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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

AQUILA, INC.
(Exact name of registrant as specified in its charter)

Registrant's telephone number, including area code    816-421-6600

        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 ý    No o

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ý    No o

        Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

        Information regarding the consolidated financial statements is set forth on pages 3 through 16.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        Management's discussion and analysis of financial condition and results of operations can be found on pages 17 through 32.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        We are subject to market risk as described on pages 65 through 68 of our 2002 Annual Report on Form 10-K. See discussion on pages 31 through 32 for changes in market risk since December 31, 2002.

ITEM 4. CONTROLS AND PROCEDURES

        Information regarding disclosure controls and procedures can be found on page 32.

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

        Not applicable

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

        Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

        Not applicable.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS

        Not applicable.

ITEM 5. OTHER INFORMATION

        Not applicable.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

        Exhibits and Reports on Form 8-K can be found on page 33.

CERTIFICATIONS

        Certifications pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 can be found on pages 35 and 36.

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Part I. Financial Information

Item 1.    Financial Statements

Aquila, Inc.

Consolidated Statements of Income—Unaudited

See accompanying notes to consolidated financial statements.

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Aquila, Inc.

Consolidated Balance Sheets

See accompanying notes to consolidated financial statements.

4

Aquila, Inc.

Consolidated Statements of Comprehensive Income—Unaudited

Aquila, Inc.

Consolidated Statements of Common Shareholders' Equity

See accompanying notes to consolidated financial statements.

5

Aquila, Inc.

Consolidated Statements of Cash Flows—Unaudited

See accompanying notes to consolidated financial statements.

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AQUILA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.     Summary of Significant Accounting Policies

Basis of Presentation

        The accompanying unaudited consolidated financial statements have been prepared in accordance with the accounting policies described in the consolidated financial statements and related notes included in our 2002 Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 15, 2003. You should read our 2002 Form 10-K in conjunction with this report. The accompanying Consolidated Balance Sheet and Consolidated Statement of Common Shareholders' Equity as of December 31, 2002, were derived from our audited financial statements, but do not include all disclosures required by accounting principles generally accepted in the United States. In our opinion, the accompanying consolidated financial statements reflect all adjustments (which include only normal recurring adjustments) necessary for a fair representation of our financial position and the results of our operations. Certain estimates and assumptions that affect reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of sales and expenses during the reporting periods shown have been made in preparing the consolidated financial statements. Actual results could differ from these estimates.

        Certain prior year amounts in the consolidated financial statements have been reclassified where necessary to conform to the 2003 presentation. In particular, sales and cost of sales have been reclassified to report energy trading gains and losses on a net basis pursuant to Emerging Issues Task Force Issue No. 02-3 (EITF 02-3), as discussed below under the caption "Energy Trading Activities." Also, as discussed in Note 3, the results of operations from certain assets which were sold in 2002 and early 2003 have been reclassified as discontinued operations in the accompanying statements of income for all periods presented.

Stock Based Compensation

        We issue stock options to employees from time to time and account for these options under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25). All stock options issued are granted at the common stock's market price at date of issuance. This means we record no compensation expense related to stock options. We also offer employees a stock purchase plan that enables them to purchase our common stock at a 15% discount from the market price.

        Because we account for options and discounts under APB 25, we must disclose pro forma net income (loss) and earnings (loss) per share as if we reflected the estimated fair value of options and

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discounts as compensation expense. For the three months ended March 31, 2003 and 2002, our pro forma net income (loss) and diluted earnings (loss) per share would have been as follows:

        In April 2003, the Financial Accounting Standards Board (FASB) announced that it would require all companies to expense the value of employee stock options. The FASB plans to issue a new statement later this year that will further define the method of determining fair value and recognizing compensation expense. The new statement is expected to become effective in 2004.

New Accounting Pronouncements

Energy Trading Activities

        In June 2002, the EITF reached a consensus on a topic discussed in EITF No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." EITF No. 02-3 requires that gains and losses on energy trading contracts be shown net on the income statement whether or not they are settled physically. The adoption of this standard required the reclassification of all prior period sales and cost of sales to reflect the net gains and losses on energy trading contracts. This new standard became effective beginning in the third quarter of 2002. The adoption of this requirement had no impact on our gross profit, but it did result in a reduction of sales and cost of sales.

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        The following table reconciles gross sales and cost of sales previously reported to sales and cost of sales reported after the effects of EITF 02-3 and the reclassification of discontinued operations (discussed in Note 3) for the three-month period ended March 31, 2002:

Derivative Instruments

        In May 2003, FASB issued Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS 149). This Statement clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative as discussed in Statement 133. In addition, it also clarifies when a derivative contains a financing component that warrants special reporting in the statement of cash flows. SFAS 149 also amends certain other existing pronouncements regarding derivatives. It is generally effective for contracts entered into or modified after June 30, 2003, and should be applied prospectively. We are in the process of assessing the impact this standard will have on our financial position and results of operations.

2.     Restructuring Charges

        We recorded the following restructuring charges for the three months ended March 31, 2003:

        During the first quarter, we incurred a $5.3 million restructuring charge to exit portions of interest rate swaps related to our Clay County and Piatt County construction financing arrangements. As debt related to these facilities was paid down, our interest rate swaps exceeded the outstanding debt. Thus we reduced our position and realized the loss associated with the cancelled portion of the unfavorable swap. In April 2003, we repaid the outstanding balances on the Clay County and Piatt County debt and incurred an additional $17.5 million of expense to exit the remaining swap positions.

        During the first quarter of 2003, we recorded $1.0 million of severance costs in connection with the restructuring of Everest Connections. This resulted from a reduction of approximately

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128 employees. We expect to incur approximately $1.3 million of additional restructuring charges at Everest Connections for severance and related other costs in 2003.

        The following is a summary of the activity for accrued restructuring charges for the three months ended March 31, 2003:

(a)

The majority of this liability represents costs accrued for future unused leased office space which will be paid over various terms through 2015.

3.     Discontinued Operations

        In 2002 and early 2003, we sold our Texas natural gas storage facility, our Texas and Mid-Continent natural gas pipeline systems, including our natural gas and natural gas liquids processing assets and our ownership interest in the Oasis Pipe Line Company, our coal terminal and handling facility and our Merchant loan portfolio. In connection with these sales, we have reported the following unaudited results of operations from these assets in earnings from discontinued operations in the Consolidated Statements of Income for the three months ended March 31, 2003 and 2002.

4.     Earnings (Loss) per Common Share

        The table below shows how we calculated diluted earnings (loss) per share and diluted shares outstanding. Basic earnings (loss) per share and basic weighted average shares are the starting point in calculating the dilutive measures. To calculate basic earnings (loss) per share, divide earnings (loss)

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available for common shares by weighted average shares outstanding without adjusting for dilutive items. Diluted earnings per share is calculated by dividing earnings available for common shares, after assumed conversion of dilutive securities, by weighted average shares outstanding, adjusted for the effect of dilutive securities. As a result of the net loss in the three months ended March 31, 2003, the potential issuances of common stock were anti-dilutive and therefore not included in the calculation of diluted earnings (loss) per share.

5.     Divestitures

Quanta Services, Inc.

        We sold our remaining 11.6 million shares of Quanta Services in February 2003 at a net price of $2.90 per share, which approximated book value, for total proceeds of $33.6 million.

Australia

        In April 2003, we announced that we reached an agreement to sell our interests in Multinet Gas, United Energy Limited and AlintaGas Limited to a consortium of AlintaGas, AMP Henderson and their affiliates for approximately $589 million, which after fees, expenses and taxes is projected to yield net cash proceeds of approximately $445 million. These proceeds must first be applied to repay obligations outstanding under our $200.0 million, 364-day secured credit facility. Completion of the transaction is subject to United Energy shareholder approval, regulatory approvals and various other conditions. We expect to close the transaction and receive the above proceeds in the third quarter of 2003.

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6.     Reportable Segment Reconciliation

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7.     Financings

Revolving Credit Facility

        In April 2002, we entered into a revolving credit facility totaling $650.0 million. The credit facility consisted of two $325.0 million credit agreements, one with a maturity date of 364 days, the other three years. In April 2003, the 364-day credit facility was repaid in full and the unutilized portion of the three-year credit facility was terminated. The three-year facility is being used solely as support for letters of credit currently outstanding under the facility. The lenders have (a) required us to cash collateralize the letters of credit and (b) extended waivers on existing covenant violations until June 1, 2003. At April 30, 2003, $101.8 million of letters of credit were outstanding under this facility.

        During the second quarter, we intend to replace the letters of credit issued under the three-year facility with the new letter of credit facility discussed below.

364-Day Secured Credit Facility

        On April 11, 2003, we closed on a $200.0 million, 364-day secured loan. The borrower is UtiliCorp Australia, Inc., our wholly-owned subsidiary. At closing, we borrowed $100.0 million of the available $200 million. The interest rate on this financing is the London Inter Bank Offering Rate (LIBOR) (with a 3% floor) plus 4.0% for the first 90 days. After the first 90 days, the interest rate increases an additional 2% and will increase an additional 2% every subsequent 90 days with a maximum rate at maturity of LIBOR (with a 3% floor) plus 10%. We paid up front arrangement fees of $4.1 million. Proceeds from the initial borrowing were used to retire debt.

        On May 12, 2003, we exercised our option under the 364-day financing to borrow the remaining $100.0 million available under this facility. The proceeds were used to terminate our Acadia tolling agreement as discussed in Note 9. We paid additional arrangement fees of $4.1 million for this borrowing.

        The 364-day term loan facility is secured by (i) a pledge of the equity of a wholly-owned subsidiary that indirectly holds our interests in independent power projects, (ii) a pledge of the equity of a wholly-owned subsidiary that indirectly holds our Australian utility investments, (iii) a pledge of the equity of our two subsidiaries that own our interests in our power plants in Clay County and Piatt County, Illinois, and (iv) a pledge, junior to that in favor of the lenders under the Three-Year Secured Facility, of the equity of a wholly-owned subsidiary that indirectly holds our Canadian utility business. If we default on this loan, the lenders would be entitled to be fully repaid from the sale proceeds of this collateral before other creditors could assert their claims against the collateral.

        We are required to use certain funds to prepay amounts outstanding under the 364-day facility. These include:

(1)

all distributions and proceeds from our Australian investments and independent power project investments (See Note 5 regarding our announced sale transaction);



(2)

all distributions, proceeds and excess cash from our power plants in Clay County and Piatt County, Illinois;



(3)

all proceeds from any accounts receivable financing or sales program; and



(4)

all distributions and proceeds from our Canadian utility business to the extent not required to be used to repay outstanding amounts under the Three-Year Secured Credit Facility described below.

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        Among other restrictions, the 364-day facility contains the following debt covenants:

(1)

If the sale of our Australian equity investments has not been completed within 180 days from April 11, 2003, a formal public sale process will commence on both our Australian equity investments and our independent power project investments.



(2)

We are restricted from paying dividends, issuing additional debt, entering into any mergers or acquisitions not meeting a specified leverage requirement or the repurchase or redemption of common stock.



(3)

The fair market value of our collateral provided must be at least twice the value of the debt outstanding.

        We can voluntarily prepay amounts under the 364-day facility without penalty at any time. However, amounts that are repaid cannot be reborrowed. To the extent we default on any of our loan covenants, our interest rate will increase an additional 2% during the default period.

Three-Year Secured Credit Facility

        On April 11, 2003, we closed on a $430.0 million, three-year secured loan. The initial interest rate on the facility will be LIBOR (which has a 3% floor) plus 5.75%. In addition, we were required to pay up front arrangement fees of $17.8 million. Proceeds from the financing will be used to retire debt and support existing and future letters of credit.

        The three-year facility is secured by (i) $430.0 million first mortgage bonds issued under a new indenture that constitutes a lien on our existing and future Michigan and Nebraska tangible utility network assets, (ii) a pledge of the equity of a wholly-owned subsidiary that indirectly holds our Canadian utility business, and (iii) a pledge, junior to that in favor of the lenders under the 364-day secured credit facility, of the equity of a wholly-owned subsidiary that indirectly holds our interests in independent power projects. If we default on this loan, the lenders would be entitled to be fully repaid from the sale proceeds of this collateral before other creditors could assert their claims against the collateral.

        We have also committed to use reasonable efforts to obtain approvals that would provide these lenders additional utility assets as collateral for their loans. If, as a result of the addition of any such collateral, the value of the collateral securing the indenture exceeds 167% of the loan secured by the indenture, the pledge of the Canadian equity interest may be released and the interest rate would be reduced to LIBOR (which has a 3% floor) plus 5.00%. In April 2003, we filed applications with the state regulatory bodies in Colorado, Iowa, Kansas, Minnesota and Missouri requesting authority to pledge utility assets in their respective states.

        We are required to use certain funds to prepay amounts outstanding under the three-year facility unless the value of the collateral will, absent such payment, remain equal to at least 200% of the outstanding loan amount under this facility (subject to certain reductions following certain events). These funds include:

(1)

all proceeds from the disposition of any collateral subject to the lien of the first mortgage indenture; and



(2)

all distributions and proceeds from our Canadian utility business and independent power project investments so long as the applicable pledge agreements continue to secure this facility.

        In addition, the $430.0 million secured debt would become immediately due and payable if we do not complete an exchange offer, tender offer, refinancing or other retirement transaction with regard to 80% of the outstanding principal of our 7% senior note series due July 15, 2004 and our 6.875% senior

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note series due October 1, 2004, at least two weeks prior to their respective maturity dates. Among other restrictions, the three-year secured facility contains the following financial covenants:

(1)

We must maintain a ratio of total debt to total capital of not more than .75 to 1.00 as of September 30, 2003 and December 31, 2003, decreasing to .70 to 1.00 for quarters ending after December 31, 2003.



(2)

Beginning July 1, 2003, we must maintain a trailing twelve-month ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) from pledged assets to interest expense related to these assets of no less than 1.05 to 1.00, increasing to 2.0 to 1.0 for quarters ending after December 31, 2004.



(3)

Beginning July 1, 2003, we must maintain a trailing twelve-month ratio of debt outstanding on our pledged assets to EBITDA from our pledged assets of no more than 10.5 to 1.0, decreasing to 5.5 to 1.0 for quarters ending after June 30, 2004.

        The three-year facility also contains covenants that restrict certain activities including, among others, limitations on additional indebtedness, restrictions on acquisition and sale transactions, and restrictions on the amount that we can fund our unregulated merchant businesses and our Everest telecommunications business. In addition, we are prohibited from paying dividends and from making certain other payments if our senior unsecured debt is not rated at least Ba2 by Moody's and BB by Standard & Poor's, or if such a payment would cause a default under the three-year facility.

        Amounts under the three-year facility cannot be voluntarily prepaid except with payment of a make-whole amount. Amounts that are repaid cannot be reborrowed. To the extent we default on any of our loan covenants, our interest rate will increase an additional 2% during the default period.

Letter of Credit Facility

        In April 2003, we executed a 364-day Letter of Credit Agreement with a commercial bank. Under terms of the Agreement, the bank has committed to issue up to $200.0 million of letters of credit under the facility. Any letter of credit issued must be fully secured by cash deposits with the bank. We have the option to decrease the commitment amount at any time. The committed amount will automatically decrease to $175.0 million at June 30, 2003 and to $150.0 million at December 31, 2003. At April 30, 2003, $66.8 million of letters of credit have been issued under this facility.

Canadian Finance Subsidiary

        In June 2001, our wholly owned Canadian finance subsidiary, Aquila Networks Canada Finance Corporation, issued $200.0 million of 7.75% senior notes in the U.S. public debt market. Aquila has fully and unconditionally guaranteed these notes.

8.     Restatement of Consolidated Statement of Cash Flow

        As stated in our 2002 Annual Report, in 1997 through 2000, we entered into long-term gas contracts that require us to deliver natural gas to municipal utility customers over a period of 10 to 12 years. In exchange for our commitment to deliver the natural gas, we were paid in advance. We considered these contracts part of our energy trading operations. As such, both the receipt of the advance cash payments and the monthly cash outflows to purchase the gas to be delivered to the customers in satisfaction of our commitments were included in our Consolidated Statements of Cash Flows under the caption Net Changes in Price Risk Management Assets and Liabilities and included in Cash Flows From Operating Activities. These contracts were included under the caption Price Risk Management Liabilities in our Consolidated Balance Sheets prior to December 31, 2002, but are now separately disclosed as Long-term Gas Contracts.

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        In 2002, the EITF, in its deliberations regarding EITF 02-3, discussed a number of items related to energy trading and risk management activities. In order to more fully address certain of the items discussed, the EITF formed a working group. One of the items discussed by the working group was "prepaid gas contracts." These discussions included the cash flow presentation of contracts similar to our long-term gas contracts. Based on this discussion, and other accounting and industry discussions and guidance occurring in 2002, we believe that the current industry and accounting consensus is to report these contracts as financing activities in the statement of cash flows. As a result, we have reported these cash flows in accordance with the current accounting interpretations and guidance for all periods presented in our Consolidated Statements of Cash Flows. This resulted in a $23.3 million increase in Cash Flows From Operating Activities for the three months ended March 31, 2002, as compared to the amount previously reported. Cash Flows From Financing Activities changed by the corresponding amount, resulting in no change in total cash flow. This change had no impact on earnings or losses.

        The net effects of the change discussed above are shown in the following table:

9.     Acadia Tolling Contract

        In May 2003, we entered into an agreement to terminate the 20-year tolling contract on the Acadia power plant in Louisiana. We made a termination payment of $105.5 million, which will be included in restructuring charges in the second quarter of 2003, and were released from the remaining aggregate payment obligation of $833.9 million, or $43.5 million on an annual basis.

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

AQUILA, INC.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

        Except where noted, the following discussion refers to the consolidated entity, Aquila, Inc. Although we began the exit from our Wholesale Services business in the second quarter of 2002, during the periods covered by this report, our businesses were structured as follows: (a) Global Networks Group, consisting of two segments, (i) Domestic Networks, our electricity and gas utilities in seven mid-continent states, which also includes our communications business and our investment in Quanta Services, Inc. (sold in late 2002 and early 2003), and (ii) International Networks, our Canadian, Australian and United Kingdom investments in electric and gas utility businesses and our investment in New Zealand electric and gas utility businesses (sold in the third quarter of 2002); and (b) Merchant Services, consisting of two segments, (i) Capacity Services, our power generation, investments in independent power projects and our natural gas gathering and processing operations (currently classified as discontinued operations), and (ii) Wholesale Services, our North American and European commodity and client service businesses (including our capital business which is also currently classified as discontinued operations).

FORWARD-LOOKING INFORMATION AND RISK FACTORS

        This report contains forward-looking information, including statements that (i) we expect our rates to be increased in certain states where we have utility operations, (ii) we expect to receive net proceeds of approximately $445 million from the sale of our Australian investments in the third quarter of 2003, and (iii) our long-term liquidity depends upon the sale of non-strategic assets, restructuring of generation capacity obligations and reduction of long-term debt. The words "may," "will," "should," "expect," "anticipate," "intend," "plan," "believe," "seek," "estimate," or the negative of these terms or similar expressions identify further forward-looking statements. Similar statements that identify our objectives, plans and goals are forward-looking statements.

        These forward-looking statements involve risks and uncertainties, and there are certain important factors that can cause actual results to differ materially from those anticipated. Some of the important factors and risks that could cause actual results to differ materially from those anticipated include:

•

Regulatory commissions may modify or refuse to approve anticipated changes to our utility rates.



•

Counterparties may default on their obligations to return collateral to us or to meet their obligations under commercial contracts, including those designed to hedge against movements in commodity prices.



•

Our credit ratings and financial condition will limit our ability to access the capital markets we historically used to refinance our debt. Because we recently pledged a significant portion of our assets as collateral for loans, it will be difficult for us to obtain additional unsecured financing. We must obtain regulatory approvals to use the majority of our remaining unencumbered assets as collateral for additional loans.



•

If our financial condition improves in the short-term, the market prices for our long-term debt may increase and limit our ability to repurchase it at a significant discount. Our new credit agreements require us to use a significant portion of the proceeds from the sale of our assets to reduce our obligations to those lenders before retiring other debt.



•

The completion of the sale of our Australian investment is subject to various conditions, including regulatory and shareholder approvals and the completion of the purchaser's funding requirements. Therefore, it is possible that the transaction will not be completed, the purchase

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price will be adjusted or actual fees, expenses or taxes resulting from the transaction will be materially different than anticipated.

•

Our commitments under long-term gas delivery contracts and capacity generation contracts will generate significant losses and negative cash flows for an extended period of time. Because these obligations represent favorable contracts to the counterparties, absent a risk of our default, they may be unwilling to restructure or sell the contracts.



•

There are numerous ongoing state and federal investigations of the trading activities of companies that participated in the energy trading industry, including us. Companies that have violated laws or rules of the investigating agencies have been required to pay significant fines. Even if no wrongdoing is found, we could incur legal and accounting costs associated with complying with the discovery requests of the investigating bodies.

RESULTS OF OPERATIONS

Financial Review

        This review of performance is organized by business segment, reflecting the way we managed our business during the periods covered by this report. Each business group leader is responsible for operating results down to earnings before interest and taxes (EBIT). We use EBIT as a performance measure as it captures the income and expenses within the management control of our segment business leaders. Corporate management is responsible for making all financing decisions. Therefore, each segment discussion focuses on the factors affecting EBIT, while financing and income taxes are separately discussed at the corporate level.

        The use of EBIT as a performance measure is not meant to be considered an alternative to net income or cash flows from operating activities, which are determined in accordance with generally accepted accounting principles (GAAP), as an indicator of operating performance or as a measure of liquidity, or other performance measures used under GAAP. In addition, the term may not be comparable to similarly titled measures used by other companies.

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Key Factors Impacting EBIT

        Our total EBIT decreased significantly in the first quarter of 2003 compared to 2002. Key factors affecting 2003 results were as follows:

•

We began our exit from the wholesale energy trading business during the second quarter of 2002. This business contributed EBIT of $21.5 million in the first quarter of 2002, compared to a loss before interest and taxes of $52.6 million in 2003. Included in the $52.6 million loss for the first quarter of 2003 was approximately $27.0 million of non-cash losses related to the sale of all of our capacity under certain long-term gas transportation agreements at substantially less than our future commitments and $5.9 million related to terminating additional trading contracts. Our remaining first quarter 2003 margin losses mainly stem from mark-to-market losses and unfavorable settlements related to our trading portfolio, including highly-structured rainfall, streamflow and load-based fixed price sale transactions.



•

Wider spark spreads (the difference between the price at which electricity is sold and the cost of fuel used to generate it) in 2002 generated $21.4 million of favorable mark-to-market gains. As liquidity and spark spreads have since narrowed in the forward market, these gains did not recur in 2003. In addition, we recorded $16.0 million of unfavorable mark-to-market losses on long dated forward contracts.



•

In connection with our merchant power plants, we make fixed lease payments (capacity payments) evenly throughout the year. For the first quarter of 2003, capacity payments increased by $11.5 million compared to 2002 because new plants became operational late in 2002. This additional capacity was utilized on a limited basis at prices that were not sufficient to cover the fixed lease payments.



•

As a result of an unfavorable regulatory decision affecting the 2002 and 2003 rates recorded by our electric utility in Alberta, Canada, EBIT was reduced by $14.3 million in the first quarter of 2003.

Restructuring Charges

        We recorded the following restructuring charges for the three months ended March 31, 2003:

        During the first quarter of 2003, we incurred a $5.3 million restructuring charge to exit portions of interest rate swaps related to our Clay County and Piatt County construction financing arrangements. As debt related to these facilities was paid down, our interest rate swaps exceeded the outstanding debt. Thus, we reduced our position and realized the loss associated with the cancelled portion of the unfavorable swap. In April 2003, we repaid the outstanding balances on the Clay County and Piatt County debt and incurred an additional $17.5 million of expense to exit the remaining swap positions.

        We also recorded $1.0 million of severance costs during the first quarter of 2003, in connection with the restructuring of Everest Connections. This resulted from a reduction of approximately 128 employees. We expect to incur approximately $1.3 million of additional restructuring charges at Everest Connections for severance and other related costs in 2003.

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Discontinued Operations

        As further discussed in Note 3 to the Consolidated Financial Statements, in connection with the sale in 2002 of our Texas natural gas storage facility, our Texas and Mid-Continent natural gas pipeline systems, including our natural gas and natural gas liquids processing assets and our ownership interest in the Oasis Pipe Line Company, our coal terminal and handling facility and our Merchant loan portfolio, we have reported the results of operations of these assets in discontinued operations in the Consolidated Statements of Income. Unaudited operating results of discontinued operations for the three months ended March 31, 2003 and 2002 are as follows:

Quarter-to-Quarter

        The decrease in earnings from discontinued operations reflects the sale of substantially all of the assets of these businesses in the fourth quarter of 2002.

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DOMESTIC NETWORKS

        The table below summarizes the operations of our Domestic Networks for the three months ended March 31, 2003 and 2002.

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

        Sales, cost of sales and gross profit for the Domestic Networks businesses increased $16.9 million, $6.4 million and $10.5 million, respectively, in 2003 compared to 2002. Sales and cost of sales for our regulated gas networks increased approximately $123.3 million and $106.0 million, respectively, for a net increase in gross profit of $17.3 million. These increases were due to a 31% increase in natural gas prices and an 8% increase in volumes sold. Because gas purchase costs for our gas utility operations are passed through to our customers, the change in gas prices did not have a corresponding impact on gross profit. These increases were offset in part by the elimination of sales, cost of sales and gross profit of $114.9 million, $105.6 million and $9.3 million, respectively, from our non-regulated wholesale gas operations that were sold in 2002. Gross profit also increased due to $6.4 million of interim rate increases in Michigan and Iowa. In addition, gross profit from Everest Connections was $3.3 million higher in 2003 due to an increase in customers.

Operating Expense

        Operating expense decreased $24.5 million in 2003 compared to 2002, primarily due to labor, benefit savings and lower administrative expenses resulting from our restructuring in 2002.

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Equity in Earnings of Investments

        Equity in earnings of investments decreased $7.8 million in 2003 compared to 2002. The decrease was primarily due to the sale of our equity interest in Quanta Services during the latter half of 2002 that reduced our ownership to 10.2% at December 31, 2002. Due to our reduced ownership, we could no longer record equity earnings. Our remaining investment was sold during the first quarter of 2003 at an amount that approximated book value.

Regulatory Matters

        The following is a summary of our recent rate case activity:

First Quarter Regulatory Activity

        A settlement has been reached with the intervenors in the Minnesota rate case for $5.7 million. The settlement has been filed with the Commission and a decision is anticipated in June 2003.

        In June 2002, we filed for a $9.3 million general rate increase in Iowa. We received approval to place an interim increase of $5.6 million into effect, subject to refund. In February 2003, a settlement was approved by the Commission for an increase of $4.3 million.

        In August 2002, we filed for a $14.3 million general rate increase in Michigan. We received approval to place an interim increase of $8.2 million into effect as of December 2002. We reached a settlement with the Commission staff and other intervening parties for an increase of $9.1 million. This settlement was approved by the Commission in March 2003 and the new rates have gone into effect. This increase was partially offset by a separate depreciation case whereby our annual rates were reduced by $.7 million. This decrease relates to our depreciation rates, which reduced cash flow but had little impact on earnings.

        In October 2002, we filed for a $23.4 million increase in our Colorado electric rates. In April 2003, we reached a settlement with the Commission staff and other intervening parties for an increase of $16.0 million. A hearing is scheduled to be held in May and new rates are expected to be effective in June 2003.

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INTERNATIONAL NETWORKS

        The table below summarizes the operations of our International Networks for the three months ended March 31, 2003 and 2002.

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

        Sales and gross profit decreased $31.3 million and $32.0 million, respectively, primarily due to the decision by the Alberta Energy and Utility Board (AEUB) to decrease our 2002 and 2003 rates in Alberta as discussed below in Regulatory Matters.

Depreciation and Amortization Expense

        Depreciation and amortization expense decreased $17.0 million in 2003 compared to 2002. This decrease was primarily due to the decision by the AEUB to reduce the depreciation rates (thus extending the depreciable lives) of most of our distribution assets in Alberta from approximately 30 years to 35 years as discussed below in Regulatory Matters.

Equity in Earnings of Investments

        Equity in earnings of investments decreased $7.2 million in 2003 compared to 2002. This decrease was primarily due to the October 2002 sale of our interest in UnitedNetworks Limited in New Zealand, which contributed equity earnings of $8.4 million in the first quarter of 2002.

        Although Midlands Electricity plc (our United Kingdom electric network) had undistributed net earnings in the first quarter of 2003, we did not recognize any equity earnings from this investment. As we stated in our 2002 Annual Report, due to regulatory limitations on cash payments by Midlands to its owners, we intend to record equity earnings and management fees only to the extent of cash received.

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Regulatory Matters

        The following is a summary of our current rate case activity: