10-Q 1 d10q.htm FORM 10-Q Form 10-Q
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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2008

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission file number 1-3701

AVISTA CORPORATION

(Exact name of registrant as specified in its charter)

 

Washington   91-0462470

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

1411 East Mission Avenue, Spokane, Washington   99202-2600
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: 509-489-0500

Web site: http://www.avistacorp.com

None

(Former name, former address and former fiscal year, if changed since last report)

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  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer  x

   Accelerated filer  ¨    Non-accelerated filer  ¨   

Smaller reporting company  ¨

     

(Do not check if a smaller

reporting company)

  

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):

Yes  ¨    No  x

As of April 18, 2008, 53,050,928 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

 

 

 


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AVISTA CORPORATION

Index

 

          Page No.

Part I. Financial Information:

  

Item 1.

  

Consolidated Financial Statements

  
  

Consolidated Statements of Income -
Three Months Ended March 31, 2008 and 2007

   3
  

Consolidated Statements of Comprehensive Income -
Three Months Ended March 31, 2008 and 2007

   4
  

Consolidated Balance Sheets -
March 31, 2008 and December 31, 2007

   5
  

Consolidated Statements of Cash Flows -
Three Months Ended March 31, 2008 and 2007

   7
  

Notes to Consolidated Financial Statements

   8
  

Report of Independent Registered Public Accounting Firm

   27

Item 2.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

   28

Item 3.

  

Quantitative and Qualitative Disclosures About Market Risk

   47

Item 4.

  

Controls and Procedures

   47

Part II. Other Information:

  

Item 1.

  

Legal Proceedings

   47

Item 1A.

  

Risk Factors

   47

Item 6.

  

Exhibits

   47

Signature

   48

FORWARD-LOOKING STATEMENTS

Our Quarterly Report on Form 10-Q contains forward-looking statements, which should be read with the cautionary statements and important factors included at “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Forward-Looking Statements” on pages 28-29. Forward-looking statements are all statements except those of historical fact, including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions. All forward-looking statements are subject to a variety of risks and uncertainties and other factors. Many of these factors are beyond our control and could have a significant effect on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in our statements.


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CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands, except per share amounts

 

      2008     2007  

Operating Revenues:

    

Utility revenues

   $ 472,272     $ 414,266  

Non-utility energy marketing and trading revenues

     6,416       29,409  

Other non-utility revenues

     17,619       15,512  
                

Total operating revenues

     496,307       459,187  
                

Operating Expenses:

    

Utility operating expenses:

    

Resource costs

     318,226       269,986  

Other operating expenses

     51,719       49,041  

Depreciation and amortization

     21,442       21,090  

Taxes other than income taxes

     25,085       23,995  

Non-utility operating expenses:

    

Resource costs

     5,920       37,727  

Other operating expenses

     13,845       17,136  

Depreciation and amortization

     1,009       1,275  
                

Total operating expenses

     437,246       420,250  
                

Income from operations

     59,061       38,937  
                

Other Income (Expense):

    

Interest expense

     (18,929 )     (20,373 )

Interest expense to affiliated trusts

     (1,696 )     (1,810 )

Capitalized interest

     841       1,116  

Other income - net

     1,043       3,711  
                

Total other income (expense)-net

     (18,741 )     (17,356 )
                

Income before income taxes

     40,320       21,581  

Income taxes

     15,089       7,487  
                

Net income

   $ 25,231     $ 14,094  
                

Weighted-average common shares outstanding (thousands), basic

     53,020       52,684  

Weighted-average common shares outstanding (thousands), diluted

     53,382       53,322  

Total earnings per common share, basic

   $ 0.48     $ 0.27  
                

Total earnings per common share, diluted

   $ 0.47     $ 0.26  
                

Dividends paid per common share

   $ 0.165     $ 0.145  
                

The Accompanying Notes are an Integral Part of These Statements.

 

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

 

     2008     2007  

Net income

   $ 25,231     $ 14,094  
                

Other Comprehensive Income (Loss):

    

Foreign currency translation adjustment

     —         114  

Unrealized gains (losses) on interest rate swap agreements - net of taxes of $(2,063) and $28, respectively

     (3,831 )     52  

Reclassification adjustment for realized losses on interest rate swap agreements deferred as a regulatory asset (included in long-term debt) - net of taxes of $5,738

     10,657       —    

Change in unfunded benefit obligation for pension plan - net of taxes of $237 and $127, respectively

     440       236  

Unrealized gains on derivative commodity instruments - net of taxes of $673

     —         1,249  

Reclassification adjustment for realized gains on derivative commodity instruments included in net income - net of taxes of $(39)

     —         (73 )
                

Total other comprehensive income

     7,266       1,578  
                

Comprehensive income

   $ 32,497     $ 15,672  
                

The Accompanying Notes are an Integral Part of These Statements.

 

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CONSOLIDATED BALANCE SHEETS

Avista Corporation

Dollars in thousands

 

     March 31,
2008
   December 31,
2007

Assets:

     

Current Assets:

     

Cash and cash equivalents

   $ 12,986    $ 11,839

Restricted cash

     120      4,068

Accounts and notes receivable-less allowances of $43,283 and $42,582

     223,725      105,440

Utility energy commodity derivative assets

     40,734      12,078

Regulatory asset for utility derivatives

     —        7,171

Funds held for customers

     90,190      89,885

Materials and supplies, fuel stock and natural gas stored

     21,416      34,985

Deferred income taxes

     21,401      20,251

Income taxes receivable

     11,888      30,025

Other current assets

     16,123      16,443
             

Total current assets

     438,583      332,185
             

Net Utility Property:

     

Utility plant in service

     3,151,356      3,131,916

Construction work in progress

     115,284      100,106
             

Total

     3,266,640      3,232,022

Less: Accumulated depreciation and amortization

     895,389      880,680
             

Total net utility property

     2,371,251      2,351,342
             

Other Property and Investments:

     

Investment in exchange power-net

     27,971      28,583

Investment in affiliated trusts

     13,403      13,403

Other property and investments-net

     75,947      74,171
             

Total other property and investments

     117,321      116,157
             

Deferred Charges:

     

Regulatory assets for deferred income tax

     115,984      117,461

Regulatory assets for pensions and other postretirement benefits

     49,322      51,006

Other regulatory assets

     43,371      43,004

Non-current utility energy commodity derivative assets

     73,136      55,313

Power and natural gas deferrals

     74,414      85,885

Unamortized debt expense

     33,627      32,542

Other deferred charges

     5,826      4,902
             

Total deferred charges

     395,680      390,113
             

Total assets

   $ 3,322,835    $ 3,189,797
             

The Accompanying Notes are an Integral Part of These Statements.

 

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CONSOLIDATED BALANCE SHEETS (continued)

Avista Corporation

Dollars in thousands

 

     March 31,
2008
    December 31,
2007
 

Liabilities and Stockholders’ Equity:

    

Current Liabilities:

    

Accounts payable

   $ 139,468     $ 117,546  

Customer fund obligations

     90,190       89,885  

Deposits from counterparties

     25,930       12,510  

Current portion of long-term debt

     179,700       427,344  

Short-term borrowings

     29,000       —    

Interest accrued

     24,281       12,578  

Utility energy commodity derivative liabilities

     8,095       19,249  

Regulatory liability for utility derivatives

     32,639       —    

Other current liabilities

     110,994       84,537  
                

Total current liabilities

     640,297       763,649  
                

Long-term debt

     752,536       521,489  
                

Long-term debt to affiliated trusts

     113,403       113,403  
                

Other Non-Current Liabilities and Deferred Credits:

    

Regulatory liability for utility plant retirement costs

     210,807       209,357  

Non-current regulatory liability for utility derivatives

     72,097       53,414  

Pensions and other postretirement benefits

     83,709       90,555  

Deferred income taxes

     440,595       440,918  

Other non-current liabilities and deferred credits

     70,281       83,046  
                

Total other non-current liabilities and deferred credits

     877,489       877,290  
                

Total liabilities

     2,383,725       2,275,831  
                

Commitments and Contingencies (See Notes to Consolidated Financial Statements)

    

Stockholders’ Equity:

    

Common stock, no par value; 200,000,000 shares authorized;

    

53,048,994 and 52,909,013 shares outstanding

     727,707       726,933  

Accumulated other comprehensive loss

     (12,342 )     (19,608 )

Retained earnings

     223,745       206,641  
                

Total stockholders’ equity

     939,110       913,966  
                

Total liabilities and stockholders’ equity

   $ 3,322,835     $ 3,189,797  
                

The Accompanying Notes are an Integral Part of These Statements.

 

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CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

 

     2008     2007  

Operating Activities:

    

Net income

   $ 25,231     $ 14,094  

Non-cash items included in net income:

    

Depreciation and amortization

     22,451       22,365  

Benefit for deferred income taxes

     (4,113 )     (11,411 )

Power and natural gas cost amortizations, net of deferrals

     27,598       14,884  

Amortization of debt expense

     1,234       1,704  

Unrealized loss on energy commodity derivatives

     —         20,933  

Equity-related Allowance for Funds Used During Construction (AFUDC)

     (893 )     (907 )

Other

     (1,998 )     1,983  

Changes in working capital components:

    

Accounts and notes receivable

     (118,986 )     26,564  

Materials and supplies, fuel stock and natural gas stored

     13,569       15,062  

Deposits with counterparties

     —         (5,889 )

Other current assets

     18,152       13,824  

Accounts payable

     28,033       (36,877 )

Deposits from counterparties

     13,420       (543 )

Other current liabilities

     20,850       14,496  
                

Net cash provided by operating activities

     44,548       90,282  
                

Investing Activities:

    

Utility property capital expenditures (excluding equity-related AFUDC)

     (47,680 )     (40,556 )

Other capital expenditures

     (1,099 )     (1,339 )

Decrease in restricted cash

     3,948       3,666  

Changes in other property and investments

     (2,295 )     (981 )
                

Net cash used in investing activities

     (47,126 )     (39,210 )
                

Financing Activities:

    

Increase (decrease) in short-term borrowings

     29,000       (4,000 )

Redemption and maturity of long-term debt

     (236 )     (12,255 )

Cash dividends paid

     (8,754 )     (7,645 )

Issuance of common stock

     108       1,630  

Cash paid for settlement of interest rate swap agreements

     (16,395 )     —    

Equity transactions of consolidated subsidiaries

     25       —    

Long-term debt and short-term borrowing issuance costs

     (23 )     (70 )
                

Net cash provided by (used in) financing activities

     3,725       (22,340 )
                

Net increase in cash and cash equivalents

     1,147       28,732  

Cash and cash equivalents at beginning of period

     11,839       28,242  
                

Cash and cash equivalents at end of period

   $ 12,986     $ 56,974  
                

Supplemental Cash Flow Information:

    

Cash paid during the period:

    

Interest

   $ 7,688     $ 6,606  

Income taxes

     117       —    

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, 2008 and 2007 are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results for the 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, 2007 (2007 Form 10-K). Please refer to the section “Acronyms and Terms” in the 2007 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 and northern Idaho, as well as parts of northeast and southwest Oregon. Avista Capital, Inc. (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 including Avista Energy, Inc. (Avista Energy) and Advantage IQ, Inc. (Advantage IQ). Avista Energy was an electricity and natural gas marketing, trading and resource management business. On June 30, 2007, Avista Energy completed the sale of substantially all of its contracts and ongoing operations. See Note 3 for further information. Advantage IQ is a provider of facility information and cost management services for multi-site customers throughout North America. See Note 14 for business segment information.

The Company’s operations are exposed to risks including, but not limited to:

 

   

streamflow and weather conditions that impact hydroelectric generation, utility operations and customer demand,

 

   

market prices and supply of wholesale energy, which the Company purchases and sells, including power, fuel and natural gas,

 

   

regulatory disallowance of the recovery of power and natural gas costs, operating costs and capital investments,

 

   

the effects of changes in legislative and governmental regulations, including restrictions on emissions from generating plants and requirements for the acquisition of new resources,

 

   

changes in regulatory requirements,

 

   

availability of generation facilities,

 

   

competition, and

 

   

availability of funding at a reasonable cost.

Also, like other utilities, the Company’s facilities and operations are exposed to terrorism risks or other malicious acts. In addition, the energy business exposes the Company to the financial, liquidity, credit and price risks associated with wholesale purchases and sales of energy commodities.

Basis of Reporting

The consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries, including variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Intercompany balances were eliminated in consolidation. The accompanying financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants.

 

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AVISTA CORPORATION

 

 

Taxes Other Than Income Taxes

Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled $19.2 million for the three months ended March 31, 2008 and $18.0 million for the three months ended March 31, 2007.

Other Income-Net

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

 

     2008     2007  

Interest income

   $ 216     $ 2,474  

Interest on power and natural gas deferrals

     968       1,203  

Equity-related Allowance for Funds Used During Construction

     893       907  

Net gain (loss) on investments

     (94 )     444  

Other expense

     (958 )     (1,424 )

Other income

     18       107  
                

Total

   $ 1,043     $ 3,711  
                

Income Taxes

The Company accounts for income taxes under Statement of Financial Accounting Standards (SFAS) No. 109, “Accounting for Income Taxes.” Under SFAS No. 109, a deferred tax asset or liability is determined based on the enacted tax rates that will be in effect when the differences between the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company’s consolidated income tax returns. The deferred tax expense for the period is equal to the net change in the deferred tax asset and liability accounts from the beginning to the end of the period. The effect on deferred taxes of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax liabilities and regulatory assets are established for tax benefits flowed through to customers as prescribed by the respective regulatory commissions.

The Company’s consolidated effective tax rate was 37.4 percent for the three months ended March 31, 2008 compared to 34.7 percent for the three months ended March 31, 2007. The increase in the effective tax rate was primarily due to changes in estimates related to the tax benefits expected to be realized for certain income tax credits.

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, net of tax, consisted of the following as of March 31, 2008 and December 31, 2007 (dollars in thousands):

 

     March 31,
2008
    December 31,
2007
 

Unfunded benefit obligation for pensions and other postretirement benefit plans

   $ (12,342 )   $ (12,782 )

Unrealized loss on interest rate swap agreements

     —         (6,826 )
                

Total accumulated other comprehensive loss

   $ (12,342 )   $ (19,608 )
                

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:

 

   

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

 

   

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

 

   

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

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 or credits 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 for all or a portion of its regulated operations, the Company could be:

 

   

required to write off its regulatory assets, and

 

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AVISTA CORPORATION

 

 

   

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,

 

   

investment in exchange power,

 

   

regulatory asset for deferred income taxes,

 

   

unamortized debt expense,

 

   

assets offsetting net utility energy commodity derivative liabilities (see Note 5 for further information),

 

   

expenditures for demand side management programs,

 

   

expenditures for conservation programs, and

 

   

unfunded pensions and other postretirement benefits.

Those items without a specific line on the Consolidated Balance Sheets are included in other regulatory assets.

Regulatory liabilities include:

 

   

utility plant retirement costs,

 

   

natural gas deferrals

 

   

settled interest rate swap agreements included as part of long-term debt, and

 

   

liabilities offsetting net utility energy commodity derivative assets (see Note 5 for further information).

Those items without a specific line on the Consolidated Balance Sheets are included in other current liabilities and other non-current liabilities and deferred credits.

NOTE 2. NEW ACCOUNTING STANDARDS

Effective January 1, 2008, the Company adopted the provisions of SFAS No. 157, “Fair Value Measurements” related to its financial assets and liabilities and nonfinancial assets and liabilities measured at fair value on a recurring basis. In February 2008, the FASB issued Staff Position No. 157-2, which deferred the effective date for certain portions of SFAS No. 157 related to nonrecurring measurements of nonfinancial assets and liabilities. The Company will be required to adopt those provisions of SFAS No. 157 in 2009. The adoption of the provisions of SFAS No. 157 that became effective on January 1, 2008, did not have a material impact on the Company’s financial condition and results of operations. However, the Company expanded disclosures with respect to fair value measurements. See Note 10 for the expanded disclosures.

Effective January 1, 2008, the Company adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure many financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option is elected would be reported in net income. The Company did not elect to use the fair value option under SFAS No. 159 for any financial assets and liabilities at implementation and as such the adoption of SFAS No. 159 did not have any impact on its financial condition and results of operations.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” This statement replaces SFAS No. 141 and addresses the accounting for all transactions or other events in which an entity obtains control of one or more businesses. This statement requires the acquiring entity in a business combination to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the transaction at the acquisition date, measured at their fair values as of that date, with limited exceptions. The Company would be required to begin applying this statement to any business combinations in 2009.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” This statement amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards for noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. This statement clarifies that a noncontrolling interest in a subsidiary is an ownership in the consolidated entity that should be reported as equity in the consolidated financial statements. The Company will be required to adopt SFAS No. 160 in 2009. The Company is evaluating the impact SFAS No. 160 will have on its financial condition and results of operations.

 

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AVISTA CORPORATION

 

 

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” This statement will require disclosure of the fair value of derivative instruments and their gains and losses in a tabular format. The statement will also require disclosure of derivative features that are related to credit risk. The Company will be required to adopt SFAS No. 161 in 2009. The Company does not expect the adoption of SFAS No. 161 to have any impact on its financial condition and results of operations. However, the Company will have expanded disclosures with respect to derivatives and hedging activities.

NOTE 3. DISPOSITION OF AVISTA ENERGY

On June 30, 2007, Avista Energy and Avista Energy Canada completed the sale of substantially all of their contracts and ongoing operations to Shell Energy North America (U.S.), L.P. (Shell Energy), formerly known as Coral Energy Holding, L.P., as well as to certain other subsidiaries of Shell Energy. Proceeds from the transaction included cash consideration for the net assets acquired by Shell Energy and the liquidation of the remaining net current assets of Avista Energy not sold to Shell Energy (primarily receivables, restricted cash and deposits with counterparties).

Certain assets of Avista Energy with a net book value of approximately $30 million were not sold or liquidated. These primarily include natural gas storage and deferred tax assets. The Company expects that the natural gas storage will ultimately be transferred to Avista Utilities, subject to future regulatory approval. The Company also expects that the power purchase agreement for the 270 megawatt (MW) natural-gas fired combined cycle combustion turbine plant located in Idaho (Lancaster Plant) for the period 2010 through 2026 will be transferred to Avista Utilities, subject to future regulatory approval.

In connection with the transaction, on June 30, 2007, Avista Energy and its affiliates entered into an Indemnification Agreement with Shell Energy and its affiliates. Under the Indemnification Agreement, Avista Energy and Shell Energy each agree to provide indemnification of the other and the other’s affiliates for certain events and matters described in the purchase and sale agreement entered into on April 16, 2007 and certain other transaction agreements. Such events and matters include, but are not limited to, the refund proceedings arising out of the western energy markets in 2000 and 2001 (see Note 12), existing litigation, tax liabilities, matters with respect to storage rights at Jackson Prairie, and any potential issues associated with the power purchase agreement for the Lancaster Plant. In general, such indemnification is not required unless and until a party’s claims exceed $150,000 and is limited to an aggregate amount of $30 million and a term of three years (except for agreements or transactions with terms longer than three years). These limitations do not apply to certain third party claims.

Avista Energy’s obligations under the Indemnification Agreement are guaranteed by Avista Capital pursuant to a Guaranty dated June 30, 2007. This Guaranty is limited to an aggregate amount of $30 million plus certain fees and expenses. Avista Capital granted Shell Energy a security interest in 50 percent of Avista Capital’s common shares of Advantage IQ as collateral for its Guaranty. The aggregate obligations secured by this security interest will in no event exceed $25 million. Avista Capital may substitute collateral, such as cash or letters of credit, in place of the security interest in Advantage IQ’s common shares. This security interest in Advantage IQ’s common shares will terminate on December 31, 2008 except to the extent of claims actually made prior to December 31, 2008. The Guaranty will terminate April 30, 2011 except with respect to claims made prior to termination.

As of May 1, 2008, neither party has made any claims under the Indemnification Agreement or Guaranty.

NOTE 4. 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 14, 2008, Avista Corp., ARC and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment extended the termination date to March 13, 2009. 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 other operating expenses of Avista Corp. The Receivables Purchase Agreement has financial covenants, which are substantially the same as those of Avista Corp.’s $320.0 million committed line of credit (see Note 7). As of March 31, 2008, $15.0 million in accounts receivables were sold under this revolving agreement, a decrease from $85.0 million as of December 31, 2007.

NOTE 5. ENERGY COMMODITY DERIVATIVES

The Company’s energy-related businesses are exposed to risks relating to, but not limited to:

 

   

changes in certain commodity prices, and

 

   

counterparty performance.

 

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Avista Utilities utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these exposures. The Company uses a variety of techniques to manage risks for their energy resources and wholesale energy market activities. The Company has a risk management policy and control procedures to manage these risks, both qualitative and quantitative. The Company’s Risk Management Committee establishes the Company’s risk management policy and control 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 engages in an ongoing process of resource optimization, which involves the economic selection from available resources to serve Avista Utilities’ load obligations and uses its existing resources to capture available economic value. Avista Utilities sells and purchases wholesale electric capacity and energy and fuel as part of the process of acquiring resources to serve its load obligations. These transactions range from terms of one hour up to multiple years. Avista Utilities makes continuing projections of:

 

   

loads at various points in time (ranging from one hour to multiple years) based on, among other things, estimates of factors such as customer usage and weather, as well as historical data and contract terms, and

 

   

resource availability at these points in time based on, among other things, estimates of streamflows, availability of generating units, historic and forward market information and experience.

On the basis of these projections, Avista Utilities makes purchases and sales of energy to match expected resources to expected electric load requirements. Resource optimization involves generating plant dispatch and scheduling available resources and also includes transactions such as:

 

   

purchasing fuel for generation,

 

   

when economic, selling fuel and substituting wholesale purchases for the operation of Avista Utilities’ resources, and

 

   

other wholesale transactions to capture the value of generation and transmission resources.

Avista Utilities’ optimization process includes entering into hedging transactions to manage risks.

As part of its resource optimization process described above, 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.

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, provides 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 electricity and natural gas. 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 above. In conjunction with the issuance of SFAS No. 133, the Washington Utilities and Transportation Commission (WUTC) and the Idaho Public Utilities Commission (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 Energy Recovery Mechanism in Washington and the Power Cost Adjustment mechanism in Idaho.

Substantially all forward contracts to purchase or sell power and natural gas 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.

 

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Utility energy commodity derivatives consisted of the following as of March 31, 2008 and December 31, 2007 (dollars in thousands):

 

     March 31,
2008
   December 31,
2007
 

Current utility energy commodity derivative assets

   $ 40,734    $ 12,078  

Current utility energy commodity derivative liabilities

     8,095      19,249  
               

Net current regulatory liability (asset)

   $ 32,639    $ (7,171 )
               

Non-current utility energy commodity derivative assets

   $ 73,136    $ 55,313  

Non-current utility energy commodity derivative liabilities

     1,039      1,899  
               

Net non-current regulatory liability

   $ 72,097    $ 53,414  
               

Non-current utility energy commodity derivative liabilities are included in other non-current liabilities and deferred credits on the Consolidated Balance Sheets.

NOTE 6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

The Company has a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities. 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 more than the maximum amounts that are currently deductible for income tax purposes. The Company contributed $15 million in cash to the pension plan in each of 2007, 2006 and 2005. The Company expects to contribute $28 million to the pension plan in 2008 ($7 million was contributed during the first quarter of 2008). The increase from original planned contributions of $15 million was a result of the new funding rules under the Pension Protection Act of 2006 and the Company’s ongoing commitment to increasing the funded status of the pension plan.

The Company also has a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to executive officers of the Company. The SERP is intended to provide benefits to executive officers whose benefits under the pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. The liability and expense for this plan are included as pension benefits.

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 liability and expense of this plan are included as other postretirement benefits.

The Company established a Health Reimbursement Arrangement to provide employees with tax-advantaged funds to pay for allowable medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on employees’ years of service and the ending salary. The liability and expense of this plan are included as other postretirement benefits.

The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement. Under the plan, an executive officer’s designated beneficiary will receive a payment equal to twice the executive officer’s annual base salary at the time of death (or if death occurs after retirement, a payment equal to twice the executive officer’s total annual pension benefit). The liability and expense for this plan are included as other postretirement benefits.

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):

 

     Pension Benefits     Other Post-
retirement Benefits
 
     2008     2007     2008     2007  

Service cost

   $ 2,552     $ 2,740     $ 149     $ 136  

Interest cost

     5,203       4,766       469       439  

Expected return on plan assets

     (5,274 )     (4,802 )     (391 )     (391 )

Transition obligation recognition

     —         —         126       126  

Amortization of prior service cost

     164       164       —         —    

Net loss recognition

     1,100       769       66       57  
                                

Net periodic benefit cost

   $ 3,745     $ 3,637     $ 419     $ 367  
                                

 

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NOTE 7. SHORT-TERM BORROWINGS

The Company has a committed line of credit agreement with various banks in the total amount of $320.0 million with an expiration date of April 5, 2011. Under the credit agreement, the Company can request the issuance of up to $320.0 million in letters of credit. The Company had $29.0 million of borrowings outstanding as of March 31, 2008 and no borrowings outstanding as of December 31, 2007. Total letters of credit outstanding were $44.9 million as of March 31, 2008 and $34.8 million as of December 31, 2007. The committed line of credit is secured by $320.0 million of non-transferable First Mortgage Bonds of the Company issued to the agent bank that 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 a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the preceding twelve-month period at the end of any fiscal quarter to be greater than 1.6 to 1. As of March 31, 2008, the Company was in compliance with this covenant with a ratio of 2.88 to 1. The committed line of credit agreement also has a covenant which does not 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, 2008, the Company was in compliance with this covenant with a ratio of 53.4 percent. If the proposed change in organization becomes effective (see Note 13), the committed line of credit will remain at Avista Corp.

In February 2008, Advantage IQ entered into a $12.5 million three-year credit agreement with a bank. Advantage IQ has the ability to increase the credit facility to $25 million under the same agreement. The credit agreement is secured by substantially all of Advantage IQ’s assets. Advantage IQ did not borrow any funds under the credit agreement through March 31, 2008.

NOTE 8. LONG-TERM DEBT

The following details the interest rate and maturity dates of long-term debt outstanding as of March 31, 2008 and December 31, 2007 (dollars in thousands):

 

Maturity
Year

  

Description

   Interest Rate     March 31,
2008
    December 31,
2007
 
2008    Secured Medium-Term Notes    6.06%-6.95 %   $ 45,000     $ 45,000  
2010    Secured Medium-Term Notes    6.67%-8.02 %     35,000       35,000  
2012    Secured Medium-Term Notes    7.37 %     7,000       7,000  
2013    First Mortgage Bonds    6.13 %     45,000       45,000  
2018    Secured Medium-Term Notes    7.39%-7.45 %     22,500       22,500  
2019    First Mortgage Bonds    5.45 %     90,000       90,000  
2023    Secured Medium-Term Notes    7.18%-7.54 %     13,500       13,500  
2028    Secured Medium-Term Notes (1)    6.37 %     25,000       25,000  
2032    Secured Pollution Control Bonds (2)    5.00 %     66,700       66,700  
2034    Secured Pollution Control Bonds (2)    5.13 %     17,000       17,000  
2035    First Mortgage Bonds    6.25 %     150,000       150,000  
2037    First Mortgage Bonds    5.70 %     150,000       150,000  
                     
  

Total secured long-term debt

       666,700       666,700  
                     
2008    Unsecured Senior Notes    9.75 %     272,860       272,860  
2023    Unsecured Pollution Control Bonds    6.00 %     4,100       4,100  
                     
  

Total unsecured long-term debt

       276,960       276,960  
                     
  

Other long-term debt and capital leases

       4,933       5,169  
                     
  

Interest rate swaps

       (15,370 )     1,083  
                     
  

Unamortized debt discount

       (987 )     (1,079 )
                     
  

Total

       932,236       948,833  
  

Current portion of long-term debt (3)

       (179,700 )     (427,344 )
                     
  

Total long-term debt

     $ 752,536     $ 521,489  
                     

 

(1) These Secured Medium-Term Notes with a maturity date of June 2028 are subject to redemption at the option of the security holders in June 2008. These notes are included in the current portion of long-term debt.

 

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(2) These Secured Pollution Control Bonds are subject to remarketing on December 30, 2008. These bonds are included in the current portion of long-term debt because they are subject to redemption at the option of the security holders on that date. If the bonds cannot be successfully remarketed on that date, the Company will be required to purchase the bonds.

 

(3) On April 3, 2008, the Company issued $250.0 million of 5.95 percent First Mortgage Bonds due in 2018. The net proceeds from the issuance of $247.5 million (net of discounts and before Avista Corp.’s expenses), together with other available funds, will be used to pay the $272.9 million of 9.75 percent Unsecured Senior Notes that mature on June 1, 2008. As such, $247.5 million of the $272.9 million of Unsecured Senior Notes is excluded from the current portion of long-term debt as of March 31, 2008.

NOTE 9. INTEREST RATE SWAP AGREEMENTS

Avista Corp. enters into forward-starting interest rate swap agreements to manage the risk associated with changes in interest rates and the impact on future interest payments. These interest rate swap agreements relate to the interest payments for the anticipated issuances of debt. 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.

In March 2008, the Company cash settled two interest rate swap agreements and paid a total of $16.4 million. These settlements were deferred as regulatory items (part of long-term debt) and will be amortized as a component of interest expense over the remaining ten year terms of the interest rate swap agreements (forecasted interest payments) in accordance with regulatory accounting practices. The Company does not have any interest rate swap agreements outstanding as of March 31, 2008.

NOTE 10. FAIR VALUE

As disclosed in Note 2, on January 1, 2008, the Company adopted the provisions of SFAS No. 157 related to its financial assets and liabilities and nonfinancial assets and liabilities measured at fair value on a recurring basis. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to the Company’s needs.

As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

 

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The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Consolidated Balance Sheet as of March 31, 2008 at fair value on a recurring basis (dollars in thousands):

 

     Total    Counterparty
Netting
    Level 1    Level 2    Level 3

Assets:

             

Energy commodity derivatives

   $ 113,870    $ (57,069 )   $ —      $ 38,700    $ 132,239

Deferred compensation assets

     9,144      —         9,144      —        —  
                                   

Total

   $ 123,014    $ (57,069 )   $ 9,144    $ 38,700    $ 132,239
                                   

Liabilities:

             

Energy commodity derivatives

   $ 9,134    $ (57,069 )   $ —      $ 19,943    $ 46,260

Deferred compensation liabilities

     9,144      —         9,144      —        —  
                                   

Total

   $ 18,278    $ (57,069 )   $ 9,144    $ 19,943    $ 46,260
                                   

Avista Utilities enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of our management of loads and resources and certain contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in respective levels and the amount of derivative assets and liabilities disclosed on the Consolidated Balance Sheets and at Note 5 is due to netting arrangements with certain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of our utility derivative commodity instruments included in Level 2. In particular, electric derivative valuations are performed using broker quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are performed using New York Mercantile Exchange (NYMEX) pricing, adjusted for basin differences, which are also quoted under NYMEX. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2. The Company also has certain contracts that primarily due to the length of the respective contract require the use of internally developed forward price estimates, which include significant inputs that may not be observable or corroborated in the market. These derivative contracts are included in Level 3. Refer to Note 5 for further discussion of the Company’s energy commodity derivative assets and liabilities.

Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an Executive Deferral Plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed excludes cash and cash equivalents of $2.3 million.

The following table presents activity for energy commodity derivative assets measured at fair value using significant unobservable inputs (dollars in thousands):

 

Beginning balance

   $ 98,943  

Total gains or losses (realized/unrealized)

  

Included in net income

     —    

Included in other comprehensive income

     —    

Included in regulatory assets/liabilities (1)

     37,078  

Purchases, issuances, and settlements, net

     (3,782 )

Transfers to other categories

     —    
        

Ending balance

   $ 132,239  
        

The following table presents activity for energy commodity derivative liabilities measured at fair value using significant unobservable inputs (dollars in thousands):

 

Beginning balance

   $ 36,506

Total gains or losses (realized/unrealized)

  

Included in net income

     —  

Included in other comprehensive income

     —  

Included in regulatory assets/liabilities (1)

     9,754

Purchases, issuances, and settlements, net

     —  

Transfers to other categories

     —  
      

Ending balance

   $ 46,260
      

 

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(1) 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. As such, the Company does not recognize unrealized gains or losses on utility derivative commodity instruments in the Consolidated Statements of Income. The Company recognizes realized gains or losses in the period of contract settlement, subject to regulatory 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 Energy Recovery Mechanism in Washington and the Power Cost Adjustment mechanism in Idaho.

NOTE 11. 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):

 

     2008     2007  

Numerator:

    

Net income

   $ 25,231     $ 14,094  

Subsidiary earnings adjustment for dilutive securities

     (76 )     (90 )
                

Adjusted net income for computation of diluted earnings per common share

   $ 25,155     $ 14,004  
                

Denominator:

    

Weighted-average number of common shares outstanding-basic

     53,020       52,684  

Effect of dilutive securities:

    

Contingent stock awards

     133       275  

Stock options

     229       363  
                

Weighted-average number of common shares outstanding-diluted

     53,382       53,322  
                

Total earnings per common share, basic

   $ 0.48     $ 0.27  
                

Total earnings per common share, diluted

   $ 0.47     $ 0.26  
                

Total stock options outstanding that were not included in the calculation of diluted earnings per common share were 315,750 for the three months ended March 31, 2008, and 26,200 for the three months ended March 31, 2007. 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.

NOTE 12. 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 because litigation and other contested proceedings are inherently subject to numerous uncertainties. With respect to matters that affect Avista Utilities’ operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the rate making process. With respect to matters discussed in this Note that affect Avista Energy (particularly the California Refund Proceeding), any potential liabilities or refunds remain at Avista Corp. and/or its subsidiaries and were not assumed by Shell Energy and/or its affiliates.

Federal Energy Regulatory Commission Inquiry

On April 19, 2004, the 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. In April 2005 and June 2005, the California Parties and the City of Tacoma, respectively, filed petitions for review of the FERC’s decisions approving the Agreement in Resolution with the United States Court of Appeals for the Ninth Circuit (Ninth Circuit). Based on the FERC’s order approving the Agreement in Resolution and the FERC’s denial of rehearing requests, the Company does not expect that this proceeding will have any material adverse effect on its financial condition, results of operations or cash flows.

 

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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 California Independent System Operator (CalISO) and the California Power Exchange (CalPX) during the period from October 2, 2000 to June 20, 2001 (Refund Period). The findings of the FERC administrative law judge were largely adopted in March 2003 by the FERC. The refunds ordered are based on the development of a mitigated market clearing price (MMCP) 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 to document these costs and limit its refund liability commensurately. In September 2005, Avista Energy submitted its cost filing claim pursuant to the FERC’s August 2005 order and demonstrated an overall revenue shortfall for sales into the California spot markets during the Refund Period after the MMCP methodology is applied to its transactions. That filing was accepted in orders issued by the FERC in January 2006 and November 2006. In its February 2007 status report, the CalISO stated that it intends to process Avista Energy’s cost offset filing (see further discussion regarding the California refund rerun below).

In 2001, Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) defaulted on payment obligations to the CalPX and the 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 to the CalPX. 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. As of March 31, 2008, 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.

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. In May 2004, the FERC provided notice that Avista Energy was no longer subject to this investigation. In March and April 2005, the California Parties and PG&E, respectively, petitioned for review of the FERC’s decision by 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 were 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. In September 2005, the Ninth Circuit held that the FERC did not have the authority to order refunds for sales made by municipal utilities in the California Refund Case. In its Order on Remand, issued in October 2007, the FERC ordered the CalISO and the CalPX to complete their refund calculations, including all entities that participated in the CalISO/CalPX markets (including those amounts that would have been paid by municipal utility entities for their sales into the CalISO and the CalPX spot markets during the refund period). The FERC then directed the CalISO to reduce refunds owed to refund recipients by the amounts attributable to municipal sales to the California markets.

In August 2006, the Ninth Circuit upheld October 2, 2000 as the refund effective date for the FPA section 206 Refund Proceeding, but remanded to the FERC its decision not to consider a FPA section 309 remedy for tariff violations prior to October 2, 2000. The Ninth Circuit also granted California’s petition for review challenging the FERC’s exclusion of the energy exchange transactions as well as the FERC’s exclusion of forward market transactions from the California refund proceedings. Petitions for rehearing were filed on November 16, 2007. It is unclear at this time what impact, if any, the Court’s remand might have on Avista Energy. The second round of issues and their corresponding briefing schedules have not yet been set by the Ninth Circuit.

The CalISO continues to work on its compliance filing for the Refund Period, which will show “who owes what to whom.” The CalISO completed the preparatory and the FERC refund reruns, as well as much of the financial adjustment phase and is now completing refund interest calculations. In its March 2008 status report, the CalISO stated that once the FERC addresses all of the “open issues” before it, the CalISO intends to: (1) perform the necessary adjustment to remove refunds associated with non-jurisdictional entities and allocate that shortfall to net refund recipients; and (2) work with the parties to the various global settlements to make appropriate adjustments to the CalISO’s data in order to properly reflect those adjustments. The CalISO did not present any date when it expects these efforts to be completed.

 

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Any potential liabilities or refunds owed by or to Avista Energy in the California Refund Proceeding were retained by Avista Corp. and/or its subsidiaries and have not been transferred to Shell Energy and/or its affiliates. Because the resolution of the California refund proceeding remains uncertain, legal counsel cannot express an opinion on the extent of the Company’s liability, if any. 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. This is primarily due to the fact that FERC orders have stated that any refunds will be netted against unpaid amounts owed to the respective parties and the Company does not believe that refunds would exceed unpaid amounts owed to the Company.

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 of wholesale energy in the Pacific Northwest between December 25, 2000, and June 20, 2001, were just and reasonable. During the hearing, Avista Corp., doing business as Avista Utilities, and Avista Energy vigorously opposed claims that rates for spot market sales were unjust and unreasonable and that the imposition of refunds would be appropriate. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of refunds. These equitable factors included the fact that the participants in the Pacific Northwest market include not only utilities and other entities that are subject to FERC jurisdiction, but also a very substantial number of governmental entities that are not subject to FERC jurisdiction with respect to wholesale sales and thus could not be ordered by the FERC to make refunds based on existing law. Seven petitions for review were filed with the Ninth Circuit challenging the merits of the FERC’s decision not to order refunds and raising procedural issues.

On August 24, 2007, the Ninth Circuit issued its opinion on the consolidated petitions for review of the Pacific Northwest refund proceeding. The Ninth Circuit found that the FERC, in denying the request for refunds, had failed to take into account new evidence of market manipulation in the California energy market and its potential ties to the Pacific Northwest energy market and that such failure was arbitrary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC’s findings must be reevaluated in light of the evidence. In addition, the Ninth Circuit concluded that the FERC abused its discretion in denying potential relief for transactions involving energy that was purchased in the Pacific Northwest and ultimately consumed in California. The Ninth Circuit expressly declined to direct the FERC to grant refunds. Requests for rehearing were filed on December 17, 2007.

Both Avista Utilities and Avista Energy were buyers and sellers of energy in the Pacific Northwest energy market during the period between December 25, 2000, and June 20, 2001, and, if refunds were ordered by the FERC, could be liable to make payments, but also could assert claims for refunds against FERC-jurisdictional entities. The opportunity to make claims against non-jurisdictional entities may be limited based on existing law. The Company cannot predict the outcome of this proceeding or the amount of any refunds that Avista Utilities or Avista Energy could be ordered to make or could be entitled to receive. Therefore, the Company cannot predict the potential impact the outcome of this matter could ultimately have on the Company’s results of operations, financial condition or cash flows.

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 should refund the difference between the rate charged and a just and reasonable rate. 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 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 Ninth Circuit. In September 2004, the Ninth Circuit upheld the FERC’s market-based rate authority, but held that the FERC erred in ruling that it lacked authority to order refunds for violations of its reporting requirement. The Court remanded the case for further proceedings, but did not order any refunds leaving it to the FERC to consider appropriate remedial options. Nonetheless, 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.

 

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In March, 2008, the FERC issued an order establishing a trial-type hearing to address “whether any individual public utility seller’s violation of the Commission’s market-based rate quarterly reporting requirement led to an unjust and unreasonable rate for that particular seller in California during the 2000-2001 period.” Purchasers in the California markets will be allowed to present evidence that “any seller that violated the quarterly reporting requirement failed to disclose an increased market share sufficient to give it the ability to exercise market power and thus cause its market-based rates to be unjust and unreasonable.” In particular, the parties are directed to address whether the seller at any point reached a 20 percent generation market share threshold, and if the seller did reach a 20 percent market share, whether other factors were present to indicate that the seller did not have the ability to exercise market power. 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.

Wah Chang Complaint

In May 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. This complaint was similar to the Port of Seattle and City of Tacoma complaints (which were dismissed by the United States District Court and the Ninth Circuit as disclosed in the Company’s prior Securities and Exchange Commission filings). 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 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 Ninth Circuit. On November 20, 2007, the Ninth Circuit dismissed Wah Chang’s appeal and affirmed the district court’s action. On December 3, 2007, Wah Chang filed a petition for rehearing with the Ninth Circuit. On January 15, 2008, the Ninth Circuit denied Wah Chang’s petition for rehearing. Based on the Ninth Circuit’s dismissal of this complaint, denial of the petition for rehearing, and expiration of the period for further appeals, the Company believes that this complaint will not have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

State of Montana Proceedings

In June 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.

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. In February 2004, the MPSC issued an order initiating investigation of the Montana retail electricity market for the purpose of determining 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.

Colstrip Generating Project Complaints

In May 2003, various parties (all of which are residents or businesses of Colstrip, Montana) filed complaints 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 foundation settlement caused by seepage from Colstrip’s freshwater surge pond. Avista Corp.’s ownership interest in the freshwater surge pond is approximately 11 percent. The plaintiffs also allege contamination and trespass damages resulting from leakage from several of Colstrip’s process ponds, most of which are for Units 1 & 2 ponds of which Avista Corp. has no ownership interest. The plaintiffs are seeking compensatory and punitive damages, an order by the court to remove certain ponds, and the forfeiture of profits earned from the generation of Colstrip. The owners of Colstrip have undertaken certain groundwater investigation and remediation measures to address groundwater contamination. These measures include improvements to the lakes and ponds of Colstrip. In April 2008, the owners of Colstrip reached a settlement with the plaintiffs. Under the settlement, Avista Corp.’s portion of the payment to the plaintiffs is $2.1 million. There is the potential for Avista Corp. to recover a portion of this payment through insurance. The Company is planning to file petitions with the WUTC and the IPUC to defer any payments as a regulatory asset, in order to allow for potential future recovery through the rate making process. The Company believes that there is a reasonable basis for the recovery of such costs through the rate making process.

 

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In March 2007, two families that own property near the holding ponds from Units 3 & 4 of Colstrip filed a complaint against the owners of Colstrip and Hydrometrics, Inc. in Montana District Court. The plaintiffs allege that the holding ponds and remediation activities have adversely impacted their property. They allege contamination, decrease in water tables, reduced flow of streams on their property and other similar impacts to their property. They also seek punitive damages, attorney’s fees and other relief similar to that asserted in the litigation described above. No trial date has been set. Because the resolution of this complaint 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 this complaint will have a material adverse effect on its financial condition, results of operations or cash flows.

Colstrip Royalty Claim

Western Energy Company (WECO) supplies coal to the owners of Colstrip Units 3 & 4 under a Coal Supply Agreement and a Transportation Agreement. Avista Corp. owns a 15 percent interest in Colstrip Units 3 & 4. The Minerals Management Service (MMS) of the United States Department of the Interior issued orders to WECO to pay additional royalties concerning coal delivered to Colstrip Units 3 & 4 via the conveyor belt. The owners of Colstrip Units 3 & 4 take delivery of the coal at the beginning of the conveyor belt. The orders assert that additional royalties are owed to 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, 2004. WECO’s appeal to the MMS for the period through 2001 was substantially denied in March 2005; WECO appealed the orders pertaining to the periods up to 2001 to the Board of Land Appeals of the U.S. Department of the Interior, which appeal was denied on September 12, 2007. WECO also filed an appeal with the MMS pertaining to the period from 2002 to 2004. The entire appeal process could take several years to resolve. Additional coal taxes may be owed to the state of Montana depending on the outcome of the MMS appeals. 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 and related taxes 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. Presumably, royalty and tax demands for periods of time after the years in dispute and future years will be determined by the outcome of the pending proceedings. Because the resolution of this issue remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. 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. However, the Company would most likely seek recovery, through the rate making process, of any amounts paid.

Northeast Combustion Turbine Site

In August 2005, a diesel fuel spill occurred at the Company’s Northeast Combustion Turbine generating facility (Northeast CT) located in Spokane, Washington. The Northeast CT site had fuel storage facilities that were leased to Co-op Supply, Inc., an affiliate of Cenex Cooperative (Co-op). The Company immediately commenced remediation efforts, including the removal of contaminated soil and the related fuel storage facilities. The Company accrued the estimated cleanup costs during 2005, which was not material to the Company’s consolidated financial condition or results of operations. Through mediation the Company recovered a substantial portion of the cleanup costs from Co-op and an engineering firm in the fourth quarter of 2006. 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.

Harbor Oil Inc. Site

Avista Corp. used Harbor Oil Inc. (Harbor Oil) for the recycling of waste oil and non-PCB transformer oil in the late 1980s and early 1990s. In June 2005, the Environmental Protection Agency (EPA) Region 10 provided notification to Avista Corp. and several other parties, as customers of Harbor Oil, that the EPA had determined that hazardous substances were released at the Harbor Oil site in Portland, Oregon and that Avista Corp. and several other parties may be liable for investigation and cleanup of the site under the Comprehensive Environmental Response, Compensation, and Liability Act, commonly referred to as the federal “Superfund” law. The initial indication from the EPA is that the site may be contaminated with PCBs, petroleum hydrocarbons, chlorinated solvents and heavy metals. Six potentially responsible parties, including Avista Corp., signed an Administrative Order on Consent with the EPA on May 31, 2007 to conduct a remedial investigation and feasibility study (RI/FS). The total cost of the

 

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RI/FS is estimated to be $1.2 million and will take approximately 2 1/2 years to complete. The actual cleanup, if any, will not occur until the RI/FS is complete. Based on the review of its records related to Harbor Oil, the Company does not believe it is a major contributor to this potential environmental contamination based on the relative volume of waste oil delivered to the Harbor Oil site. However, there is currently not enough information to allow the Company to assess the probability or amount of a liability, if any, being incurred. As such, it is not possible to make an estimate of any liability at this time.

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 Ninth Circuit. The United States Supreme Court affirmed this decision in June 2001. This ownership decision 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 annual generation of 10 aMW, utilizes a dam on the Spokane River downstream of the Lake which controls the water level in 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 related 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. The Company intends to seek recovery, through the rate making process, of any amounts paid.

Spokane River Relicensing

The Company owns and operates six hydroelectric plants on the Spokane River, and five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls, which have a total present capability of 155.7 MW) are under one FERC license and are referred to as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. Since the FERC was unable to issue new license orders prior to the August 1, 2007 expiration of the current license, an annual license was issued, in effect extending the current license and its conditions until August 1, 2008. The Company has no reason to believe that Spokane River Project operations will be interrupted in any manner relative to the timing of the FERC’s actions.

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 filed its new license applications with the FERC in July 2005. The Company requested the FERC to consider a license for Post Falls, which has a present capability of 18 MW, that is separate from the other four hydroelectric plants because Post Falls presents more complex issues that may take longer to resolve than those relating to the rest of the Spokane River Project. If granted, the new licenses would have terms of 30 to 50 years. In the license applications, the Company proposed a number of measures intended to address the impact of the Spokane River Project and enhance resources associated with the Spokane River.

Since the Company’s July 2005 filing of applications to relicense the Spokane River Project, the FERC has continued various stages of processing the applications. In May 2006, the FERC issued a notice requesting other parties to provide terms and conditions regarding the two license applications. In response to that notice, a number of parties (including the Coeur d’Alene Tribe, the state of Idaho, Washington state agencies, and the United States Department of Interior (DOI)) filed either recommended terms and conditions, pursuant to Sections 10(a) and 10(j) of the Federal Power Act (FPA), or mandatory conditions related to the Post Falls application, pursuant to Section 4(e) of the FPA. The Company’s initial estimate of the potential cost of the conditions proposed for Post Falls total between $400 million and $500 million over a 50-year period. For the rest of the Spokane River Project, which is located in Washington, the Company’s initial estimate of the cost of meeting the recommended conditions, should they be included in a final license, totaled between $175 million and $225 million over a 50-year period. These cost estimates were based on the preliminary conditions and recommendations.

The Company requested a trial-type hearing in front of an Administrative Law Judge (ALJ) on facts related to the DOI’s mandatory conditions for Post Falls. In January 2007, the ALJ issued his ruling regarding the Company’s challenge of the facts. The Company believes that the ALJ’s findings supported, in several key areas, its analysis of the facts at hand. The ALJ’s factual findings also supported the DOI’s analysis in certain areas as well.

 

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The DOI issued final mandatory conditions for Post Falls on May 7, 2007, which reflected the findings of the ALJ. Most significantly, the DOI dropped an earlier proposed fishery condition. However, the DOI increased obligations that the Company could incur in other areas, such as wetlands restoration.

In July 2007, the FERC issued a Final Environmental Impact Statement (FEIS) after review and consideration of comments. This is the last administrative step for the FERC before the issuance of license orders; however, the FERC cannot proceed until several other matters are resolved, including Clean Water Act and Endangered Species Act issues as disclosed below. The Company continues to review the FEIS and related documents. While the Company believes the ultimate cost of relicensing will be less than its earlier projections as disclosed above, the Company has not finalized specific new cost estimates at this point.

The relicensing process also triggers review under the Endangered Species Act. In the FEIS, the FERC analyzed potential project impacts on listed and threatened endangered species, and has determined that the proposed action and continued operation of Post Falls and the rest of the Spokane River Project is not likely to adversely affect any threatened or endangered species. The Company prepared a draft Biological Assessment in 2005. The FERC has issued a Biological Assessment and formally requested concurrence from the United States Department of Fish and Wildlife Service (USFWS). The USFWS responded by letter, concurring with regards to bald eagles, and requesting additional information regarding bull trout. The Company filed a supplemental report to address the USFWS information request. The Company has continued informal consultation with the USFWS. If the FERC initiates formal consultation with the USFWS, additional evaluation will be required by the Company.

In addition, the Company must receive Clean Water Act Certification (CWAC) from the states of Idaho and Washington for the Spokane River Project. Applications for such certification were filed in July 2006 with each state. Both Idaho and Washington communicated to the Company that they were unable to complete the certifications within one year as mandated by the Clean Water Act. Subsequently, the Company withdrew these applications and re-filed for certification in June 2007. The Washington Department of Ecology (DOE) released its draft CWAC on April 7, 2008 for a 30 day public comment period. The Company will review and comment on the draft CWAC during the comment period. The DOE will issue a final CWAC following its assessment of the comments received. The FERC is precluded from issuing a license order until such CWACs are issued, or waived, by the states. The Company cannot predict the schedule for these final phases of relicensing.

The total annual operating and capitalized costs associated with the relicensing of the Spokane River Project will become better known and estimable as the process continues. The Company will continue to seek recovery, through the rate making process, of all such operating and capitalized costs.

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 completed the Gas Supersaturation Control Program (GSCP). The Idaho Department of Environmental Quality and the USFWS approved the GSCP in February 2004 and the FERC issued an order approving the GSCP in January 2005.

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. When river flows exceed the capacity of the powerhouse turbines, the excess flows would be diverted to the tunnels rather than released over the spillway. The Company has undertaken physical and computer modeling studies to confirm the feasibility and likely effectiveness of the tunnel solution. Analysis of the predicted total dissolved gas (TDG) performance indicates that the tunnels will not meet the performance criteria anticipated in the GSCP. In August 2007, the Gas Supersaturation Subcommittee concluded that the tunnel project does not meet the expectations of the GSCP and is not an acceptable project. As a result, the Company will continue meeting with key stakeholders to review and amend the GSCP which includes developing alternatives to the construction of the tunnels. The Company intends to seek recovery, through the rate making process, of the costs to address the dissolved atmospheric gas levels.

The USFWS has listed bull trout as threatened under the Endangered Species Act. The Clark Fork Settlement Agreement describes programs intended to restore bull trout populations in the project area. Using the concept of adaptive management and working closely with the USFWS, the Company is evaluating the feasibility of fish passage at Cabinet Gorge and Noxon Rapids. 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 bull trout population enhancement measures.

 

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Air Quality

The Company must be in compliance with requirements under the Clean Air Act and Clean Air Act Amendments for its thermal generating plants. The Company continues to monitor legislative developments at both the state and national level for the potential of further restrictions on sulfur dioxide, nitrogen oxide and carbon dioxide, as well as other greenhouse gas and mercury emissions.

In particular, the EPA finalized mercury emission regulations that will affect coal-fired generation plants, including Colstrip. The new EPA regulations establish an emission trading program to take effect beginning in January 2010, with a second phase to take effect in 2018. In addition, in 2006, the Montana Department of Environmental Quality (DEQ) adopted final rules for the control of mercury emissions from coal-fired plants that are more restrictive than EPA regulations. The new rules set strict mercury emission limits by 2010, and put in place a recurring ten-year review process to ensure facilities are keeping pace with advancing technology in mercury emission control. The rules also provide for temporary alternate emission limits provided certain provisions are met, and they allocate mercury emission credits in a manner that rewards the cleanest facilities. In February 2008, the United States Court of Appeals for the District of Columbia overturned the EPA’s mercury emissions regulations. However, this ruling is not expected to affect the Company’s current plans to comply with the more restrictive regulations adopted by the Montana DEQ as described below.

Compliance with these new and proposed requirements and possible additional legislation or regulations will result in increases to capital expenditures and operating expenses for expanded emission controls at the Company’s thermal generating facilities. The Company, along with the other owners of Colstrip, completed the first phase of testing on two mercury control technologies. Although the mercury reduction targets as mandated by the Montana DEQ have not been achieved, the owners of Colstrip are encouraged with the preliminary results and believe it should be possible to achieve the required emissions levels with further mercury control system optimization. Preliminary estimates indicate that the Company’s share of installation capital costs would be $1.3 million and annual operations and maintenance costs would increase by $2.8 million (beginning in mid-2009). The Company will continue to seek recovery, through the rate making process, of the costs to comply with various air quality requirements.

Residential Exchange Program

The residential exchange program is intended to provide access to the benefits of low-cost federal hydroelectricity to residential and small-farm customers of the region’s private (investor owned) and public utilities (governmental or customer owned). The Bonneville Power Administration (BPA) administers the residential exchange program under the Northwest Power Act. Previously, Avista Corp. and other private utilities in the Pacific Northwest executed settlement agreements with BPA to resolve each party’s rights and obligations under the residential exchange program. These settlements covered payment of benefits for the period October 1, 2001, through September 30, 2011. The payments Avista Corp. received under the agreements with the BPA were passed through to its residential and small-farm customers via a credit to their monthly electric bills.

Several public utilities and other parties filed suit against the BPA in the Ninth Circuit, challenging the validity of the agreements between Avista Corp. and the BPA, as well as BPA’s agreements with other private utilities. On May 3, 2007, the Ninth Circuit ruled that the BPA exceeded its authority when it entered into the settlement agreements with private utilities (including Avista Corp.) for the period from 2001 through 2011. The BPA concluded that the Ninth Circuit’s decisions created substantial doubt about whether its certifying official could allow continuation of payments under the settlement agreements. Consequently, on May 21, 2007, the BPA notified Avista Corp. and other private utilities that it was immediately suspending payments the BPA made to them pursuant to the settlement agreements. In its May 21, 2007 notice, the BPA indicated that the suspension of payments would continue at least until any requests for rehearing were filed and the Ninth Circuit issued final decisions on those requests for rehearing. On July 18, 2007 Avista Corp. and numerous other parties, including the Public Utility Commission of Oregon and the WUTC, filed petitions for review, and review en banc, in the Ninth Circuit, challenging the ruling of the panel that struck down the settlement agreements. The Ninth Circuit subsequently denied these requests. Three private utilities, including Avista Corp., filed a petition for writ of certiorari with the United States Supreme Court.

In June 2007, with approval from the WUTC and the IPUC, Avista Corp. eliminated the credit associated with the settlement agreements with the BPA from its customers’ monthly electric bills.

Beginning in June 2007, the region’s private and public utilities worked toward an agreement that would identify an appropriate level of benefits for customers served by the private utilities, including the resolution of outstanding legal issues associated with the May 3, 2007 Ninth Circuit opinions. The BPA is working on a long-term resolution of residential exchange issues as part of its 2009 rate case. In addition to resolving residential exchange issues for the long-term, the BPA also proposed an interim payout of $336 million to private utilities for its fiscal year 2008. Avista Corp. accepted the interim offer from the BPA and received a payment of $9.6 million in April 2008. Rate adjustments to pass through the interim payment to Avista Corp.’s customers were approved by the WUTC and IPUC in April 2008.

 

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Since the residential exchange settlement payments are passed through to Avista Corp.’s customers as adjustments to electric bills, there is no effect on Avista Corp.’s net income. There is currently not enough information to allow Avista Corp. to assess the probability or amount of any potential liability that may be incurred related to any issues regarding payments made to Avista Corp. pursuant to the settlement agreements. Since 2001, Avista Corp. passed through to its customers approximately $70 million pursuant to the settlement agreements. The Company would seek recovery, through the rate making process, if payments were required to be made to the BPA.

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 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.

NOTE 13: POTENTIAL HOLDING COMPANY FORMATION

At the 2006 Annual Meeting of Shareholders in May 2006, the shareholders of Avista Corp. approved a proposal to proceed with a statutory share exchange, which would change the Company’s organization to a holding company structure. The holding company, currently named AVA Formation Corp. (AVA), would become the parent of Avista Corp. After the contemplated dividend to AVA of the capital stock of Avista Capital (Avista Capital Dividend) now held by Avista Corp., AVA would then also be the parent of Avista Capital. The Avista Capital Dividend would effect the structural separation of Avista Corp.’s non-utility businesses from its regulated utility business.

Avista Corp. received approval from the FERC in April 2006 (conditioned on approval by the state regulatory agencies), the IPUC in June 2006 and the WUTC in February 2007. Avista Corp. has also filed for approval from the utility regulators in Oregon and Montana and proceedings are pending in each of these jurisdictions. The statutory share exchange is subject to the receipt of the remaining regulatory approvals and the satisfaction of other conditions. If the statutory share exchange and the implementation of the holding company structure are approved by regulators on terms acceptable to the Company, it may be completed sometime in 2008.

The IPUC accepted a stipulation entered into between Avista Corp. and the IPUC Staff that sets forth a variety of conditions, which would serve to segregate the Company’s utility operations from the other businesses conducted by the holding company. The stipulation would require Avista Corp. to maintain certain common equity levels as part of its capital structure. Avista Corp. committed to increase its actual utility common equity component to 35 percent by the end of 2007 and 38 percent by the end of 2008, which is consistent with provisions of the Company’s Washington general rate case implemented on January 1, 2006. The calculation of the utility equity component is essentially the ratio of Avista Corp.’s total common equity to total capitalization excluding, in each case, Avista Corp.’s investment in Avista Capital. The utility equity component was approximately 45 percent as of March 31, 2008. In addition, IPUC approval would be required for any dividend from Avista Corp. to the holding company that would reduce utility common equity below 25 percent of total capitalization which, for this purpose, includes long and short-term debt, capitalized lease obligations and preferred and common equity.

The WUTC accepted a similar stipulation entered into between Avista Corp. and the WUTC staff. The stipulation requires Avista Corp. to increase its actual utility common equity component to 40 percent by June 30, 2008. In addition, WUTC approval would be required for any dividend from Avista Corp. to the holding company that would reduce utility common equity below 30 percent of total capitalization.

Pursuant to the Plan of Share Exchange, a statutory share exchange would be effected whereby each outstanding share of Avista Corp. common stock would be exchanged for one share of AVA common stock, no par value, so that holders of Avista Corp. common stock would become holders of AVA common stock and Avista Corp. would become a subsidiary of AVA. The other outstanding securities of Avista Corp. would not be affected by the statutory share exchange, with limited exceptions for stock options and other securities outstanding under equity compensation and employee benefit plans.

 

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NOTE 14. INFORMATION BY BUSINESS SEGMENTS

The business segment presentation reflects the basis 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. Advantage IQ is a provider of facility information and cost management services for multi-site customers throughout North America. The Other category, which is not a reportable segment, includes other investments and operations of various subsidiaries as well as certain other operations of Avista Capital.

In prior periods, the Company had a reportable Energy Marketing and Resource Management segment. The activities of this business segment were conducted primarily by Avista Energy. On June 30, 2007, Avista Energy and Avista Energy Canada completed the sale of substantially all of their contracts and ongoing operations to Shell Energy, as well as to certain other subsidiaries of Shell Energy. Completion of this transaction effectively ended the majority of the operations of this segment. This business still owns natural gas storage facilities and has operating revenues and resource costs related to the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of the power purchase agreement were assigned to Shell Energy through the end of 2009. Beginning in 2010, the Company expects these rights and obligations will be transferred to Avista Utilities, subject to future regulatory approval. These remaining activities do not represent a reportable business segment in 2008 and are included in the Other category for segment reporting purposes. The historical activities were reclassified to the Other category in accordance with the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

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

 

     Avista
Utilities
   Advantage
IQ
   Other     Total Non-
Utility
    Intersegment
Eliminations (1)
    Total

For the three months ended March 31, 2008:

              

Operating revenues

   $ 472,272    $ 12,520    $ 11,515     $ 24,035     $ —       $ 496,307

Resource costs

     318,226      —        5,920       5,920       —         324,146

Other operating expenses

     51,719      8,891      4,954       13,845       —         65,564

Depreciation and amortization

     21,442      624      385       1,009       —         22,451

Income (loss) from operations

     55,800      3,005      256       3,261       —         59,061

Interest expense (2)

     20,568      20      51       71       (14 )     20,625

Income taxes

     13,987      1,117      (15 )     1,102       —         15,089

Net income (loss)

     23,314      1,766      151       1,917       —         25,231

Capital expenditures

     47,680      1,086      13       1,099       —         48,779

For the three months ended March 31, 2007:

              

Operating revenues

   $ 414,266    $ 10,999    $ 33,922     $ 44,921     $ —       $ 459,187

Resource costs

     269,986      —        37,727       37,727       —         307,713

Other operating expenses

     49,041      7,827      9,309       17,136       —         66,177

Depreciation and amortization

     21,090      596      679       1,275       —         22,365

Income (loss) from operations

     50,154      2,576      (13,793 )     (11,217 )     —         38,937

Interest expense (2)

     22,021      81      227       308       (146 )     22,183

Income taxes

     10,997      912      (4,422 )     (3,510 )     —         7,487

Net income (loss)

     19,927      1,584      (7,417 )     (5,833 )     —         14,094

Capital expenditures

     40,556      758      581       1,339       —         41,895

Total Assets:

              

As of March 31, 2008

   $ 3,141,244    $ 108,557    $ 73,034     $ 181,591     $ —       $ 3,322,835

As of December 31, 2007

     3,009,499      108,929      71,369       180,298       —         3,189,797

 

(1) Intersegment eliminations reported as interest expense represent intercompany interest.

 

(2) Including interest expense to affiliated trusts.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Avista Corporation

Spokane, Washington

We have reviewed the accompanying consolidated balance sheet of Avista Corporation and subsidiaries (the “Corporation”) as of March 31, 2008, and the related consolidated statements of income, comprehensive income, and cash flows for the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Corporation’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Avista Corporation and subsidiaries as of December 31, 2007, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2007, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

 

/s/ Deloitte & Touche LLP

April 30, 2008

 

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

Forward-Looking Statements

From time to time, we make forward-looking statements such as statements regarding projected or future:

 

   

financial performance,

 

   

capital expenditures,

 

   

dividends,

 

   

capital structure,

 

   

other financial items,

 

   

strategic goals and objectives, and

 

   

plans for operations.

These statements have underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our 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 except those of historical fact including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions.

Forward-looking statements (including those made in this Quarterly Report on Form 10-Q) are subject to a variety of risks and uncertainties and other factors. Most of these factors are beyond our control and many of them could have a significant effect on our operations, results of operations, financial condition or cash flows. This could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others:

 

   

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

 

   

changes in wholesale energy prices that can affect, among other things, cash needed to purchase electricity, natural gas for our retail customers and natural gas fuel for electric generation, and the value of surplus energy sold, as well as the market value of derivative assets and liabilities;

 

   

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

 

   

the effect of state and federal regulatory decisions affecting our ability to recover costs and/or earn a reasonable return including, but not limited to, the disallowance of costs that we have deferred;

 

   

the potential effects of legislation or administrative rulemaking, including the possible adoption of national or state laws requiring resources to meet certain standards and placing restrictions on greenhouse gas emissions to mitigate concerns over global climate changes;

 

   

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

 

   

the outcome of legal proceedings and other contingencies;

 

   

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

 

   

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

 

   

the ability to relicense and maintain licenses for our hydroelectric generating facilities at cost-effective levels with reasonable terms and conditions;

 

   

unplanned outages at any of our generating facilities or the inability of facilities to operate as intended;

 

   

unanticipated delays or changes in construction costs, as well as our ability to obtain required operating permits for present or prospective facilities;

 

   

natural disasters that can disrupt energy production or delivery, as well as the availability and costs of materials and supplies and support services;

 

   

blackouts or disruptions of interconnected transmission systems;

 

   

the potential for future terrorist attacks or other malicious acts, particularly with respect to our utility assets;

 

   

changes in the long-term climate of the Pacific Northwest, which can affect, among other things, customer demand patterns and the volume and timing of streamflows to our hydroelectric resources;

 

   

changes in future economic conditions in our service territory and the United States in general, including inflation or deflation;

 

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changes in industrial, commercial and residential growth and demographic patterns in our service territory;

 

   

the loss of significant customers and/or suppliers;

 

   

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

 

   

deterioration in the creditworthiness of our customers and counterparties;

 

   

our ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including our credit ratings, interest rates and other capital market conditions;

 

   

the effect of any change in our credit ratings;

 

   

changes in actuarial assumptions, the interest rate environment and the actual return on plan assets for our pension plan, which can affect future funding obligations, costs and pension plan liabilities;

 

   

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

 

   

increasing costs of insurance, changes in coverage terms and our ability to obtain insurance;

 

   

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

 

   

the potential effects of negative publicity regarding business practices, whether true or not, which could result in, among other things, costly litigation and a decline in our common stock price;

 

   

changes in technologies, possibly making some of the current technology obsolete;

 

   

changes in tax rates and/or policies; and

 

   

changes in our strategic business plans, which may be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses.

Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonable based on, without limitation, an examination of historical operating trends, data contained in our records and other data available from third parties. However, there can be no assurance that our 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. We undertake 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 us to predict all of such factors, nor can we assess the effect of each such factor on our 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.

In this Form 10-Q, we discuss our credit ratings. It is important to note that these credit ratings are not recommendations to buy, sell or hold securities. The ratings are subject to change or withdrawal at any time by the respective credit rating agencies. Each credit rating should be evaluated independently of any other ratings.

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

Potential Holding Company Formation

In May 2006, our shareholders approved a proposal to proceed with a statutory share exchange, which would change our organization to a holding company structure. If the implementation of the holding company structure is approved by regulators on terms acceptable to us, it may be completed sometime in 2008. See further information at “Note 13 of the Notes to Consolidated Financial Statements.”

Business Segments

We have two reportable business segments as follows:

 

   

Avista Utilities – generation, transmission and distribution of electric energy and distribution of natural gas to retail customers, as well as wholesale purchases and sales of energy commodities. Avista Utilities is an operating division of Avista Corp. comprising our regulated utility operations.

 

   

Advantage IQ – facility information and cost management services for multi-site customers. The activities of this business segment are conducted by Advantage IQ, an indirect subsidiary of Avista Corp.

In prior periods, we had a reportable Energy Marketing and Resource Management segment. The activities of this business segment were conducted primarily by Avista Energy, an indirect subsidiary of Avista Corp. On June 30, 2007, Avista Energy and Avista Energy Canada completed the sale of substantially all of their contracts and ongoing

 

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operations to Shell Energy, as well as to certain other subsidiaries of Shell Energy. Completion of this transaction effectively ended the majority of the operations of this segment. This business still owns natural gas storage facilities and has operating revenues and resource costs related to the power purchase agreement for the Lancaster Plant. The Lancaster Plant is owned by an unrelated third-party and all of the output from the plant is contracted to Avista Energy through 2026. The majority of the rights and obligations of the power purchase agreement were assigned to Shell Energy through the end of 2009. Beginning in 2010, we expect these rights and obligations will be transferred to Avista Utilities, subject to future regulatory approval. These remaining activities do not represent a reportable business segment in 2008 and are included in the Other category for segment reporting purposes. The historical activities were reclassified to the Other category in accordance with the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

We have other businesses including sheet metal fabrication, venture fund investments and real estate investments. These activities are conducted by various indirect subsidiaries of Avista Corp., including Advanced Manufacturing and Development (AM&D), doing business as METALfx. The Other category is not a reportable segment.

Avista Energy, Advantage IQ and the various other companies are subsidiaries of Avista Capital, which is a direct, wholly owned subsidiary of Avista Corp. Our total common stockholders’ equity was $939.1 million as of March 31, 2008, of which $74.1 million represented our investment in Avista Capital.

The following table presents net income (loss) for each of our business segments (and the other businesses) for the three months ended March 31 (dollars in thousands):

 

     2008    2007  

Avista Utilities

   $ 23,314    $ 19,927  

Advantage IQ

     1,766      1,584  

Other

     151      (7,417 )
               

Net income

   $ 25,231    $ 14,094  
               

Executive Level Summary

Overall

Our operating results and cash flows are primarily derived from:

 

   

regulated utility operations (Avista Utilities),

 

   

facility information and cost management services for multi-site customers (Advantage IQ).

In late 2007 and early 2008, Moody’s Investors Service and Standard & Poor’s upgraded our credit ratings, which resulted in an investment grade rating for our senior unsecured debt and corporate rating from each of these rating agencies. The upgrades reflect several steps taken over the past few years to lower our business risk profile and improve financial metrics. The most recent significant steps were the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007 and our general rate case settlement in Washington implemented on January 1, 2008.

Although we are pleased with the upgrades, it is important to note that we are at the lower end of the investment grade category and will continue to work towards improving our ratings. We intend to continue to focus on improving earnings and operating cash flows, controlling costs, reducing debt and debt service costs, while working to improve our credit ratings.

Our net income was $25.2 million for the three months ended March 31, 2008, an increase from $14.1 million for the three months ended March 31, 2007. This increase was primarily due to the $7.6 million net loss at Avista Energy (included in Other) in the first quarter of 2007 and increased earnings at Avista Utilities (primarily due to the implementation of a general rate increase in Washington).

Avista Utilities

Avista Utilities is our most significant business segment. Our utility operating and financial performance is dependent upon, among other things:

 

   

weather conditions,

 

   

the price of natural gas in the wholesale market, including the effect on the price of fuel for generation,

 

   

the price of electricity in the wholesale market, including the effects of weather conditions, natural gas prices and other factors affecting supply and demand, and

 

   

regulatory decisions, allowing our utility to recover costs, including purchased power and fuel costs, on a timely basis, and to earn a fair return on investment.

 

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Our hydroelectric generation was 96 percent of normal in 2007. Our hydroelectric generation was below normal (based on a 70-year average) for six of the past eight years. Due to colder than normal temperatures and lower than normal streamflows, our hydroelectric generation was below normal for the first quarter of 2008. Based on current snowpack conditions that are well above normal levels, we may have favorable hydroelectric generation conditions during the period May through July of 2008. Actual hydroelectric generation will depend on precipitation, temperatures and other variables during the remainder of the year.

Our utility net income was $23.3 million for the three months ended March 31, 2008, an increase from $19.9 million for the three months ended March 31, 2007 primarily due to an increase in gross margin (operating revenues less resource costs). The increase in net income was also partially due to a decrease in interest expense. This was partially offset by an increase in other operating expenses and taxes other than income taxes. The increase in gross margin was primarily due to the implementation of the general rate increase in Washington effective January 1, 2008. We recognized an expense of $3.4 million under the Energy Recovery Mechanism (ERM) in Washington for the first quarter of 2008 compared to $3.2 million for the first quarter of 2007.

We plan to continue to invest in generation, transmission and distribution systems with a focus on providing reliable service to our customers. Utility capital expenditures were $47.7 million for the first quarter of 2008. We expect utility capital expenditures to be approximately $200 million for 2008.

As approved by the WUTC, electric rates for our Washington customers increased by 9.4 percent (designed to increase annual revenues by $30.2 million) and natural gas rates increased by 1.7 percent (designed to increase annual revenues by $3.3 million) effective January 1, 2008. As approved by the Public Utility Commission of Oregon (OPUC) in March 2008, natural gas rates for our Oregon customers increased 0.7 percent effective April 1, 2008 (designed to increase annual revenues by $0.9 million) and will increase an additional 1.1 percent effective November 1, 2008 (designed to increase annual revenues by an additional $1.4 million).

In March 2008, we filed a general rate case in Washington requesting overall base rate increases averaging 10.3 percent for electric and 3.3 percent for natural gas. In April 2008, we filed a general rate case in Idaho requesting overall base rate increases averaging 16.7 percent for electric and 5.8 percent for natural gas. Any rate adjustments, if approved by the WUTC or IPUC, would most likely become effective in 2009.

Based primarily on the following, we expect utility net income to increase in 2008 as compared to 2007:

 

   

Implementation of the general rate increase in Washington effective January 1, 2008, which includes resetting the base level of power supply costs used in the ERM calculations.

 

   

The write-down of a turbine and the disallowance of debt repurchase costs in 2007.

 

   

A decrease in interest expense due to the maturity of the $273 million of 9.75 percent Unsecured Senior Notes on June 1, 2008. On April 3, 2008, we issued $250 million (net proceeds of $247.5 million before Company expenses) of 5.95 percent First Mortgage Bonds to fund a significant portion of this maturing debt.

 

   

We expect improved hydroelectric generation as compared to 2007 and an increase in electric and natural gas retail loads in 2008.

Advantage IQ

Advantage IQ had net income of $1.8 million for the three months ended March 31, 2008, an increase from $1.6 million for the three months ended March 31, 2007. This increase was primarily due to an increase in operating revenues as a result of customer growth, partially offset by decreased interest revenue on funds held for customers and increased operating expenses from expanding operations. As a result of the decline in short-term interest rates, net income may decrease slightly for the full year of 2008 as compared to 2007. Customer growth and operating efficiencies are expected to be offset by a decrease in Advantage IQ’s interest revenue.

Other Businesses

Over time as opportunities arise, we plan to dispose of assets and phase out operations that do not fit with our overall corporate strategy. However, we may invest incremental funds to protect our existing investments and invest in new businesses that fit with our overall corporate strategy. Net income for these operations was $0.2 million for the three months ended March 31, 2008 compared to a net loss of $7.4 million for the three months ended March 31, 2007. The net loss for 2007 was due to Avista Energy.

Liquidity and Capital Resources

We have a committed line of credit in the total amount of $320.0 million with an expiration date of April 2011. There were $29.0 million of cash borrowings outstanding and $44.9 million in letters of credit outstanding as of March 31, 2008.

 

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In March 2008, we amended our accounts receivable sales facility to extend the termination date to March 2009. Under this facility, we can sell without recourse, on a revolving basis, up to $85.0 million of accounts receivable. We had sold $15.0 million of accounts receivable under this facility as of March 31, 2008.

We have long-term debt maturities of $318 million in 2008, the majority of which is the $273 million of 9.75 percent Unsecured Senior Notes that mature on June 1, 2008. On April 3, 2008, we issued $250 million (net proceeds of $247.5 million before Company expenses) of 5.95 percent First Mortgage Bonds to fund a significant portion of this maturing debt.

We are planning to issue additional long-term debt during the second half of 2008 to fund other maturing debt, as well as to provide additional funding for capital expenditures and other corporate purposes.

Additionally, the current portion of long-term debt includes $25.0 million of Secured Medium-Term Notes with a maturity date of June 2028 that are subject to redemption at the option of the security holders in June 2008 and $83.7 million of Secured Pollution Control Bonds that are subject to remarketing on December 30, 2008. If the Secured Pollution Control Bonds cannot be successfully remarketed on that date, we will be required to purchase the bonds.

In December 2006, we entered into a sales agency agreement with a sales agent to issue up to 2 million shares of our common stock from time to time. We are currently planning to begin issuing common stock under this sales agency agreement during the second half of 2008.

Avista Utilities – Regulatory Matters

General Rate Cases

We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We will continue to file for rate adjustments to:

 

   

provide for recovery of operating costs and capital investments, and

 

   

more closely align earned returns with those allowed by regulators.

With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include in-service dates of major infrastructure investments and the timing of changes in major revenue and expense items. The following is a summary of our authorized rates of return in each jurisdiction:

 

Jurisdiction and service

   Implementation
Date
   Authorized
Overall Rate
of Return
    Authorized
Return on
Equity
    Authorized
Equity
Level
 

Washington electric and natural gas

   January 2008    8.20 %   10.2 %   46 %

Idaho electric and natural gas

   September 2004    9.25 %   10.4 %   43 %

Oregon natural gas

   April 2008    8.21 %   10.0 %   50 %

As approved by the WUTC, on January 1, 2008, electric rates for our Washington customers increased by an average of 9.4 percent, which is designed to increase annual revenues by $30.2 million. As part of this general rate increase, the base level of power supply costs used in the ERM calculations was updated. Also, on January 1, 2008, natural gas rates increased by an average of 1.7 percent, which is designed to increase annual revenues by $3.3 million.

In March 2008, we filed a general rate case with the WUTC requesting to increase base electric rates for our Washington customers by an average of 10.3 percent, which is designed to increase annual revenues by $36.6 million. We also requested to increase base natural gas rates for our Washington customers by an average of 3.3 percent, which is designed to increase annual revenues by $6.6 million. Our request is based on a proposed rate of return of 8.43 percent with a common equity ratio of 46.3 percent and a 10.8 percent return on equity. The WUTC generally has up to 11 months to review a general rate case filing.

As part of the general rate case settlement agreement that was modified and approved by the WUTC in December 2005, we agreed to increase the utility equity component to 35 percent by the end of 2007 and 38 percent by the end of 2008. If we do not meet those targets, it could result in a reduction to base rates of 2 percent for each target. The calculation of the utility equity component is essentially the ratio of our total consolidated common equity to total capitalization excluding, in each case, our investment in Avista Capital. The utility equity component was approximately 45 percent as of March 31, 2008.

In April 2008, we filed a general rate case with the IPUC requesting to increase overall base electric retail rates for our Idaho customers by an average of 16.7 percent, which is designed to increase annual revenues by $32.2 million. We also requested to increase base natural gas retail rates for our Idaho customers by an average of 5.8 percent,

 

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which is designed to increase annual revenues by $4.7 million. Our request is based on a proposed rate of return of 8.74 percent with a common equity ratio of 47.9 percent and a 10.8 percent return on equity. The IPUC generally has up to seven months to review a general rate case filing.

As approved by the OPUC in March 2008, natural gas rates for our Oregon customers increased 0.7 percent effective April 1, 2008 (designed to increase annual revenues by $0.9 million) and are expected to increase an additional 1.1 percent effective November 1, 2008 (designed to increase annual revenues by an additional $1.4 million). The November 1, 2008 increase is related to placing into service a natural gas construction project and the allocation of natural gas storage assets to our Oregon operations and may be adjusted downward if actual costs are lower than currently estimated. In March 2008, the OPUC also approved new book depreciation rates, which will reduce annual depreciation expense in Oregon by $3.4 million.

Oregon Senate Bill 408

The OPUC issued amended rules in September 2007 related to Oregon Senate Bill 408 (OSB 408). OSB 408 was enacted into law in 2005. These rules direct the utility to establish an automatic adjustment clause to account for the difference between income taxes collected in rates and taxes paid to units of government, net of adjustments, when that difference exceeds $100,000. The automatic adjustment clause may result in either rate increases or rate decreases and applies only to taxes paid and collected on or after January 1, 2006.

The rules provide for an “apportionment method” that uses a three-factor formula consisting of property, payroll and sales for regulated operations of the utility in Oregon as the numerator, and these same factors for the consolidated company as the denominator, to determine the amount of consolidated taxes paid that are properly attributed to Oregon operations. Under the rules, we determine the least of:

 

   

the properly attributed amount of taxes paid using the apportionment method,

 

   

the amount of taxes determined on a stand-alone basis for Oregon operations, and

 

   

total consolidated taxes paid.

We then compare this amount to taxes collected in rates to determine if a refund or surcharge is required.

As required by OPUC orders, we (along with other utilities in Oregon) filed a private letter ruling request with the Internal Revenue Service (IRS) in December 2006. The private letter ruling request sought guidance on whether OSB 408 and the related OPUC orders violate normalization rules for accounting for income taxes. The OPUC order issued in September 2007 required that all of the affected utilities in Oregon file amended private letter ruling requests by November 30, 2007 to reflect the latest amendments to the rules. In January 2008 the IRS issued its finding that the OSB 408 rules, as represented to them in our applications, meets their tax normalization requirements, and presents no violation. In February 2008, we reached a settlement-in-principle with respect to the refund liability for 2006 that was approved by the OPUC in April 2008. The approved settlement provides for a refund to customers of $1.5 million, including interest. In addition to the 2006 settlement amount, we recorded a liability for potential refunds to customers totaling $2.2 million for 2007 and the first quarter of 2008. Based on new rates implemented on April 1, 2008 through the Oregon general rate case, we believe that an appropriate level of taxes will be collected from our Oregon customers such that additional liabilities for potential refunds will not be required during the remainder of 2008. However, any final determination of refunds or surcharges to customers will ultimately be determined based on final calculations for the year as described above.

Natural Gas Decoupling

In February 2007, the WUTC approved the implementation of a natural gas decoupling mechanism. Decoupling separates the direct link between natural gas sales volume and the recovery of the fixed cost of providing service to our customers. Because our rate structure provides for recovery of the majority of fixed costs on a per-therm (sales volume) basis, energy efficiency and conservation objectives have been directly at odds with the recovery of fixed costs, which do not vary with the volume of natural gas sold. Our decoupling mechanism should allow us to recover lost margin resulting from lower usage by Washington customers due to conservation and price elasticity. However, the mechanism does not provide rate adjustments related to abnormal weather. The decoupling mechanism is a three-year “pilot” that began in January 2007. We are in the process of performing an independent evaluation of the decoupling mechanism. Continuation of the mechanism beyond 2009 is subject to review and approval by the WUTC. A rate adjustment in any one year would be limited to no more than 2 percent. Our first decoupling rate adjustment became effective November 1, 2007. The rate adjustment is designed to recover $0.3 million over a twelve-month period or a 0.2 percent increase for residential and commercial customers, representing 80 percent of the lost margin for the period January through June 2007.

Power Cost Deferrals and Recovery Mechanisms

The ERM is an accounting method used to track certain differences between actual power supply costs and the amount included in base retail rates for our Washington customers.

 

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This difference in power supply costs primarily results from changes in:

 

   

short-term wholesale market prices,

 

   

the level of hydroelectric generation,

 

   

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

 

   

retail loads.

The initial amount of power supply costs in excess of or below the level in retail rates, which we either incur the cost of, or receive the benefit from, is referred to as the deadband. The annual (calendar year) deadband amount is currently $4.0 million. We incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. We will share annual power supply cost variances between $4.0 million and $10.0 million with customers. As such, 50 percent of the annual power supply cost variance in this range is deferred for future surcharge or rebate to customers and we incur the cost of, or receive the benefit from, the remaining 50 percent. To the extent that the annual power supply cost variance from the amount included in base rates exceeds $10.0 million, 90 percent of the cost variance is deferred for future surcharge or rebate. We incur the cost of, or receive the benefit from, the remaining 10 percent of the annual variance beyond $10.0 million without affecting current or future customer rates. The following is a summary of the ERM:

 

Annual Power Supply Cost Variability

   Deferred for Future
Surcharge or Rebate
to Customers
    Expense or Benefit
to the Company
 

+/- $0 - $4 million

   0 %   100 %

+/- between $4 million - $10 million

   50 %   50 %

+/- excess over $10 million

   90 %   10 %

Under the ERM, we make an annual filing on or before April 1st of each year to provide the opportunity for the WUTC staff 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.

We have a Power Cost Adjustment (PCA) mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. In June 2007, the IPUC approved continuation of the PCA mechanism with the annual rate adjustment provision. The October 1 rate adjustments recover or rebate power costs deferred during the preceding, July-June, twelve-month period. The PCA rate surcharge, as approved by the IPUC, increased from 2.5 percent to 4.7 percent on October 1, 2007.

The following table shows activity in deferred power costs for Washington and Idaho during the three months ended March 31, 2008 (dollars in thousands):

 

     Washington     Idaho     Total  

Deferred power costs as of December 31, 2007

   $ 58,524     $ 21,163     $ 79,687  

Activity from January 1 – March 31, 2008:

      

Power costs deferred

     —         5,638       5,638  

Interest and other net additions

     684       285       969  

Recovery of deferred power costs through retail rates

     (9,299 )     (2,581 )     (11,880 )
                        

Deferred power costs as of March 31, 2008

   $ 49,909     $ 24,505     $ 74,414  
                        

Purchased Gas Adjustments

Effective November 1, 2007, natural gas rates decreased:

 

   

6.0 percent in Washington,

 

   

4.6 percent in Idaho, and

 

   

1.7 percent in Oregon.

These natural gas rate decreases are designed to pass through changes in purchased natural gas costs to our customers with no change in gross margin (operating revenues less resource costs) or net income. In Oregon, there is an ongoing review of the PGA mechanism used by all natural gas distribution companies in Oregon (including Avista Corp.). The outcome of this review could impact our PGA mechanism and natural gas purchasing and hedging strategies in Oregon. Total net deferred natural gas costs were a liability of $19.1 million as of March 31, 2008, a change from a net asset of $2.4 million as of December 31, 2007 primarily due to recovery from customers and deferral for future rebate to customers during the first quarter of 2008.

 

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Results of Operations

The following provides an overview of changes in our Consolidated Statements of Income for the three months ended March 31, 2008 as compared to the three months ended March 31, 2007. More detailed explanations are provided, particularly for operating revenues and operating expenses in the business segment discussions (Avista Utilities, Advantage IQ and the other businesses) that follow this section.

Utility revenues increased $58.0 million to $472.3 million as a result of increases in electric revenues of $36.1 million and natural gas revenues of $21.9 million. The increase in electric revenues was due to increased retail revenues (primarily due to the Washington general rate case) and wholesale revenues and sales of fuel. The increase in natural gas revenues was the result of increased wholesale and retail natural gas sales, primarily due to increased volumes.

Non-utility energy marketing and trading revenues decreased $23.0 million to $6.4 million. This category of revenues decreased significantly with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007.

Other non-utility revenues increased $2.1 million to $17.6 million as a result of an increase in revenues from Advantage IQ of $1.5 million primarily due to customer growth, partially offset by a decrease in interest earnings on funds held for customers (due to a decrease in interest rates). The remaining $0.6 million increase in other revenues was primarily due to increased sales at AM&D.

Utility resource costs increased $48.2 million due to increases in electric resource costs of $29.5 million and natural gas resource costs of $18.8 million. The increase in electric resource costs reflects an increase in base resource costs as set forth in the Washington general rate case, as well as higher purchased power and fuel costs due in part to a decrease in hydroelectric generation. The increase in natural gas resource costs primarily reflects an increase in the volume of natural gas purchases and increased amortization of deferred natural gas costs.

Utility other operating expenses increased $2.7 million primarily due to an increase of $1.5 million in electric generation operating and maintenance expenses, as well as a $1.7 million increase in electric distribution expenses. This was partially offset by slight decreases in certain administrative and general expenses, including outside services, injuries and damages, and pension and benefits costs.

Utility taxes other than income taxes increased $1.1 million primarily due to increased retail revenues and related taxes.

Non-utility resource costs decreased $31.8 million. This category of expenses decreased significantly with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007.

The net change in other non-utility operating expenses was a decrease of $3.3 million due to:

 

   

a decrease of $4.4 million in the other businesses due to the sale of Avista Energy’s ongoing operations, partially offset by

 

   

an increase of $1.1 million for Advantage IQ due to expanding operations.

Interest expense decreased $1.4 million due to the redemption of all outstanding preferred stock in September 2007 and the effect of long-term debt maturities during 2007, which were primarily funded with proceeds from the sale and liquidation of Avista Energy’s assets.

Capitalized interest decreased $0.3 million due in part to a decrease in the effective AFUDC rate from 9.1 percent to 8.2 percent with the implementation of the Washington general rate case on January 1, 2008.

Other income-net decreased $2.7 million primarily due to a decrease in interest income and interest on power and natural gas deferrals.

Income taxes increased $7.6 million primarily due to increased income before income taxes. Our effective tax rate was 37.4 percent for the three months ended March 31, 2008 compared to 34.7 percent for the three months ended March 31, 2007. The increase in our effective tax rate was primarily due to changes in estimates related to the tax benefits expected to be realized for certain income tax credits.

 

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Avista Utilities

Net income for the utility was $23.3 million for the three months ended March 31, 2008 compared to $19.9 million for the three months ended March 31, 2007. Utility income from operations was $55.8 million for the three months ended March 31, 2008 compared to $50.2 million for the three months ended March 31, 2007. This increase in income from operations was primarily due to increased gross margin (operating revenues less resource costs). This was partially offset by an increase in other utility operating expenses and taxes other than income taxes. The following table presents our operating revenues, resource costs and resulting gross margin for the three months ended March 31 (dollars in thousands):

 

     Electric    Natural Gas    Total
     2008    2007    2008    2007    2008    2007

Operating revenues

   $ 226,237    $ 190,168    $ 246,035    $ 224,098    $ 472,272    $ 414,266

Resource costs

     121,548      92,064      196,678      177,922      318,226      269,986
                                         

Gross margin

   $ 104,689    $ 98,104    $ 49,357    $ 46,176    $ 154,046    $ 144,280
                                         

Utility operating revenues increased $58.0 million and utility resource costs increased $48.2 million, which resulted in an increase of $9.8 million in gross margin. The gross margin on electric sales increased $6.6 million and the gross margin on natural gas sales increased $3.2 million. The increase in our electric and natural gas gross margin was primarily due to the implementation of general rate increases in Washington effective January 1, 2008. The increase was also partially due to colder weather in the first quarter of 2008 and customer growth.

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

 

     Electric Operating
Revenues
   Electric Energy
MWh sales
     2008    2007    2008    2007

Residential

   $ 88,483    $ 73,096    1,155    1,107

Commercial

     63,209      55,111    824    771

Industrial

     24,525      22,247    512    493

Public street and highway lighting

     1,470      1,406    6    6
                       

Total retail

     177,687      151,860    2,497    2,377

Wholesale

     30,676      26,308    311    342

Sales of fuel

     14,578      8,143    —      —  

Other

     3,296      3,857    —      —  
                       

Total

   $ 226,237    $ 190,168    2,808    2,719
                       

Retail electric revenues increased $25.8 million due to an increase in:

 

   

total MWhs sold (increased revenues $8.5 million) primarily due to customer growth and an increase in use per customer (primarily due to colder weather), and

 

   

revenue per MWh (increased revenues $17.3 million) primarily due to the Washington general rate increase implemented on January 1, 2008 and the elimination of the BPA residential exchange credit.

Wholesale electric revenues increased $4.4 million due to an increase in sales prices (increased revenues $7.5 million), partially offset by a decrease in sales volumes (decreased revenues $3.1 million).

When electric wholesale market prices are below the cost of operating our natural gas-fired thermal generating units, we sell the natural gas purchased for generation in the wholesale market as sales of fuel. Sales of fuel increased $6.4 million due to increased thermal generation resource optimization activities.

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

 

     Natural Gas
Operating Revenues
   Natural Gas
Therms Delivered
     2008    2007    2008    2007

Residential

   $ 116,755    $ 112,539    91,181    83,863

Commercial

     63,997      61,378    54,285    49,923

Interruptible

     1,465      1,588    1,524    1,561

Industrial

     2,116      2,068    2,030    1,881
                       

Total retail

     184,333      177,573    149,020    137,228

Wholesale

     58,861      43,534    72,043    65,463

Transportation

     1,688      1,675    42,331    43,805

Other

     1,153      1,316    269    238
                       

Total

   $ 246,035    $ 224,098    263,663    246,734
                       

 

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The $6.8 million increase in retail natural gas revenues was due to an increase in volumes (increased revenues $14.6 million), partially offset by lower retail rates (decreased revenues $7.8 million). We sold more retail natural gas in the first quarter of 2008 primarily due to colder weather and customer growth. The decrease in retail rates reflects the purchased gas adjustments implemented in the fourth quarter of 2007, partially offset by the Washington general rate increase implemented on January 1, 2008. The increase in our wholesale revenues of $15.3 million was due to an increase in prices (increased revenues $9.9 million) and an increase in volumes (increased revenues $5.4 million). Wholesale sales reflect the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process. Variances between the revenues and costs of the sale of resources in excess of load requirements are accounted for through the PGA mechanisms.

The following table presents our average number of electric and natural gas retail customers for the three months ended March 31:

 

     Electric
Customers
   Natural Gas
Customers
     2008    2007    2008    2007

Residential

   311,769    305,728    278,304    273,109

Commercial

   39,054    38,334    32,926    32,245

Interruptible

   —      —      39    41

Industrial

   1,384    1,368    258    259

Public street and highway lighting

   428    424    —      —  
                   

Total retail customers

   352,635    345,854    311,527    305,654
                   

The following table presents our utility resource costs for the three months ended March 31 (dollars in thousands):

 

     2008    2007  

Electric resource costs:

     

Power purchased

   $ 51,498    $ 39,879  

Power cost amortizations, net of deferrals

     6,241      6,662  

Fuel for generation

     39,782      34,131  

Other fuel costs

     15,350      10,896  

Other regulatory amortizations, net

     5,146      (2,354 )

Other electric resource costs

     3,531      2,850  
               

Total electric resource costs

     121,548      92,064  
               

Natural gas resource costs:

     

Natural gas purchased

     171,529      166,340  

Natural gas amortizations, net of deferrals

     21,588      8,490  

Other regulatory amortizations, net

     3,561      3,092  
               

Total natural gas resource costs

     196,678      177,922  
               

Total resource costs

   $ 318,226    $ 269,986  
               

Power purchased increased $11.6 million due in part to an increase in the prices (increased costs $6.6 million) reflecting an overall increase in wholesale markets. The increase was also due to an increase in the volume of power purchases (increased costs $5.0 million) primarily due to decreased hydroelectric generation and an increase in retail sales volumes (due to colder weather and customer growth).

Net amortization of deferred power costs was $6.2 million for the first quarter of 2008 compared to $6.7 million for the first quarter of 2007. During the first quarter of 2008, we recovered (collected as revenue) $9.3 million of previously deferred power costs in Washington and $2.6 million in Idaho. During the first quarter of 2008, we deferred $5.6 million of power costs in Idaho, as power supply costs exceeded the amount included in base retail rates. We did not defer any power costs in Washington during the first quarter of 2008, as power supply costs were within the $4.0 million deadband under the ERM.

Fuel for generation increased $5.7 million primarily due to an increase in thermal generation volumes (particularly Coyote Springs 2).

Other fuel costs increased $4.5 million. This represents fuel that was purchased for generation, but was later sold when conditions indicated that it was not economic to use the fuel in generation as part of the resource optimization process. The associated revenues are reflected as sales of fuel. Other fuel costs exceeded revenues we received from selling the natural gas. We account for this shortfall under the ERM in Washington and the PCA in Idaho. The increase in other fuel costs was primarily due to increased thermal generation resource optimization activities.

 

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Other regulatory amortizations increased $7.5 million primarily due to the elimination of the BPA residential exchange credit.

The expense for natural gas purchased for sale to customers increased $5.2 million primarily due to an increase in total therms purchased. This was primarily due to an increase in wholesale sales as part of the balancing of loads and resources as part of the natural gas procurement process, and partially due to an increase in retail sales volumes. This was partially offset by a decrease in natural gas prices. During the first quarter of 2008, we amortized $21.6 million of deferred natural gas costs compared to $8.5 million for the first quarter of 2007. This change reflects a decrease in natural gas prices and the deferral for future rebate to customers.

Advantage IQ

Net income for Advantage IQ was $1.8 million for the three months ended March 31, 2008 compared to $1.6 million for the three months ended March 31, 2007. Operating revenues increased $1.5 million and operating expenses increased $1.1 million. The increase in operating revenues was primarily due to the expansion of Advantage IQ’s customer base, partially offset by a decrease in interest revenue on funds held for customers (due to a decrease in interest rates). As of March 31, 2008, Advantage IQ had 413 customers representing 214,000 billed sites in North America, an increase from 403 customers and 199,000 billed sites as of December 31, 2007. The increase in operating expenses primarily reflects increased labor and other operational costs necessary to serve an expanding customer base. In the first quarter of 2008, Advantage IQ processed bills totaling $3.4 billion, an increase of $0.5 billion, or 16 percent, as compared to the first quarter of 2007.

Other Businesses

Net income from these operations was $0.2 million for the three months ended March 31, 2008 compared to a net loss of $7.4 million for the three months ended March 31, 2007. The net loss for 2007 was due to Avista Energy as a result of underperformance on the power side of the business and losses on the power purchase agreement for the Lancaster Plant. Operating revenues decreased $22.4 million and operating expenses decreased $36.5 million. Operating revenues and operating expenses decreased significantly with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007. The remaining non-utility energy marketing and trading revenues and non-utility resource costs primarily represent payments for the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were assigned to Shell Energy through the end of 2009. Beginning in 2010 through 2026, the rights and obligations of the power purchase agreement for the Lancaster Plant will be contracted to Avista Energy. We expect that these rights and obligations will be transferred to our regulated utility, subject to future approval by the WUTC and the IPUC.

New Accounting Standards

Effective January 1, 2008, we adopted the majority of the provisions of SFAS No. 157, “Fair Value Measurements,” related to our financial assets and liabilities and nonfinancial assets and liabilities measured at fair value on a recurring basis. In February 2008, the FASB issued Staff Position No. 157-2, which deferred the effective date for certain portions of SFAS No. 157 related to nonrecurring measurements of nonfinancial assets and liabilities. We will be required to adopt those provisions of SFAS No. 157 in 2009. The adoption of the provisions of SFAS No. 157 that became effective on January 1, 2008, did not have a material impact on our financial condition and results of operations. However, we expanded our disclosures with respect to fair value measurements. See “Note 10 of the Notes to Consolidated Financial Statements” for further information.

Effective January 1, 2008, we adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure many financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option is elected would be reported in net income. As we did not elect to use the fair value option under SFAS No. 159 for any financial assets and liabilities at implementation, the adoption of SFAS No. 159 did not have any impact on our financial condition and results of operations.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” This statement replaces SFAS No. 141 and addresses the accounting for all transactions or other events in which an entity obtains control of one or more businesses. We will be required to begin applying this statement to any business combinations in 2009.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” This statement amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards from noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. We will be required to adopt SFAS No. 160 in 2009. We are evaluating the impact SFAS No. 160 will have on our financial condition and results of operations.

 

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In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” This statement will require disclosure of the fair value of derivative instruments and their gains and losses in a tabular format. The statement will also require disclosure of derivative features that are related to credit risk. We will be required to adopt SFAS No. 161 in 2009. We do not expect the adoption of SFAS No. 161 to have any impact on our financial condition and results of operations. However, we will have expanded disclosures with respect to derivatives and hedging activities.

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. Our critical accounting policies that require the use of estimates and assumptions were discussed in detail in the 2007 Form 10-K and have not changed materially from that discussion.

Liquidity and Capital Resources

Review of Cash Flow Statement

Overall During the three months ended March 31, 2008, positive cash flows from operating activities of $44.5 million and a $29.0 million increase in the amount outstanding on our $320.0 million committed line of credit were used to fund the majority of our cash requirements. These cash requirements included utility capital expenditures of $47.7 million, the cash settlement of interest rate swap agreements of $16.4 million and dividends of $8.8 million.

Operating Activities Net cash provided by operating activities was $44.5 million for the three months ended March 31, 2008 compared to $90.3 million for the three months ended March 31, 2007. Net cash used by working capital components was $25.0 million for the three months ended March 31, 2008, compared to net cash provided of $26.6 million for the three months ended March 31, 2007. The net cash used during the three months ended March 31, 2008 primarily reflects an increase in accounts receivable (representing net cash owed from our customers primarily from wholesale transactions including sales of fuel, electricity and natural gas), as well as a decrease in the amount of accounts receivable sold under our revolving accounts receivable sales facility. This cash used was partially offset by positive cash flows from accounts payable (representing net cash owed to our vendors), other current liabilities, other current assets (primarily related to federal income taxes), materials and supplies, fuel stock and natural gas stored (representing the seasonal drawdown of natural gas inventory) and deposits from counterparties (representing cash received as collateral funds from counterparties at Avista Utilities).

The net cash provided during the three months ended March 31, 2007 primarily reflected positive cash flows from:

 

   

accounts receivable (representing net cash received from our customers),

 

   

materials and supplies, fuel stock and natural gas stored (representing the seasonal drawdown of natural gas inventory),

 

   

other current assets (representing a net decrease in income taxes receivable), and

 

   

other current liabilities (representing an increase in interest accrued).

This cash provided was partially offset by negative cash flows from:

 

   

accounts payable (representing net cash paid to our vendors), and

 

   

cash deposits with counterparties (representing cash posted as collateral at Avista Energy).

Significant non-cash items included $27.6 million of power and natural gas cost amortizations, net of deferrals, for the three months ended March 31, 2008, an increase from $14.9 million for the three months ended March 31, 2007. This was primarily due to an increase in deferrals of natural gas costs for future rebate to customers, as natural gas resource costs were below the amount included in rates. Significant changes in non-cash items also included the unrealized loss of $20.9 million on energy trading activities at Avista Energy for the first quarter of 2007.

Investing Activities Net cash used in investing activities was $47.1 million for the three months ended March 31, 2008, an increase compared to $39.2 million for the three months ended March 31, 2007. This was primarily due to an increase in utility property capital expenditures in the first quarter of 2008.

 

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Financing Activities Net cash provided by financing activities was $3.7 million for the three months ended March 31, 2008 compared to net cash used of $22.3 million for the three months ended March 31, 2007. During the first quarter of 2008, our short-term borrowings increased $29.0 million. Cash dividends paid increased to $8.8 million (or 16.5 cents per share) for the first quarter of 2008 from $7.6 million (or 14.5 cents per share) for the first quarter of 2007. In March 2008, we cash settled two interest rate swap agreements and paid a total of $16.4 million.

During the first quarter of 2007, our short-term borrowings decreased $4.0 million, which reflected a decrease in the amount of debt outstanding under our committed line of credit. Debt maturities were $12.3 million for the first quarter of 2007.

 

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Overall Liquidity

With the completion of the sale of substantially all of Avista Energy’s contracts and ongoing operations, our consolidated operating cash flows are primarily derived from the operations of Avista Utilities. The primary source of operating cash flows for our utility operations is revenues (including the recovery of previously deferred power and natural gas costs) from sales of electricity and natural gas. Significant uses of cash flows from our utility operations include the purchase of electricity and natural gas, and payment of other operating expenses, taxes and interest, with any excess being available for other corporate uses such as capital expenditures and dividends.

Over time, our operating cash flows usually do not fully support the amount required for utility capital expenditures. As such, from time to time, we need to access capital markets in order to fund these needs as well as fund maturing debt. See further discussion at “Capital Resources.”

We design operating and capital budgets to control operating costs and optimize capital expenditures, particularly for our regulated utility operations. In addition to operating expenses, we have continuing commitments for capital expenditures for construction, improvement and maintenance of utility facilities.

We will continue to periodically file for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align our earned returns with those allowed by regulators. Effective January 1, 2008, our rates in Washington increased (as approved by the WUTC), which is designed to increase annual electric revenues by $30.2 million and annual natural gas revenues by $3.3 million. We filed general rate cases in Washington in March 2008 and in Idaho in April 2008. See further details in the section “Avista Utilities - Regulatory Matters.”

With respect to our utility operations, when power and natural gas costs exceed the levels currently recovered from retail customers, net cash flows are negatively affected. Factors that could cause purchased power costs to exceed the levels currently recovered from our customers include, but are not limited to, higher prices in wholesale markets when we buy energy or an increased need to purchase power in the wholesale markets. Factors beyond our control that could result in an increased need to purchase power in the wholesale markets include, but are not limited to:

 

   

increases in demand (either due to weather or customer growth),

 

   

low availability of streamflows for hydroelectric generation,

 

   

unplanned outages at generating facilities, and

 

   

failure of third parties to deliver on energy or capacity contracts.

We monitor the potential liquidity impacts of increasing energy commodity prices for our utility operations. We believe that we have adequate liquidity to meet the increased cash needs of higher energy commodity prices through our:

 

   

$85.0 million revolving accounts receivable sales facility, and

 

   

$320.0 million committed line of credit.

Our utility has regulatory mechanisms in place that provide for the deferral and recovery of the majority of power and natural gas supply costs. However, if prices increase, deferral balances will increase, which will negatively affect our cash flow and liquidity until such costs, with interest, are recovered from customers.

Capital Resources

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings, consisted of the following as of March 31, 2008 and December 31, 2007 (dollars in thousands):

 

     March 31, 2008     December 31, 2007  
     Amount    Percent
of total
    Amount    Percent
of total
 

Current portion of long-term debt (1)

   $ 179,700    8.9 %   $ 427,344    21.6 %

Short-term borrowings

     29,000    1.5       —      —    

Long-term debt to affiliated trusts

     113,403    5.6       113,403    5.8  

Long-term debt (1)

     752,536    37.4       521,489    26.4  
                          

Total debt

     1,074,639    53.4       1,062,236    53.8  

Stockholders’ equity

     939,110    46.6       913,966    46.2  
                          

Total

   $ 2,013,749    100.0 %   $ 1,976,202    100.0 %
                          

 

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(1) On April 3, 2008, we issued $250.0 million of 5.95 percent First Mortgage Bonds due in 2018. The net proceeds from the issuance of $247.5 million (net of discounts and before our expenses), together with other available funds, will be used to pay the $272.9 million of 9.75 percent Unsecured Senior Notes that mature on June 1, 2008. As such, $247.5 million of the $272.9 million of Unsecured Senior Notes is excluded from the current portion of long-term debt as of March 31, 2008.

We need to finance capital expenditures and obtain additional working capital from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduces the amount of cash flow available to fund working capital, purchased power and natural gas costs, capital expenditures, dividends and other requirements. Our stockholders’ equity increased $25.1 million during the first quarter of 2008 primarily due to net income and other comprehensive income, partially offset by dividends.

We generally fund capital expenditures with a combination of internally generated cash and external financing. The level of cash generated internally and the amount that is available for capital expenditures fluctuates depending on a variety of factors. Cash provided by our utility operating activities is expected to be the primary source of funds for operating needs, dividends and capital expenditures for 2008. Borrowings under our $320.0 million committed line of credit may supplement these funds to the extent necessary.

We have long-term debt maturities of $318 million in 2008, the majority of which is the $273 million of 9.75 percent Unsecured Senior Notes that mature on June 1, 2008. On April 3, 2008, we issued $250 million (net proceeds of $247.5 million before Company expenses) of 5.95 percent First Mortgage Bonds to fund a significant portion of this maturing debt.

We are planning to issue additional long-term debt during the second half of 2008 to fund other maturing debt, as well as to provide additional funding for capital expenditures and other corporate purposes.

Additionally, the current portion of long-term debt includes $25.0 million of Secured Medium-Term Notes with a maturity date of June 2028 that are subject to redemption at the option of the security holders in June 2008 and $83.7 million of Secured Pollution Control Bonds that are subject to remarketing on December 30, 2008. If the Secured Pollution Control Bonds cannot be successfully remarketed on that date, we will be required to purchase the bonds.

We have a $320.0 million committed line of credit agreement with various banks with an expiration date of April 5, 2011. Under the agreement, we can request the issuance of up to $320.0 million in letters of credit. As of March 31, 2008, we had $29.0 million of borrowings outstanding under this committed line of credit. There were not any borrowings outstanding as of December 31, 2007. As of March 31, 2008, there were $44.9 million in letters of credit outstanding, an increase from $34.8 million as of December 31, 2007. The committed line of credit is secured by $320.0 million of non-transferable First Mortgage Bonds 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 we default on obligations under the committed line of credit.

Our committed line of credit agreement contains customary covenants and default provisions, including a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the preceding twelve-month period at the end of any fiscal quarter to be greater than 1.6 to 1. As of March 31, 2008, we were in compliance with this covenant with a ratio of 2.88 to 1. The committed line of credit agreement also has a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 70 percent at the end of any fiscal quarter. As of March 31, 2008, we were in compliance with this covenant with a ratio of 53.4 percent. If the proposed change in organization to a holding company structure becomes effective, the committed line of credit agreement will remain at Avista Corp. (Avista Utilities). See “Note 13 of the Notes to Consolidated Financial Statements” for further information on the proposed change in organization to a holding company structure.

Any default on the line of credit or other financing arrangements of Avista Corp. or any of our significant subsidiaries could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other such entities. Any defaults could also induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock. We do not guarantee the indebtedness of any of our subsidiaries. As of March 31, 2008, Avista Corp. and our subsidiaries were in compliance with all of the covenants of our financing agreements.

In December 2005, the WUTC issued an order approving the settlement agreement reached in our Washington general rate case with certain conditions. We agreed to increase the utility equity component to 35 percent by the end of 2007 and to 38 percent by the end of 2008. As further discussed at “Note 13 of the Notes to the Consolidated Financial Statements,” the IPUC accepted a stipulation that we entered with the IPUC Staff that sets forth a variety of conditions related to the proposed implementation of our holding company structure. One of the conditions provides for the

 

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same utility equity components that are required in our Washington general rate case implemented in January 2006. If we do not meet those targets, it could result in a reduction in base rates of 2 percent for each target in each of Washington and Idaho. We also entered into a settlement agreement in Washington related to our proposed holding company formation. In this settlement agreement, we committed to increase the utility equity component to 40 percent by June 30, 2008. However, the provision to reduce base rates by 2 percent does not apply if we fail to meet this target. If we fail to meet this Washington equity target at June 30, 2008, we will be required to use our most current actual equity ratio (in lieu of a hypothetical capital structure) in our next Washington general rate case filing (subsequent to June 30, 2008). The utility equity component was approximately 45 percent as of March 31, 2008.

In December 2006, we entered into a sales agency agreement with a sales agent to issue up to 2 million shares of our common stock from time to time. We are currently planning to begin issuing common stock under this sales agency agreement during the second half of 2008.

Off-Balance Sheet Arrangements

Avista Receivables Corporation (ARC) is our wholly owned, bankruptcy-remote subsidiary formed for the purpose of acquiring or purchasing interests in certain of our accounts receivable, both billed and unbilled. On March 14, 2008, 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 March 17, 2008 to March 13, 2009.

The Receivables Purchase Agreement was originally entered into on May 29, 2002 and provides us with cost-effective funds for:

 

   

working capital requirements,

 

   

capital expenditures, and

 

   

other general corporate needs.

Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 million of our 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. The Receivables Purchase Agreement has financial covenants, which are substantially the same as those of our $320.0 million committed line of credit. As of March 31, 2008, we had sold $15.0 million in accounts receivable under this revolving agreement.

Credit Ratings

The following table summarizes our credit ratings as of May 1, 2008:

 

     Standard & Poor’s (1)    Moody’s (2)    Fitch, Inc. (3)

Avista Corporation

        

Corporate/Issuer rating

   BBB-    Baa3    BB+

Senior secured debt (4)

   BBB+    Baa2    BBB

Senior unsecured debt

   BBB-    Baa3    BBB-

Preferred stock

   BB    Ba2    BB+

Avista Capital II (5)

        

Preferred Trust Securities

   BB    Ba1    BB+

AVA Capital Trust III (5)

        

Preferred Trust Securities

   BB    Ba1    BB+

Rating outlook

   Stable    Stable    Positive

 

(1) Ratings were upgraded in February 2008.

 

(2) Ratings were upgraded in December 2007.

 

(3) Ratings were upgraded in August 2007 and affirmed in February 2008.

 

(4) Based on our understanding of the methodology currently used by Standard & Poor’s, the rating on senior secured debt may depend on, among other things, the amount of our utility property (net of depreciation) relative to the amount of such debt outstanding and the amount currently issuable. Thus, the rating on senior secured debt as of any particular time may depend on factors affecting our utility property accounts, as well as factors affecting the principal amount of such debt issued and issuable, including factors affecting our net income.

 

(5) Only assets are subordinated debentures of Avista Corporation.

Each security rating agency has its own methodology for assigning ratings. Security ratings are not recommendations to buy, sell or hold securities. The ratings are subject to change or withdrawal at any time by the respective credit rating agencies. Each credit rating should be evaluated independently of any other ratings.

 

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Pension Plan

As of March 31, 2008, our pension plan had assets with a fair value that was less than the benefit obligation under the plan. We contributed $15 million to the pension plan in both 2006 and 2007. We plan to contribute $28 million to the pension plan in 2008 ($7 million was contributed during the first quarter). The increase from our original planned contributions of $15 million was a result of the new funding rules under the Pension Protection Act of 2006 and our ongoing commitment to increasing the funded status of the plan.

Dividends

The Board of Directors considers the level of dividends on our common stock on a regular basis, taking into account numerous factors including, without limitation:

 

   

our results of operations, cash flows and financial condition,

 

   

the success of our business strategies, and

 

   

general economic and competitive conditions.

Our net income available for dividends is primarily derived from our regulated utility operations.

The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock contained in our Restated Articles of Incorporation, as amended, and to long-term debt contained in various indentures. Covenants under the 9.75 percent Unsecured Senior Notes that mature on June 1, 2008 limit our ability to increase common stock cash dividends to no more than 5 percent over the previous quarter, unless certain conditions are met related to restricted payments. As of March 31, 2008, we met the conditions that would allow us to increase the common stock cash dividend in excess of 5 percent over the previous quarter.

In March 2008, Avista Corp. paid a quarterly dividend of $0.165 per share on its common stock, an increase of 10 percent or $0.015 per share, over the previous quarterly dividend.

As further discussed at “Note 13 of the Notes to the Consolidated Financial Statements,” the IPUC accepted a stipulation that we entered with the IPUC Staff that sets forth a variety of conditions if and when we implement a holding company structure. One of the conditions would require IPUC approval of any dividend to the holding company that would reduce utility common equity below 25 percent. We entered into a similar agreement in Washington. This agreement would require WUTC approval of any dividend to the holding company that would reduce utility common equity below 30 percent. The utility equity component was approximately 45 percent as of March 31, 2008.

Avista Utilities Operations

We expect utility capital expenditures to be approximately $200 million for 2008, and over $200 million in each of 2009 and 2010. In addition to ongoing needs for our distribution and transmission systems, significant projects include upgrades to generating facilities. These estimates of capital expenditures are subject to continuing review and adjustment. Actual capital expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements.

We are close to completing the acquisition of a wind generation site. We expect to construct a 50 MW generation facility at an estimated cost of approximately $120 million. This amount is not included in our estimates of utility capital expenditures disclosed above. Future generation resource decisions will be impacted by legislation for restrictions on greenhouse gas emissions and renewable energy requirements as discussed at “Environmental Issues and Other Contingencies.”

Advantage IQ Operations

In February 2008, Advantage IQ entered into a $12.5 million three-year credit agreement with a bank. Advantage IQ has the ability to increase the credit facility to $25 million under the same agreement. The credit agreement is secured by substantially all of Advantage IQ’s assets. Advantage IQ did not borrow any funds under the credit agreement through March 31, 2008.

Contractual Obligations

Our future contractual obligations have not changed materially from the amounts disclosed in the 2007 Form 10-K with the following exceptions:

As of March 31, 2008, we had $29.0 million of borrowings outstanding under our committed line of credit. There were not any borrowings outstanding as of December 31, 2007.

 

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The amount outstanding under our revolving accounts receivable sales financing facility decreased from $85.0 million as of December 31, 2007 to $15.0 million as of March 31, 2008. In March 2008, the termination date of this facility was extended from March 17, 2008 to March 13, 2009.

We expect to contribute $28 million to the pension plan in 2008, and $18 million in each of 2009, 2010, 2011 and 2012. Our prior estimate was $15 million for each year. The planned contribution for 2008 exceeds our minimum required contribution.

On April 3, 2008, we issued $250.0 million of 5.95 percent First Mortgage Bonds due in 2018. The net proceeds from the issuance of $247.5 million (net of discounts and before our expenses), together with other available funds, will be used to pay the $272.9 million of 9.75 percent Unsecured Senior Notes that mature on June 1, 2008.

Business Risk

Primarily through our utility operations, we are exposed to the following risks including, but not limited to:

 

   

streamflow and weather conditions that impact hydroelectric generation, utility operations and customer demand,

 

   

market prices and supply of wholesale energy, which we purchase and sell, including power, fuel and natural gas,

 

   

regulatory disallowance of the recovery of power and natural gas costs, operating costs and capital investments,

 

   

the effects of changes in legislative and governmental regulations, including restrictions on emissions from generating plants and requirements for the acquisition of new resources,

 

   

changes in regulatory requirements,

 

   

availability of generation facilities,

 

   

competition, and

 

   

availability of funding at a reasonable cost.

Also, like other utilities, our facilities and operations are exposed to natural disasters and terrorism risks or other malicious acts. See further reference to risks and uncertainties under “Forward-Looking Statements.”

Our business risk has not materially changed during the three months ended March 31, 2008. Please refer to the 2007 Form 10-K for further description and analysis of business risk including, but not limited to, commodity price, credit, other operating, interest rate and foreign currency risks.

Risk Management

We use a variety of techniques to manage risks for energy resources and wholesale energy market activities. We have a risk management policy and control procedures to manage these risks, both qualitative and quantitative. Please refer to the 2007 Form 10-K for discussion of risk management policies and procedures.

Environmental Issues and Other Contingencies

We are subject to environmental regulation by federal, state and local authorities. The generation, transmission, distribution, service and storage facilities in which we have an ownership interest are designed and operated in compliance with all applicable environmental laws.

We monitor legislative and regulatory developments at all levels of government with respect to environmental issues, particularly those with the potential to alter the operation and productivity of our generating plants.

Environmental laws and regulations may have the effect of:

 

   

increasing the costs of generating plants,

 

   

increasing the lead time for the construction of new generating plants,

 

   

requiring modification of our existing generating plants,

 

   

requiring existing generating plants to be curtailed or shut down,

 

   

increasing the risk of delay on construction projects,

 

   

reducing the amount of energy available from our generating plants, and

 

   

restricting the types of generating plants that can be built.

 

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As such, compliance with such environmental laws and regulations could result in increases to capital expenditures and operating expenses, as well as reductions in net generation. However, we intend to seek recovery of incurred costs through the rate making process.

Long-term global climate changes could have a significant effect on our business. Changing temperatures and precipitation, including snowpack conditions, affect the availability and timing of hydroelectric generation capacity. Changing temperatures could also increase or decrease customer demand. Our operations could also be affected by changes in laws and regulations intended to mitigate the risk of global climate changes, including restrictions on the operation of our power generation resources.

Greenhouse gas requirements could result in significant costs for us to comply with restrictions on carbon dioxide or other greenhouse gas emissions. Such requirements could also preclude us from developing certain types of generating plants.

We continue to monitor and evaluate the possible adoption of national, regional, or state greenhouse gas requirements. In particular, a greenhouse gas bill was passed by the legislature in the state of Washington and bills have been introduced in the U. S. Senate and House of Representatives. There will most likely be continuing activity in the near future.

In February 2007, the Governors of Arizona, California, New Mexico, Oregon and Washington started the Western Climate Initiative (WCI) for the purpose of developing regional strategies to address climate change. The Governors of Utah and Montana, and the Premiers of British Columbia and Manitoba subsequently joined the WCI. In August 2007, the WCI partners set an overall regional goal for reducing greenhouse gas emissions to 15 percent below 2005 levels by 2020. By August 2008, the WCI partners are expected to complete the design of a market-based mechanism to help achieve this reduction goal.

The greenhouse gas bill passed into law in the state of Washington during 2007 places significant restrictions on greenhouse gas emissions from any new generation plants built in the state of Washington. Furthermore, utilities are prevented from entering into contracts to purchase energy produced by plants in other states that do not meet the same restrictions. Currently, the only type of thermal generating plants that meet these restrictions are combined-cycle natural gas-fired generation turbines. This greenhouse gas bill sets goals to reduce emissions in the state of Washington to 1990 levels by 2020; to 25 percent below 1990 levels by 2035; and to 50 percent below 1990 levels by 2050.

Initiative Measure 937 (I-937) was passed into law through the General Election in Washington in November 2006. I-937 requires certain investor-owned, cooperative, and government-owned electric utilities (including Avista Corp.) to acquire new renewable energy resources and/or renewable energy credits in incremental amounts until those resources or credits equal 15 percent of the utility’s total retail load in 2020. I-937 also requires these utilities to meet biennial energy conservation targets beginning in 2012. Failure to comply with renewable energy and energy efficiency standards will result in penalties of at least $50 per MWh being assessed against a utility for each MWh it is deficient in meeting a standard. A utility would be deemed to comply with the renewable energy standard if it invests at least 4 percent of its total annual retail revenue requirement on the incremental costs of renewable resources and/or renewable credits.

Our most recent Electric Integrated Resource Plan (IRP), which we filed with the WUTC and the IPUC in September 2007, includes the acquisition of additional renewable resources such that, if the IRP is implemented, we would be compliant with the requirement by the various milestone dates. The IRP outlines a preferred resource strategy that calls for 350 MW of natural gas generation, 300 MW of wind generation, 87 MW of conservation, 38 MW of hydroelectric generation plant upgrades and 35 MW of other renewable generation by 2017. In response to the new laws in the state of Washington as described above, the IRP eliminates coal-based generation as a new resource. The amount of renewable resources in our future IRPs could change if the cost effectiveness of those resources changes.

In October 2007, we became a member of the Chicago Climate Exchange (CCX), North America’s only voluntary, verifiable and legally binding emissions reduction and trading marketplace for all six greenhouse gases. Members agree to reduce their greenhouse gas emissions by 6% from an established baseline by 2010. The CCX allows participants who exceed their reduction targets to bank or sell the excess CCX Carbon Financial Instruments. The audit establishing our baseline emissions is expected to be completed in the second quarter 2008.

For other environmental issues and other contingencies see “Note 12 of the Notes to Consolidated Financial Statements.”

 

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations: – Business Risk and – Risk Management,” “Note 5 of the Notes to Consolidated Financial Statements” and “Note 10 of the Notes to Consolidated Financial Statements.”

 

Item 4. Controls and Procedures

The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers as appropriate to allow timely decisions regarding required disclosure. Under the supervision and with the participation of the Company’s management, including the Company’s principal executive officer and principal financial officer, the Company has evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon the Company’s evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level as of March 31, 2008.

There have been no changes in the Company’s internal control over financial reporting that occurred during the first quarter of 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II. Other Information

 

Item 1. Legal Proceedings

See “Note 12 of the Notes to Consolidated Financial Statements” in “Part I. Financial Information Item 1. Consolidated Financial Statements.”

 

Item 1A. Risk Factors

Please refer to the 2007 Form 10-K for disclosure of risk factors that could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results or outcomes to differ materially from those discussed in our reports filed with the Securities and Exchange Commission (including this Quarterly Report on Form 10-Q), and elsewhere. These risk factors have not materially changed from the disclosures provided in the 2007 Form 10-K.

In addition to these risk factors, please also see “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements” for additional factors which could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.

 

Item 6. Exhibits

 

12        Computation of ratio of earnings to fixed charges and preferred dividend requirements*
15        Letter Re: Unaudited Interim Financial Information*
31.1    Certification of Chief Executive Officer*
31.2    Certification of Chief Financial Officer*
32        Certification of Corporate Officers (Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)**

 

* Filed herewith.

 

** Furnished herewith.

 

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

    AVISTA CORPORATION
    (Registrant)
Date: May 2, 2008     /s/ Malyn K. Malquist
   

Malyn K. Malquist

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

 

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