates by 6.4 percent, which is designed to increase annual revenues by $3.3 million. Due to a decrease implemented concurrently in Avista Utilities’ power cost adjustment (PCA) surcharge and certain other minor adjustments, the net increase in electric rates for Idaho customers was 1.9 percent above rates in effect at that time. The decrease in the PCA surcharge reduces the rate increase impact to customers and extends the period for recovery of deferred power costs. The final order authorized an overall rate of return of 9.25 percent, including a return on common equity of 10.4 percent based on an authorized equity level of approximately 43 percent.

Other Regulatory Filings

In April 2005, the IPUC issued an order approving the inclusion of the remaining 50 percent of Coyote Springs 2 in base electric rates. The order provides for a 1.9 percent increase in base electric rates, which is designed to increase annual revenues by $3.2 million. At the same time, the IPUC approved a 1.9 percent reduction in the Company’s current PCA rate surcharge, which extends the two-year recovery period of deferred power costs by an additional year. These two requests together result in no overall change to customers’ existing rates.

Power Cost Deferrals and Recovery Mechanisms

Avista Utilities defers the recognition in the income statement of certain power supply costs that are in excess of the level currently recovered from retail customers as authorized by the WUTC and the IPUC. A portion of power supply costs are recorded as a deferred charge on the Consolidated Balance Sheets for future review and the opportunity for recovery through retail rates.

In Washington, the ERM allows Avista Utilities to increase or decrease electric rates periodically with WUTC approval to reflect changes in power supply costs. The ERM provides for Avista Utilities to incur the cost of, or receive the benefit from, the first $9.0 million in annual power supply costs above or below the amount included in base retail rates. Under the ERM, 90 percent of the power supply costs exceeding or below the initial $9.0 million are deferred for future surcharge or rebate to Avista Utilities’ customers. The remaining 10 percent of power supply costs are an expense of, or benefit to, the Company. In its March 2005 general rate case filing, Avista Utilities has requested that the $9.0 million exclusion be eliminated and that 90 percent of all power supply costs above or below the amount included in base retail rates be deferred.

The Company expensed $0.2 million of the initial $9.0 million of power supply costs above the amount included in base retail rates during the three months ended March 31, 2005 and expects to expense the full $9.0 million during 2005. The Company expensed the initial $9.0 million of power supply costs above the amount included in base retail rates during 2004, 2003 and 2002 ($4.5 million in 2002 due to mid-year implementation on July 1, 2002).

Under the ERM, Avista Utilities agreed to make an annual filing on or before April 1st of each year to provide the opportunity for the WUTC and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. The ERM provides for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by WUTC order. Avista Utilities made its annual filing with the WUTC on March 30, 2005 related to $10.8 million of deferred power costs incurred for 2004. In addition, on or before December 31, 2006, Avista Utilities will make a filing with the WUTC that will allow interested parties the opportunity to review and propose changes to the ERM.

Avista Utilities has a PCA mechanism in Idaho that allows it to modify electric rates periodically with IPUC approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the authorized level of net power supply expense approved in the last Idaho general rate case. As disclosed at “General Rate Cases” above, in October 2004, the IPUC issued its final order with respect to general electric and natural gas rate cases filed by Avista Utilities in Idaho. The IPUC authorized the recovery of remaining deferred power costs over a two-year period through a PCA rate surcharge to customers that was reduced to 4.4 percent. The PCA surcharge was further reduced to 2.5 percent in April 2005 with the approval of the

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inclusion of the remaining interest in Coyote Springs 2 in base electric rates. The decrease in the PCA rate surcharge extends the recovery period of deferred power costs by an additional year.

The following table shows activity in deferred power costs for Washington and Idaho during 2004 and the three months ended March 31, 2005 (dollars in thousands):

Purchased Gas Adjustments

Natural gas commodity costs in excess of, or which fall below, the amount recovered in current retail rates are deferred and recovered or refunded as a pass-through to customers in future periods with applicable regulatory approval through adjustments to rates. During September through November of 2004, natural gas rate increases of 11.7 percent, 14.2 percent, 12.6 percent and 10.5 percent were approved and implemented in Washington, Idaho, Oregon and California, respectively. These natural gas rate increases are designed to pass through changes in purchased natural gas costs to customers with no change in Avista Utilities’ gross margin or net income. Total deferred natural gas costs were $23.1 million and $28.6 million as of March 31, 2005 and December 31, 2004, respectively.

Natural Gas Benchmark Mechanism

The IPUC, WUTC and OPUC approved Avista Utilities’ Natural Gas Benchmark Mechanism in 1999. The mechanism eliminated the majority of natural gas procurement operations within Avista Utilities and placed responsibility for natural gas procurement operations with Avista Energy, the Company’s non-regulated subsidiary. The ownership of the natural gas assets remains with Avista Utilities; however, the assets were managed by Avista Energy through an Agency Agreement. In early 2002, the IPUC and the OPUC approved the continuation of the Natural Gas Benchmark Mechanism and related Agency Agreement through March 31, 2005. Effective April 1, 2005, the Natural Gas Benchmark Mechanism and Related Agency Agreement were terminated and the management of natural gas procurement functions was moved from Avista Energy back to Avista Utilities. This was required for Washington customers by WUTC orders issued over one year earlier, in February 2004, and Avista Utilities’ resulting transition plan approved by the WUTC in April 2004. The Company also elected to move these functions back to Avista Utilities for Idaho and Oregon natural gas customers. As part of the transition plan, Avista Utilities began procuring natural gas for load service during the second half of 2004 and the first quarter of 2005. This procurement process includes entering into financial and physical hedging transactions as a means of managing risks. This transition of Avista Utilities’ natural gas procurement operations also impacts the level of counterparty credit requirements at both Avista Utilities and Avista Energy. In response to this as well as to provide enhanced financial flexibility, in May 2004 Avista Corp. increased the amount available under its committed line of credit to $350.0 million from $245.0 million. In December 2004, Avista Corp. entered into a five-year $350.0 million committed line of credit, which replaced the 364-day committed line of credit entered into in May 2004.

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Power Market Issues

Legal and Regulatory Proceedings in Western Power Markets

Avista Energy and Avista Utilities are involved in a number of legal and regulatory proceedings and complaints with respect to power markets in the western United States. Most of these proceedings and complaints relate to the significant increase in the spot market price of energy in western power markets in 2000 and 2001, which allegedly contributed to or caused unjust and unreasonable prices. These proceedings and complaints include, but are not limited to, refund proceedings and hearings in California and the Pacific Northwest, market conduct investigations by the FERC (including a specific investigation of Avista Utilities and Avista Energy), and complaints and cross-complaints filed by various parties with respect to alleged misconduct by other parties in western power markets. As a result of these proceedings and complaints, certain parties have asserted claims for refunds and damages from Avista Energy and Avista Utilities, which could result in a negative impact on future earnings. Avista Energy and Avista Utilities have joined other parties in opposing these refund claims and complaints for damages. See further information in “Note 11 of the Notes to Consolidated Financial Statements.”

Market Conduct Investigations and Market-Based Rate Authority

As a result of certain revelations about alleged improper practices engaged in by Enron and certain of its affiliates, the FERC initiated investigations in February 2002 of Avista Corp. doing business as Avista Utilities, Avista Energy and other unrelated parties. Avista Utilities and Avista Energy cooperated with the FERC investigation by providing requested documents and other information. Several parties filed documents with the FERC in March 2003 alleging improper market conduct by various parties, including Avista Utilities and Avista Energy, and requesting refunds and other relief. Avista Utilities and Avista Energy filed replies in response to the allegations of the parties.

In March 2003, the FERC policy staff issued its final report on its investigation of western energy markets. In the report, the FERC policy staff recommended the issuance of “show cause” orders to dozens of companies to respond to allegations of possible misconduct in the western energy markets during 2000 and 2001. Of the companies named in the March 2003 FERC policy staff report, Avista Corp. and Avista Energy were among the few that had already been subjects of a FERC investigation. See further information under “Federal Energy Regulatory Commission Inquiry” in “Note 11 of the Notes to Consolidated Financial Statements.”

Every three years or more frequently if certain regulatory triggers are met, Avista Corp. doing business as Avista Utilities, and Avista Energy are required to file for renewal of their respective market-based rate authority with the FERC. Avista Utilities and Avista Energy made their respective filings with the FERC in September 2004. By orders issued in March 2005, the FERC approved the renewal of the market-based rate authority of Avista Utilities and Avista Energy.

Wholesale Energy Markets and Development of Regional Transmission Organizations

The FERC has proposed changes to the design of the wholesale energy market, which includes the formation of Regional Transmission Organizations. This could significantly change how transmission facilities are regulated and operated.

Avista Corp. has participated with other utilities in the western United States on the possible formation of a Regional Transmission Organization. Interim bylaws governing continuing developmental activities for this non-profit corporation, under the name Grid West, were adopted in December 2004. The next phase of the development of Grid West would be the establishment of a board of directors, which is currently planned for late 2005. Avista Corp. is also participating in concurrent discussions with the Transmission Improvements Group regarding the enhancement of existing organizational structures to incorporate certain elements and functions that have been contemplated to be included in a Regional Transmission Organization.

The final proposal for any Regional Transmission Organization must be filed with the FERC and approved by the boards of directors of the filing companies and regulators in various states. The Company’s decision to move forward with the formation of any Regional Transmission Organization serving the Pacific Northwest region, as well as the legal, financial and operating implications of such decisions, will ultimately depend on the terms and conditions related to the formation of the entities and conditions established in the regulatory approval processes. The Company cannot predict these implications.

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Results of Operations

Contribution to Diluted Earnings per Common Share by Business Segments

The following table presents the contribution to diluted earnings per common share by business segments for the three months ended March 31:

Overall Operations

Net income was $10.2 million for the three months ended March 31, 2005 compared to $12.2 million for the three months ended March 31, 2004. This decrease was primarily due to a net loss for Avista Energy (Energy Marketing and Resource Management segment). This was partially offset by the improved performance of Avista Utilities, as well as increased net income from Avista Advantage.

Energy Marketing and Resource Management incurred a net loss of $8.4 million for the three months ended March 31, 2005 compared to net income of $3.5 million for the three months ended March 31, 2004. The net loss was primarily due to losses in Avista Energy’s natural gas portfolio.

Net income for Avista Utilities was $19.0 million for the three months ended March 31, 2005, compared to $10.8 million for the three months ended March 31, 2004. The increase for Avista Utilities was primarily due to an increase in gross margin as a result of general rate increases, customer growth and decreased electric resource costs. This was partially offset by warmer weather in the Washington and Idaho service territory, which decreased use per customer.

Avista Advantage had net income of $0.8 million for the three months ended March 31, 2005 compared to a net loss of less than $0.1 million for the three months ended March 31, 2004. The change was primarily due to an increase in operating revenues from customer growth.

The Other business segment incurred a net loss of $1.2 million for the three months ended March 31, 2005 compared to a net loss of $1.6 million (excluding the cumulative effect of accounting change) for the three months ended March 31, 2004.

Total revenues increased $18.9 million for the three months ended March 31, 2005 compared to the three months ended March 31, 2004. Avista Utilities’ revenues increased $29.7 million due to increases in both electric and natural gas revenues. The increase in natural gas revenues was primarily due to natural gas rate increases implemented during 2004. The increase in electric revenues primarily reflects an increase in wholesale revenues and a slight increase in retail revenues, partially offset by a decrease in sales of fuel. Revenues from Energy Marketing and Resource Management decreased $52.4 million primarily due to decreased revenues under the Agency Agreement with Avista Utilities as natural gas procurement operations are being transitioned to Avista Utilities, and decreased net trading margin on contracts accounted for under SFAS No. 133, partially offset by increased revenues for Avista Energy Canada. Revenues from Avista Advantage increased $2.0 million to $7.2 million primarily as a result of customer growth. Revenues from the Other business segment decreased $0.1 million to $3.8 million.

Total resource costs increased $18.9 million for the three months ended March 31, 2005 compared to the three months ended March 31, 2004. Resource costs for Avista Utilities increased $13.1 million primarily due to an increase in purchased natural gas costs, as well as net amortization of deferred natural gas costs for the three months ended March 31, 2005 compared to net deferrals for the three months ended March 31, 2004. The increase in purchased natural gas costs was primarily due to an increase in prices. The increase in natural gas resource costs was partially offset by a decrease in electric resource costs. Resource costs for Energy Marketing and Resource Management decreased $33.9 million primarily due to decreased resource costs under the Agency Agreement with Avista Utilities as natural gas procurement operations are being transitioned to Avista Utilities, partially offset

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by increased resource costs for Avista Energy Canada.

Intersegment eliminations, which decrease both operating revenues and resource costs, were $19.4 million for the three months ended March 31, 2005 compared to $59.2 million for the three months ended March 31, 2004, representing decreased purchases of natural gas under the Agency Agreement between Avista Utilities and Avista Energy.

Operations and maintenance expenses increased $1.0 million for the three months ended March 31, 2005 compared to the three months ended March 31, 2004 primarily due to increased costs for Avista Advantage. The increased costs for Avista Advantage primarily reflects increased labor costs necessary to service an expanding customer base.

Administrative and general expenses decreased $1.2 million for the three months ended March 31, 2005 compared to the three months ended March 31, 2004 primarily due to decreased expenses for Energy Marketing and Resource Management and the Other business segment. The decrease for Energy Marketing and Resource Management was primarily a result of decreased compensation expense. The decrease for the Other business segment was due to accrual of an environmental liability during the three months ended March 31, 2004.

Depreciation and amortization increased $5.0 million for the three months ended March 31, 2005 compared to the three months ended March 31, 2004 due in part to utility plant additions at Avista Utilities and the resulting increase in depreciation expense. This was also due to a correction at Avista Utilities for overstated depreciation expense in prior periods recorded during the first quarter of 2004.

Interest expense decreased $0.3 million for the three months ended March 31, 2005 compared to the three months ended March 31, 2004 primarily due to a decrease in the effective borrowing rate as a result of previous debt issuances and repurchases, partially offset by a slight increase in the average balance of outstanding debt.

Other income-net increased $0.2 million for the three months ended March 31, 2005 compared to the three months ended March 31, 2004 primarily due to decreased losses on certain investments in the Other business segment. This was partially offset by a decrease in interest income.

Income taxes decreased $2.3 million for the three months ended March 31, 2005 compared to the three months ended March 31, 2004, primarily due to decreased income before income taxes. The effective tax rate was 40.1 percent for the three months ended March 31, 2005 compared to 41.9 percent for the three months ended March 31, 2004.

During the three months ended March 31, 2004, the Other business segment recorded as a cumulative effect of accounting change a charge of $0.5 million related to the implementation of FIN 46, which required Avista Ventures to consolidate several minor entities.

Avista Utilities

Net income for Avista Utilities was $19.0 million for the three months ended March 31, 2005 compared to $10.8 million for the three months ended March 31, 2004. Avista Utilities’ income from operations was $51.6 million for the three months ended March 31, 2005 compared to $39.7 million for the three months ended March 31, 2004. This increase was primarily a result of increased gross margin (operating revenues less resource costs) due to general rate increase implemented in 2004, customer growth and decreased electric resource costs. This was partially offset by decreased use per customer in the Washington and Idaho service territory due to warmer weather. The increase in gross margin was partially offset by an increase in depreciation expense.

The following table presents Avista Utilities’ gross margin for the three months ended March 31 (dollars in thousands):

Avista Utilities’ operating revenues increased $29.7 million and resource costs increased $13.1 million, which resulted in an increase of $16.6 million in gross margin for the three months ended March 31, 2005 as compared to the three months ended March 31, 2004. The gross margin on electric sales increased $10.8 million and the gross

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margin on natural gas sales increased $5.8 million. The increase in electric gross margin was partially due to a decrease in electric resource costs and the expense of only $0.2 million of power supply costs in Washington exceeding the amount included in base retail rates during the first quarter of 2005, compared to $6.3 million for the first quarter of 2004. This decrease in electric resource costs reflects improved hydroelectric generation from earlier runoff due to warmer weather, added generation and increased resources available to sell due to retail loads that were less than expected. The increase in electric gross margin was also due to the Idaho electric general rate increase implemented in September 2004 as well as customer growth, partially offset by warmer weather during the first quarter of 2005 as compared to the first quarter of 2004. The increase in the gross margin on natural gas sales was primarily due to the Idaho natural gas general rate increase implemented in September 2004 and the Washington natural gas general rate increase implemented in November 2004, colder weather in the Oregon service territory, as well as customer growth. The effects of general rate increases and customer growth were partially offset by warmer weather in the Washington and Idaho service territory and decreased use per customer.

The following table presents Avista Utilities’ electric operating revenues and megawatt-hour (MWh) sales for the three months ended March 31 (dollars and MWhs in thousands):

Retail electric revenues increased $1.0 million for the three months ended March 31, 2005 from the three months ended March 31, 2004. This increase was primarily due to an increase in total MWhs sold (increased revenues $2.2 million), partially offset by a slight decrease in revenue per MWh (decreased revenues $1.2 million). The increase in total MWhs sold was primarily due to customer growth, partially offset by warmer weather. Total heating degree days at Spokane, Washington for both the three months ended March 31, 2005 decreased as compared to the three months ended March 31, 2004 with both periods warmer than normal. As such, electric loads and revenues were negatively affected by weather when comparing 2005 and 2004 results. In September 2004, a general electric rate increase was implemented in Idaho. However, this was almost entirely offset by a decrease in the PCA surcharge, such that the net increase in rates to Idaho customers was only 1.9 percent. Although the general rate case increased gross margin, income from operations and net income, it did not have a significant effect on operating revenues for the three months ended March 31, 2005 as compared to the three months ended March 31, 2004. The slight decrease in revenue per MWh was primarily due to a change in revenue mix with a greater percentage of revenues from industrial customers.

Wholesale electric revenues increased $17.6 million primarily due to an increase in wholesale sales volumes and partially due to an increase in wholesale sales prices. The increase in wholesale sales volumes reflects added generation capacity, earlier than normal runoff to hydroelectric generating assets and lower than anticipated retail loads, which resulted in excess resources that were sold in the wholesale market.

Sales of fuel decreased $13.4 million as a greater percentage of fuel purchases were used in generation. Sales of fuel represents natural gas that was not used for generation because electric wholesale market prices were generally below the cost of operating the natural gas-fired thermal generating units.

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The following table presents Avista Utilities’ natural gas operating revenues and therms delivered for the three months ended March 31 (dollars and therms in thousands):