AQUILA INC - 10-Q Quarterly Report

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

FORM 10-Q

(Mark One)
ý	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended March 31, 2004
OR
o	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: 1-03562

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

Delaware (State or other jurisdiction of incorporation or organization)	44-0541877 (IRS Employer Identification No.)
20 West Ninth Street, Kansas City, Missouri (Address of principal executive offices)	64105 (Zip Code)

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.

Class		Outstanding at April 30, 2004
Common Stock, $1 par value		195,615,486

Part I—Financial Information

Item 1. Financial Statements

Information regarding the consolidated financial statements is set forth on pages 3 through 15.

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 16 through 31.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are subject to market risk as described on pages 71 through 74 of our 2003 Annual Report on Form 10-K. See discussion on page 31 of this document for changes in market risk since December 31, 2003.

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 Security 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.

Part I. Financial Information
Item 1. Financial Statements

Aquila, Inc.
Consolidated Statements of Income—Unaudited

		Three Months Ended March 31,
In millions, except per share amounts			2004			2003

Sales:
	Electricity—regulated	$	160.0		$	150.5
	Natural gas—regulated		438.5			420.6
	Electricity—non-regulated		(1.8	)		(20.6	)
	Natural gas—non-regulated		(45.3	)		(30.5	)
	Other—non-regulated		1.8			2.8

Total sales			553.2			522.8

Cost of sales:
	Electricity—regulated		81.8			71.7
	Natural gas—regulated		327.5			305.9
	Electricity—non-regulated		16.2			26.0
	Natural gas—non-regulated		—			3.8
	Other—non-regulated		6.4			5.8

Total cost of sales			431.9			413.2

Gross profit			121.3			109.6

Operating expenses:
	Operating expense		117.8			136.3
	Restructuring charges		.3			6.3
	Net loss (gain) on sale of assets		32.1			(2.2	)
	Depreciation and amortization expense		38.4			47.7

Total operating expenses			188.6			188.1

Other income (expense):
	Equity in earnings of investments		2.1			24.5
	Other income		1.5			19.8

Total other income (expense)			3.6			44.3

Interest expense			64.3			60.8

Loss from continuing operations before income taxes			(128.0	)		(95.0	)
Income tax benefit			(43.4	)		(30.6	)

Loss from continuing operations			(84.6	)		(64.4	)
Earnings from discontinued operations, net of tax			32.8			12.5

Net loss		$	(51.8	)	$	(51.9	)

Basic and diluted earnings (loss) per common share:
	Continuing operations	$	(.43	)	$	(.33	)
	Discontinued operations		.17			.06

	Net loss	$	(.26	)	$	(.27	)

Dividends per common share		$	—		$	—

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Balance Sheets

In millions		March 31, 2004		December 31, 2003

		(Unaudited)
Assets
Current assets:
	Cash and cash equivalents	$	728.2	$	601.7
	Restricted cash		242.6		249.2
	Funds on deposit		338.2		382.5
	Accounts receivable, net		449.3		598.4
	Inventories and supplies		80.7		149.4
	Price risk management assets		361.3		311.0
	Prepayments and other		199.7		194.7
	Current assets of discontinued operations		150.4		231.9

Total current assets			2,550.4		2,718.8

	Property, plant and equipment, net		2,749.4		2,752.7
	Investments in unconsolidated subsidiaries		18.6		312.9
	Price risk management assets		545.1		492.6
	Goodwill, net		111.0		111.0
	Deferred charges and other assets		260.6		271.9
	Non-current assets of discontinued operations		1,038.5		1,059.2

Total Assets		$	7,273.6	$	7,719.1

Liabilities and Shareholders' Equity
Current liabilities:
	Current maturities of long-term debt	$	421.8	$	414.8
	Accounts payable		327.6		488.2
	Accrued liabilities		272.9		335.4
	Price risk management liabilities		339.2		290.1
	Current portion of long-term gas contracts		85.4		84.8
	Customer funds on deposit		273.5		279.5
	Current liabilities of discontinued operations		340.0		368.5

Total current liabilities			2,060.4		2,261.3

Long-term liabilities:
	Long-term debt, net		2,207.2		2,291.2
	Deferred income taxes and credits		298.7		376.2
	Price risk management liabilities		465.7		383.5
	Long-term gas contracts, net		560.2		586.3
	Deferred credits		237.3		273.9
	Non-current liabilities of discontinued operations		148.6		187.4

Total long-term liabilities			3,917.7		4,098.5

Common shareholders' equity			1,295.5		1,359.3

Total Liabilities and Shareholders' Equity		$	7,273.6	$	7,719.1

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Statements of Comprehensive Income—Unaudited

			Three Months Ended March 31,
In millions				2004			2003

Net loss			$	(51.8	)	$	(51.9	)
Other comprehensive income (loss), net of related tax:
	Foreign currency adjustments:
		Foreign currency translation adjustments, net of deferred tax benefit of $1.9 million for 2004		(3.2	)		61.0
		Reclassification of foreign currency (gains) losses to income due to sale of businesses, net of deferred tax (expense) benefit of $(11.9) million for 2004		(18.6	)		—

		Total foreign currency adjustments		(21.8	)		61.0

	Cash flow hedges:
		Unrealized gains (losses) on hedging instruments during the period, net of deferred tax expense (benefit) of $(.4) million and $(.3) million for 2004 and 2003, respectively		(.7	)		(.5	)
		Unrealized gains (losses) on hedging instruments of equity method investments, net of deferred tax expense (benefit) of $(.1) million for 2003		—			(2.4	)
		Reclassification of net losses (gains) on hedging instruments to net income, net of deferred tax benefit (expense) of $.3 million and $2.1 million for 2004 and 2003, respectively		.5			3.2
		Reclassification of net (gains) losses to income on cash flow hedges in equity method investments due to sale, net of deferred tax benefit (expense) of $5.5 million for 2004		9.1			—

		Total cash flow hedges		8.9			.3

	Held for sale securities:
		Reclassification of net losses (gains) on sales of securities to income		—			(7.3	)

		Total held for sale securities		—			(7.3	)

	Other comprehensive income (loss)			(12.9	)		54.0

Total Comprehensive Income (Loss)			$	(64.7	)	$	2.1

Aquila, Inc.
Consolidated Statements of Common Shareholders' Equity

In millions	March 31, 2004			December 31, 2003

	(Unaudited)
Common stock: authorized 400 million shares at March 31, 2004 and December 31, 2003, par value $1 per share; 195,531,786 shares issued at March 31, 2004 and 195,252,630 shares issued at December 31, 2003; authorized 20 million shares of Class A common stock, par value $1 per share, none issued	$	195.5		$	195.3
Premium on capital stock		3,162.0			3,161.3
Retained deficit		(2,099.7	)		(2,047.9	)
Accumulated other comprehensive income		37.7			50.6

Total Common Shareholders' Equity	$	1,295.5		$	1,359.3

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Statements of Cash Flows—Unaudited

				Three Months Ended March 31,
In millions					2004			2003

Cash Flows From Operating Activities:
	Net loss			$	(51.8	)	$	(51.9	)
	Adjustments to reconcile net loss to net cash used for operating activities:
		Depreciation and amortization expense			38.4			45.0
		Restructuring charges			.3			6.3
		Cash paid for restructuring and other charges			(7.6	)		(20.0	)
		Net (gain) loss on sale of assets			23.7			(2.2	)
		Net changes in price risk management assets and liabilities			53.6			46.5
		Deferred income taxes and investment tax credits			(68.9	)		2.0
		Equity in earnings of investments			(2.1	)		(24.5	)
		Dividends and fees from investments			1.1			23.2
		Changes in certain assets and liabilities, net of effects of divestitures:
			Restricted cash		13.0			(68.1	)
			Funds on deposit		44.3			(190.3	)
			Accounts receivable/payable, net		(8.6	)		(10.4	)
			Inventories and supplies		64.0			34.2
			Prepayments and other		(15.0	)		148.3
			Deferred charges and other assets		3.0			21.1
			Accrued liabilities		(73.2	)		(31.5	)
			Customer funds on deposit		(6.0	)		90.2
			Deferred credits		(17.8	)		(24.3	)
			Other		3.0			(7.3	)

Cash used for operating activities					(6.6	)		(13.7	)

Cash Flows From Investing Activities:
	Utilities capital expenditures				(53.6	)		(45.8	)
	Merchant capital expenditures				—			(26.2	)
	Cash proceeds received on sale of assets				297.7			307.5
	Other				(3.0	)		(12.5	)

Cash provided from investing activities					241.1			223.0

Cash Flows From Financing Activities:
	Issuance of long-term debt				—			.9
	Retirement of long-term debt				(98.5	)		(146.4	)
	Short-term borrowings (repayments), net				—			6.0
	Cash paid on long-term gas contracts				(25.5	)		(23.1	)
	Other				3.6			1.0

Cash used for financing activities					(120.4	)		(161.6	)

Increase in cash and cash equivalents					114.1			47.7
Cash and cash equivalents at beginning of period (includes $55.8 million and $55.6 million, respectively, of cash included in current assets of discontinued operations)					657.5			441.7

Cash and cash equivalents at end of period (includes $43.4 million and $70.0 million, respectively, of cash included in current assets of discontinued operations)				$	771.6		$	489.4

See accompanying notes to consolidated financial statements.

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 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 10, 2004. You should read our 2003 Form 10-K in conjunction with this report. The accompanying Consolidated Balance Sheets and Consolidated Statements of Common Shareholders' Equity as of December 31, 2003, 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 have been made in preparing the consolidated financial statements 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. 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 2004 presentation. In particular, as discussed in Note 4, the results of operations from certain assets that were sold in 2003 and 2004 and certain assets that are currently held for sale have been reclassified as discontinued operations in the accompanying balance sheets and 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 grant. Therefore we record no compensation expense related to stock options. We historically offered employees a stock purchase plan that enabled them to purchase our common stock at a 15% discount from the market price. This program was suspended in the second quarter of 2003 when all authorized shares in the plan were issued. Shareholder approval is required to authorize additional shares for this program to continue.

Because we account for options and discounts under APB 25, we disclose a pro forma net loss and a basic and diluted loss per share as if we reflected the estimated fair value of options and discounts as compensation expense in accordance with Statement of Financial Accounting

Standards No. 123, "Accounting for Stock-Based Compensation." Our pro forma net loss and basic and diluted loss per share are as follows:

		Three Months Ended March 31,
In millions, except per share amounts			2004			2003

Net loss:
	As reported	$	(51.8	)	$	(51.9	)
	Total stock-based employee compensation expense determined under fair value method, net of related tax		(1.4	)		(1.5	)

	Pro forma net loss	$	(53.2	)	$	(53.4	)

Basic and diluted loss per share:
	As reported	$	(.26	)	$	(.27	)
	Pro forma		(.27	)		(.28	)

In March 2004, the Financial Accounting Standards Board (FASB) issued a proposed standard that would require all companies to expense the value of employee stock options beginning in 2005. We are currently evaluating the impact of this proposed standard.

New Accounting Standards

Variable Interest Entities

In December 2003, the FASB issued a revised Interpretation No. 46, "Consolidation of Variable Interest Entities, an interpretation of ARB No. 51." This interpretation addresses the consolidation by business enterprises of variable interest entities as defined in the interpretation. We are required to apply this interpretation in the first reporting period that ends after March 15, 2004. This interpretation did not have any effect on our financial statements.

2. Restructuring Charges

We recorded the following restructuring charges:

	Three Months Ended March 31,
In millions		2004		2003

Interest rate swap reductions	$	—	$	5.3
Merchant Services severance costs		.2		—
Corporate and Other severance costs		.1		1.0

Total restructuring charges	$	.3	$	6.3

Severance Costs and Retention Payments

For the three months ended March 31, 2004, we incurred severance and other related costs of $.3 million related to the continued exit of our Merchant Services business and the sale of our investment in Midlands Electricity. For the three months ended March 31, 2003, we incurred severance and other related costs of $1.0 million in connection with the restructuring of Everest Connections, our communications business which is included in Corporate and Other. These costs resulted from a reduction of approximately 160 employees.

Interest Rate Swap Reductions

We incurred $5.3 million of restructuring charges for the three months ended March 31, 2003, to exit interest rate swaps related to our Clay County and Piatt County construction financing arrangements. As debt related to these facilities was paid down, the notional amount of our interest rate swaps exceeded the outstanding debt. Thus, we reduced our position and realized the loss associated with the cancelled swaps.

Restructuring Reserve Activity

The following is a summary of the activity for accrued restructuring charges for the three months ended March 31, 2004:

In millions

Severance and Retention Costs:
	Accrued severance costs as of December 31, 2003	$	.9
	Additional expense during the period		.3
	Cash payments during the period		(.4	)

Accrued severance and retention costs as of March 31, 2004		$	.8

Other Restructuring Costs:
	Accrued other restructuring costs as of December 31, 2003	$	16.0
	Additional expense during the period		—
	Cash payments during the period		(2.2	)

Accrued other restructuring costs as of March 31, 2004 (a)		$	13.8

(a): The majority of this liability represents costs accrued for future unused office space with various lease terms through 2010, net of anticipated subleases.

3. Net Loss (Gain) on Sale of Assets

Consistent with our plan to sell non-core assets and return to operating primarily as a domestic utility, we have sold or are in the process of selling the assets listed in the following table. After-tax losses (gains) discussed below are reported after giving consideration to the effect of capital loss carryback and carryforward limitations. As a result, the net tax effect may differ substantially from our expected statutory tax rates. The after-tax losses (gains) discussed below are based on current estimates of the tax treatment of these transactions and may be adjusted

after detailed allocation of the purchase prices for tax purposes and the filing of tax returns including these sales. We recorded the following pretax net loss (gain) on sale of assets:

		Three Months Ended March 31,
In millions			2004			2003

Domestic Utilities:
	Appliance services business	$	—		$	(2.2	)

	Total Domestic Utilities		—			(2.2	)

Merchant Services:
	Aries power project and tolling agreement		47.0			—
	Independent power plants		(6.1	)		—
	Marchwood development project		(5.0	)		—

	Total Merchant Services		35.9			—

Corporate and Other:
	Midlands Electricity		(3.3	)		—
	Other		(.5	)		—

	Total Corporate and Other		(3.8	)		—

Total net loss (gain) on sale of assets		$	32.1		$	(2.2	)

Aries Power Project and Tolling Agreement

In March 2004, we transferred to Calpine Corp., our joint venture partner in the Aries power project, our 50% ownership interest in this project, $5.0 million cash and certain transmission and ancillary contract rights in exchange for the termination of our remaining aggregate undiscounted payment obligation of approximately $397.3 million under our 20-year tolling agreement with the Aries facility. At the same time, Calpine returned approximately $12.5 million of collateral we had posted in support of ongoing energy trading contracts. We recorded a pretax loss of $47.0 million, or $35.6 million after tax, in connection with this transaction.

Independent Power Plants

In November 2003, we agreed to sell our interests in 12 plants to Teton Power Funding LLC. Two of the power plants, Lake Cogen Ltd. (Lake Cogen) and Onondaga Cogen Ltd Partnership (Onondaga), were consolidated on our balance sheet. Therefore, in accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144), we have reported the results of operations and assets of these two plants in discontinued operations. See Note 4 for further explanation.

Our interests in the remaining plants were equity method investments that do not qualify for reporting as discontinued operations under SFAS 144 and are therefore included in continuing operations. In the third quarter of 2003, we evaluated the carrying value of these equity method investments based on the bids received and other internal valuations. The results of this assessment indicated that these investments were impaired. Therefore, we recorded a pretax impairment charge of $87.9 million, or $69.9 million after tax, to reduce the carrying value of our investments to their estimated fair value in the third quarter of 2003. This sale closed in March 2004. We received proceeds of approximately $256.9 million and paid approximately $4.1 million in transaction fees. As the actual proceeds realized were greater than estimated when we recorded the 2003 impairment charge, we recorded a pretax gain of $6.1 million, or $6.3 million after tax in the first quarter of 2004.

Marchwood Development Project

In January 2004, we sold undeveloped land and site licenses for a proposed merchant power plant development project in the United Kingdom for approximately $5.0 million. As a final decision to proceed with construction of this project had not been made, all project development costs had been expensed as incurred. As a result, the pretax gain on the sale was equal to the net proceeds of $5.0 million. The after-tax gain was $3.1 million.

Midlands Electricity

In October 2003, we and FirstEnergy Corp. agreed to sell 100% of the shares of Aquila Sterling Limited (ASL), the owner of Midlands Electricity plc to a subsidiary of Powergen UK plc for approximately £36 million. We completed the sale of ASL in January 2004. We received proceeds of $55.5 million and paid approximately $7.6 million in transaction fees. We recorded a pretax and after-tax gain from this sale of $3.3 million in the first quarter of 2004 due to strengthening in the British pound exchange rate after we recorded a pretax and after-tax impairment charge of approximately $4.0 million in the third quarter of 2003. In 2002, we recorded a pretax and after-tax impairment charge of $247.5 million to record an other-than-temporary decline in this investment.

4. Discontinued Operations

Consistent with our plan to sell non-core assets and return to operating primarily as a domestic utility, we have sold or are in the process of selling our investments in independent power plants and our Canadian utility businesses, which are therefore considered discontinued operations in accordance with SFAS 144. After-tax losses discussed below are reported after giving consideration to the effect of capital loss carryback and carryforward limitations. As a result, the net tax effect may differ substantially from our expected statutory tax rates.

Canada

In September 2003, we agreed to sell our Canadian utility businesses to Fortis Inc. for approximately C$1,360 million (US$1,037 million at the March 31, 2004 exchange rate), including the repayment or assumption of C$174.8 million of debt (US$133.3 million at the March 31, 2004 exchange rate) or US$903.7 million in net proceeds to us before closing adjustments, transaction costs and taxes. In addition, we will be required to repay US$215 million borrowed by our Canadian subsidiaries under a 364-day unsecured loan. We expect to use the remaining net proceeds from the sale to pay related taxes and transaction fees, improve our liquidity, and reduce debt and other obligations. In April 2004, the sale was approved by the Alberta and British Columbia regulatory commissions. The transaction is subject to approval by the Kansas Corporation Commission, as well as other customary closing conditions, and is expected to close in the second quarter of 2004. If the sale does not close by June 30, 2004, the sale agreement will automatically terminate. In March 2004, we entered into a foreign currency forward contract to sell C$800 million on May 28, 2004 at a .7470 exchange rate. At the March 31, 2004 exchange rate of .7626, the settlement of this contract would have reduced the U.S. dollar proceeds from the sale by $12.6 million. Changes in the market value of this forward contract will continue to be recorded in income until the close of the sale or the expiration of the contract.

Independent Power Plants

In November 2003, we agreed to sell our interests in 12 plants to Teton Power Funding LLC. Two of the power plants, Lake Cogen and Onondaga, were consolidated on our balance sheet. We have reported the results of operations and assets of these two plants in discontinued operations.

In the third quarter of 2003, we evaluated the carrying value of these assets based on the bids received and other internal valuations. The results of this assessment indicated these assets were impaired. We recorded a pretax impairment charge of $47.5 million, or $39.8 million after tax, to reduce the carrying value of these assets to their estimated fair value less costs to sell in the third quarter of 2003. We closed this sale in March 2004. Because the actual proceeds realized were greater than estimated when we recorded the 2003 impairment charge, we recorded a pretax gain of $8.4 million, or $16.2 million after tax. The after-tax gain was greater than the pretax gain because an income tax benefit of $11.1 million was recognized for the partial reversal of a valuation allowance provided in 2003. The 2003 valuation allowance was provided as it was expected that a substantial portion of the loss would be treated as a capital loss, the benefit from which more likely than not would not be realized. However, the form of the final sale resulted in a portion of these losses being realized as ordinary losses. The related valuation allowance was therefore reversed in the first quarter of 2004. The remaining valuation allowance for the capital losses on the sale of the independent power plants may be adjusted again after detailed allocation of the purchase price for tax purposes is completed based on an independent appraisal and the final tax returns are filed related to the sale.

We have reported the results of operations from the above assets in discontinued operations in the Consolidated Statements of Income. The related assets and liabilities included in the sale of these businesses, as detailed below, have been reclassified as current and non-current assets and liabilities of discontinued operations on the Consolidated Balance Sheets.

In millions		March 31, 2004		December 31, 2003

Current assets of discontinued operations:
	Cash and cash equivalents	$	43.4	$	55.8
	Funds on deposit		46.4		46.3
	Accounts receivable, net		42.5		58.3
	Price risk management assets		—		34.5
	Other current assets		18.1		37.0

Total current assets of discontinued operations		$	150.4	$	231.9

Non-current assets of discontinued operations:
	Property, plant and equipment, net	$	777.2	$	752.1
	Price risk management assets		—		45.8
	Goodwill, net		226.9		229.5
	Other non-current assets		34.4		31.8

Total non-current assets of discontinued operations		$	1,038.5	$	1,059.2

Current liabilities of discontinued operations:
	Current maturities of long-term debt	$	.9	$	22.8
	Short-term debt		215.0		215.0
	Accounts payable		33.0		39.0
	Other current liabilities		91.1		91.7

Total current liabilities of discontinued operations		$	340.0	$	368.5

Non-current liabilities of discontinued operations:
	Long-term debt, net	$	132.3	$	133.9
	Deferred credits		16.3		53.5

Total non-current liabilities of discontinued operations		$	148.6	$	187.4

Operating results from our discontinued operations are as follows:

		Three Months Ended March 31,
In millions			2004			2003

Sales		$	88.3		$	56.7
Cost of sales			18.9			18.0

Gross profit			69.4			38.7

Operating expenses:
	Operating expense		31.8			31.5
	Gain on sale of assets		(8.4	)		—
	Depreciation and amortization expense		—			(2.8	)

Total operating expenses			23.4			28.7

Other income (expense)			(12.2	)		3.1
Interest expense			9.0			4.3

Earnings before income taxes			24.8			8.8
Income tax benefit			(8.0	)		(3.7	)

Earnings from discontinued operations		$	32.8		$	12.5

5. Earnings (Loss) per Common Share

The table below shows how we calculated basic and diluted earnings (loss) per share. 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 our net loss for the period by our weighted average shares outstanding, without adjusting for dilutive items. Diluted earnings (loss) per share is calculated by dividing our net loss, after assumed conversion of dilutive securities, by our weighted average shares outstanding, adjusted for the effect of dilutive securities. As a result of the net losses in the three months ended March 31, 2004 and 2003, the potential issuances of common stock for dilutive securities were considered anti-dilutive and therefore not included in the calculation of diluted earnings (loss) per share.

		Three Months Ended March 31,
In millions, except per share amounts			2004			2003

Loss from continuing operations		$	(84.6	)	$	(64.4	)
Earnings from discontinued operations			32.8			12.5

Net loss		$	(51.8	)	$	(51.9	)

Basic and diluted earnings (loss) per share:
	Loss from continuing operations	$	(.43	)	$	(.33	)
	Earnings from discontinued operations		.17			.06

	Net loss	$	(.26	)	$	(.27	)

Weighted average number of common shares used in basic and diluted earnings (loss) per share			195.4			194.1

6. Reportable Segment Reconciliation

We have restated our financial reporting segments to reflect the significant changes in our business over the last two years, including the continuing wind-down of our wholesale energy trading operations, the sale of our merchant loan portfolio, our natural gas pipeline, gathering and storage assets, our investments in international utility networks and our investment in Quanta Services, Inc. We now manage our business in two operating segments. Domestic Utilities consists of our regulated electricity and natural gas utility operations in seven states. Merchant Services includes our remaining investments in merchant power plants, our commitments under merchant capacity tolling obligations, our commitments under long-term gas contracts and the remaining contracts from our wholesale energy trading operations. All other operations are included in Corporate and Other, including the costs of the company that are not allocated to our operating businesses, our investment in Everest Connections, and our former investments in Quanta Services, Australia and the United Kingdom. The current and non-current assets of our consolidated independent power plants and our Canadian utility businesses are included in Merchant Services and Corporate and Other, respectively.

Our reportable segment reconciliation is shown below:

		Three Months Ended March 31,
In millions			2004			2003

Sales:
	Domestic Utilities	$	605.9		$	583.0
	Merchant Services		(61.6	)		(67.9	)
	Corporate and Other		8.9			7.7

Total		$	553.2		$	522.8

Earnings (Loss) Before Interest and Taxes (EBIT):
	Domestic Utilities	$	63.4		$	75.0
	Merchant Services		(126.3	)		(107.9	)
	Corporate and Other		(.8	)		(1.3	)

Total EBIT			(63.7	)		(34.2	)
Interest expense			64.3			60.8

Loss from continuing operations before income taxes		$	(128.0	)	$	(95.0	)

In millions		March 31, 2004		December 31, 2003

Assets:*
	Domestic Utilities	$	2,955.4	$	3,060.2
	Merchant Services		2,327.8		2,717.8
	Corporate and Other		1,990.4		1,941.1

Total assets		$	7,273.6	$	7,719.1

* Included in total assets as of March 31, 2004 and December 31, 2003 are total current and non-current assets of discontinued operations as follows: Merchant Services, $10.4 million and $128.5 million, and Corporate and Other, $1,178.5 million and $1,162.6 million, respectively.

7. Financings

Note Payable

In connection with the acquisition of our interest in Midlands Electricity from FirstEnergy Corp., we issued a note payable to the seller, FirstEnergy, for a portion of the purchase price. This note required us to make annual payments of $19.0 million through May 2008. The note obligation was recorded at its net present value at the date of acquisition, discounted at our incremental borrowing rate at that time of 8.15%. In February 2004, we paid $78.6 million to extinguish the entire note payable and accrued interest, resulting in other income related to this transaction of approximately $1.9 million.

Letter of Credit Facility

In April 2004, we extended for one year our 364-day Letter of Credit Agreement with a commercial bank. Under terms of the Agreement, the bank committed to issue letters of credit under the facility subject to a limit of $100.0 million outstanding at any one time. All letters of credit issued are fully secured by cash deposits with the bank. As of March 31, 2004, $70.6 million of letters of credit were outstanding under this facility. Additionally, we have letters of credit outstanding of approximately $14.7 million as of March 31, 2004.

8: Employee Benefits

The following table shows the components of net periodic benefit costs:

	Pension Benefits						Other Post-retirement Benefits

		Three Months Ended March 31,

In millions		2004			2003			2004			2003

Components of Net Periodic Benefit Cost:
Service cost	$	2.0		$	2.0		$	.1		$	.1
Interest cost		4.8			4.8			1.2			1.2
Expected return on plan assets		(6.0	)		(5.8	)		(.3	)		(.3	)
Amortization of transition amount		(.3	)		(.3	)		.2			.4
Amortization of prior service cost		.3			.3			.4			.2
Recognized net actuarial loss		2.0			2.6			.5			.3
Curtailment (gain) loss		—			.1			—			(.1	)
Regulatory adjustment		.1			(.9	)		.2			.1

Net Periodic Benefit Cost	$	2.9		$	2.8		$	2.3		$	1.9

We previously disclosed in our financial statements for the year ended December 31, 2003, that we expected to contribute $.8 million and $6.5 million to our U.S. defined benefit pension plans and other post-retirement benefit plans, respectively, in 2004. We presently do not anticipate contributing amounts significantly different from those previously disclosed.

In our most recent settlement with the Missouri Public Service Commission (the Commission) we agreed to recover our Missouri-related pension funding at an agreed upon annual amount for ratemaking purposes. This settlement determines the annual amount we will recover and recognize as pension expense beginning in the second quarter of 2004. As ordered by the Commission, the difference between the agreed upon expense for ratemaking purposes and the amount determined under Statement of Financial Accounting Standards No. 87, "Employers' Accounting for Pensions," will be recognized as a regulatory asset or liability in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation."

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

See Forward-Looking Information and Risk Factors beginning on page 30.

LIQUIDITY AND CAPITAL RESOURCES

Overall

Because of our non-investment grade credit rating and limitations on our ability to raise incremental capital through the bank and capital markets, for short-term liquidity needs we must rely primarily on our existing cash position and anticipated proceeds from pending asset sales. The following table reflects our anticipated cash sources and key short-term contractual obligations for the next twelve months (including short-term debt reported in discontinued operations):

In millions

Anticipated Cash Sources:
Cash at March 31, 2004		$	728.2
Pending asset sale proceeds:
	Canadian utility operations (a)		903.7
Pending partnership distributions:
	BAF Energy		24.0

Total		$	1,655.9


Anticipated Debt, Toll and Long-term Gas Contract Requirements:
Short-term debt:
	Bank borrowings—Canada	$	215.0
Current maturities of long-term debt:
	Senior notes due on July 15 and October 1, 2004		400.0
	Miscellaneous		22.7
Long-term gas contract commitments			134.0
Elwood tolling agreement			37.3

Total		$	809.0

(a): Gross proceeds net of assumed debt obligations.

We plan to address our cash requirements with cash on hand and the pending asset sale proceeds listed above. If the asset sales do not occur prior to maturity of our senior notes, we will need to address the maturity with existing cash and additional borrowings to bridge the timing of the sale. The remaining cash will be used for future working capital requirements and appropriate liability reductions. Liability reductions would most likely be in the form of a reduction of our debt and contractual liabilities, including tolling contracts and long-term gas contracts.

Pending Asset Sales

exchange rate), or US$903.7 million in net proceeds to us before closing adjustments, transaction costs and taxes. We estimate that closing adjustments will increase the purchase price approximately $75 million and that we will pay approximately US$90 million in cash taxes and transaction costs. In addition, we will be required to repay US$215 million borrowed by our Canadian subsidiaries under a 364-day unsecured loan. In April 2004, the sale was approved by the Alberta and British Columbia regulatory commissions. The transaction is subject to approval of the Kansas Corporation Commission, as well as other customary closing conditions, and is expected to close in the second quarter of 2004. If the sale does not close by June 30, 2004, the sale agreement will automatically terminate. We have a foreign currency forward contract on C$800 million of the anticipated Canadian asset sale proceeds. As of March 31, 2004, the settlement of this forward contract would reduce the above proceeds by US$12.6 million. See discussion of currency rate exposures under Item 3. Quantitative and Qualitative Disclosures About Market Risk on page 31.

Pending Partnership Distributions

We own a 23.11% non-voting limited partnership interest in BAF Energy, a California limited partnership that owns a 120 MW natural gas-fired combined cycle cogeneration facility located in King City, California. On April 14, 2004, Calpine King City Cogen, LLC signed a purchase agreement to buy 100% of the King City cogeneration facility from BAF Energy. Our share of the proceeds, approximately $24 million, is expected to be received as a distribution from the partnership in June 2004.

Working Capital Requirements

Due to our non-investment grade credit rating and lack of lines of credit, we must maintain cash on hand at all times to cover the peak working capital requirements of our business. The most significant activity impacting working capital is the purchase of natural gas for our gas utility customers. We could experience significant working capital requirements during peak winter heating months due to higher natural gas consumption, potential periods of high natural gas prices and the fact that we are currently required to prepay certain of our gas commodity suppliers and pipeline transportation companies. We are currently working to shorten the time lag between our procurement of the commodity and the collection of our revenue. This could be accomplished by establishing an accounts receivable sales program or credit lines with our commodity vendors.

Cash Flows

Cash Flows used for Operating Activities

Our negative first quarter 2004 operating cash flows were driven by the following events and factors:

•: We had a net loss from continuing operations of $128.0 million before income tax benefits.
•: During the first quarter of 2004, we paid a $26.5 million civil penalty settlement to the Commodity Futures Trading Commission related to the reporting of natural gas trading information to publications.
•: Offsetting cash outflows in 2004 were collateral returns resulting from the end of the winter season for our utility business and continued wind-down of our trading positions, use of inventory and other positive working capital in our utility business.

Our negative first quarter 2003 operating cash flows were driven by the following events and factors:

•: We had a net loss from continuing operations of $95.0 million before income tax benefits.
•: We were required to post significant collateral as a result of our credit rating downgrades. These collateral demands were related to trading contracts as well as certain debt and tolling agreements.
•: We made $20.0 million of restructuring payments in 2003 for severance, retention and other related charges primarily due to our exit from the wholesale energy trading business and for the restructuring of our domestic utilities business to more closely align it with its regulatory service areas.
•: Partially offsetting cash outflows were the receipt of approximately $191.1 million of income tax refunds, cash collections related to price risk management assets and inflows due to the liquidation of our wholesale gas storage inventory.

We also have material margin losses related to our long-term gas contracts in our operating cash flows. These margin losses represent the cash payments for gas purchased to settle these contracts on a monthly basis, net of the contract settlement reported in financing activities discussed below. These obligations and our capacity tolling contracts will have a material negative impact on our operating cash flows for the foreseeable future. We are attempting to restructure or terminate these obligations. Any cash payments made to exit these obligations will have a negative impact on operating cash flows in the year the payment is made, but are expected to improve operating cash flows in future periods.

Our significant debt load relative to our overall capitalization and the 14.875% interest rate we pay on $500 million of our long-term bonds has substantially increased our interest costs and will continue to negatively impact our operating cash flows. We expect to reduce our overall interest expense in 2004 by retiring a portion of our debt through the use of proceeds generated from the sale of our Canadian utility businesses and independent power projects. These interest savings will be partially offset, however, by the loss of cash flows from the businesses that are sold.

It is important for us to substantially improve our operating cash flows. We will attempt to do this by improving the efficiency of our remaining businesses, increasing revenues through utility rates, retiring debt and restructuring the obligations discussed above.

Cash Flows provided from Investing Activities

Cash flows provided from investing activities in the first quarter of 2004 and 2003 consist primarily of cash proceeds we received from the sale of our assets offset by cash used by our utilities and merchant businesses for capital expenditures. The $18.1 million increase in 2004 compared to 2003 stemmed from reduced merchant capital expenditures in 2004, as we completed the construction of a merchant plant in June 2003, partially offset by lower cash proceeds received from asset sales and additional utilities capital expenditures.

Cash Flows used for Financing Activities

Cash flows used for financing activities in the first quarter of 2004 and 2003 consist primarily of cash we paid to retire our long-term debt obligations and our payments under our long-term gas contracts. The decrease in cash used for financing activities in 2004 as compared to 2003 stems from the 2004 retirement of debt associated with our acquisition of Midlands

Electricity and our Canadian operations, as compared to the debt we retired in 2003 associated with our investment in Australia and the construction of our merchant power plants.

We also have material cash outflows related to our long-term gas contracts in our financing activities. These cash outflows represent the settlement of our recorded liability based on the units of revenue method of accounting. The combined operating cash outflow and financing cash outflow related to long-term gas contracts represents the total cost to purchase gas to service these contracts. If we do not terminate or restructure these contracts, we will continue to have similar cash outflows related to these contracts in our financing activities in future periods.

Collateral Positions

As of March 31, 2004, we had posted collateral for the following in the form of cash or cash collateralized letters of credit:

In millions

Trading positions	$	193.2
Utility cash collateral requirements		80.0
Tolling agreements		37.7
Insurance and other		27.3

Total Funds on Deposit	$	338.2

Collateral requirements for our remaining trading positions will fluctuate based on movement in commodity prices. This will vary depending on the magnitude of the price movement and the current position of our portfolio. We will receive our posted collateral related to trading positions as we settle our trading positions in the future.

We are required to post collateral to certain of our commodity and pipeline transportation vendors. The amount fluctuates with gas prices and projected volumetric deliveries. The return of this collateral depends on our achieving a stronger credit profile.

We have been required to post collateral related to our Elwood tolling contract until we either successfully restructure the contract or obtain investment-grade ratings from certain major rating agencies. We will not be required to post any additional collateral related to this contract.

On April 8, 2004, Standard & Poor's downgraded our senior unsecured debt rating from B to B-. This action had no impact on our liquidity or collateral position.

FINANCIAL REVIEW

Except where noted, the following discussion refers to the consolidated entity, Aquila, Inc. Our businesses are structured as follows: (a) Domestic Utilities, our electric and gas utilities in seven mid-continent states, and (b) Merchant Services, our power generation operations, our former investments in independent power plants, and the remaining portfolio from our North American and European energy trading businesses. We sold our investments in all but one of our independent power plants in March 2004. Two consolidated plants, Lake Cogen and Onondaga, have been classified in discontinued operations in all periods presented. All other operations are included in Corporate and Other, including: costs that are not allocated to our operating businesses; our investment in Everest Connections; and our former investments in Australia and the United Kingdom. Our Canadian utility businesses that we are in the process of selling are also classified in discontinued operations.

This review of performance is organized by business segment, reflecting the way we manage our business. 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 interest expense 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). In addition, the term may not be comparable to similarly titled measures used by other companies.

		Three Months Ended March 31,
In millions		2004			2003

Earnings (Loss) Before Interest and Taxes:
	Domestic Utilities	$	63.4		$	75.0
	Merchant Services		(126.3	)		(107.9	)
	Corporate and Other		(.8	)		(1.3	)

Total EBIT			(63.7	)		(34.2	)
Interest expense			64.3			60.8
Income tax benefit			(43.4	)		(30.6	)

Loss from continuing operations			(84.6	)		(64.4	)
Earnings from discontinued operations, net of tax			32.8			12.5

Net loss		$	(51.8	)	$	(51.9	)

Key Factors Impacting Continuing Operating Results

Our total loss before interest and taxes increased in 2004 compared to 2003. Key factors affecting 2004 results were as follows:

•: As a result of asset sales, we recorded net losses on sale of assets of $32.1 million in 2004 compared to a gain of $2.2 million in 2003. These losses resulted from our decision to sell non-core and international utility assets in order to return to operating primarily as a domestic electric and gas utility. See Note 3 to Consolidated Financial Statements for further discussion and detail of asset sales.
•: Discounting of our trading portfolio resulted in a non-cash loss of $21.2 million, primarily related to our long-term gas contracts.
•: The loss in the first quarter of 2003 included $25.6 million non-cash loss related to the sale of our capacity under certain long-term gas transportation agreements at substantially less than our future commitments.
•: Equity earnings from our investments in independent power plants and in Australian utility assets decreased by $22.4 million in 2004 compared to 2003 primarily due to the sale of these businesses in March 2004 and May and July 2003, respectively, and mark-to-market earnings recognized at the project level of certain independent power plants in 2003.
•: Domestic Utilities EBIT decreased $11.6 million primarily due to increased fuel and purchased power costs and increased operating costs.

Discontinued Operations

As further discussed in Note 4 to the Consolidated Financial Statements, we have reported the results of operations of our Canadian network businesses that we are in the process of selling and our consolidated independent power plants, Lake Cogen and Onondaga, in discontinued operations in the Consolidated Statements of Income. The unaudited operating results of these operations are as follows:

		Three Months Ended March 31,
In millions		2004			2003

Sales		$	88.3		$	56.7
Cost of sales			18.9			18.0

Gross profit			69.4			38.7

Operating expenses:
	Operating expense		31.8			31.5
	Gain on sale of assets		(8.4	)		—
	Depreciation and amortization expense		—			(2.8	)

Total operating expenses			23.4			28.7

Other income (expense)			(12.2	)		3.1

Earnings before interest and taxes			33.8			13.1
Interest expense			9.0			4.3

Earnings before income taxes			24.8			8.8
Income tax benefit			(8.0	)		(3.7	)

Earnings from discontinued operations		$	32.8		$	12.5

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit increased $31.6 million, $.9 million and $30.7 million, respectively, in 2004 compared to 2003. Sales, cost of sales, and gross profit for our Canadian network business increased $43.3 million, $2.2 million and $41.1 million, respectively, primarily due to the decision in March 2003 by the Alberta Energy Utilities Board (AEUB) to reduce our 2002 and 2003 customer billing rates. The AEUB decision resulted in an adjustment to reduce first quarter 2003 sales and gross profit by approximately $33.7 million. Sales, cost of sales and gross profit for Lake Cogen and Onondaga were lower in 2004 by $11.5 million, $1.3 million and $10.2 million, respectively, due to a price dispute settlement that increased Lake Cogen's 2003 sales by $5.7 million and the sale of these businesses in early March 2004.

Gain on Sale of Assets

Gain on sale of assets consisted of $8.4 million related to the sale of our consolidated independent power plants, Lake Cogen and Onondaga.

Depreciation and Amortization Expense

Depreciation and amortization expense increased $2.8 million in 2004 compared to 2003. The elimination of depreciation from our Canadian utility plant due to its classification as held for sale in accordance with SFAS 144, decreased depreciation expense $12.9 million. SFAS 144 requires that depreciation expense no longer be recorded for those assets classified for accounting

purposes as held for sale. The decrease was offset by the $15.2 million adjustment in the first quarter of 2003 due to the decision by the AEUB to reduce the depreciation rates on most of our distribution assets in Alberta.

Other Income (Expense)

Other income (expense) decreased $15.3 million in 2004 compared to 2003 primarily due to $1.4 million of costs related to a currency put option, $12.6 million due to the unfavorable market value adjustment on a foreign currency forward contract intended to protect us from unfavorable currency movements on the Canada sale proceeds and $.9 million of foreign currency losses related to U.S. dollar denominated debt issued by our Canadian subsidiaries.

Interest Expense

Interest expense increased $4.7 million in 2004 compared to 2003 primarily due to the interest costs on the $215 million 364-day credit facility in Canada.

Income Tax Benefit

The income tax benefit for 2004 increased $4.3 million from 2003. The income tax benefit on pretax income from discontinued operations was primarily the result of the reversal of $11.1 million of valuation allowances provided in the third quarter of 2003. This valuation allowance was required as it was expected that a substantial portion of the losses on the sale of the independent power plants would be treated as a capital loss, the benefit from which more likely than not would not be realized. However, the form of the final sale resulted in a portion of these losses being realized as ordinary losses. The related valuation allowance was therefore reversed in the first quarter of 2004. The remaining valuation allowance for the capital losses on the sale of the independent power plants may be adjusted again after detailed allocation of the purchase price for tax purposes is completed based on an independent appraisal and the final tax returns are filed related to the sale. In addition, our Canadian utility operation in Alberta recognizes income taxes using the flow-through method. As a result, the elimination of depreciation in 2004 and the adjustment of depreciable lives due to the regulatory decision in 2003 increased pretax income but had no impact on income tax expense (benefit).

Current Operating Developments

In September 2003, we agreed to sell our Canadian utility businesses for approximately C$1,360 million (US$1,037 million at the March 31, 2004 exchange rate) before the assumption or repayment of certain debt, closing adjustments, transaction costs and taxes. In April 2004, the sale was approved by the Alberta and British Columbia regulatory commissions. The transaction is subject to approval of the Kansas Corporation Commission, among other regulatory bodies, as well as other customary closing conditions, and is expected to close in the second quarter of 2004. If the sale does not close by June 30, 2004, the sale agreement will automatically terminate. We expect to record a gain on this sale at the date of close.

Domestic Utilities

The table below summarizes the operations of our Domestic Utilities.

		Three Months Ended March 31,
In millions		2004		2003

Sales:
	Electricity—regulated	$	160.0	$	150.5
	Natural gas—regulated		438.5		420.6
	Natural gas—non-regulated		.6		4.7
	Other—non-regulated		6.8		7.2

Total sales			605.9		583.0

Cost of sales:
	Electricity—regulated		81.8		71.7
	Natural gas—regulated		327.5		305.9
	Natural gas—non-regulated		—		3.8
	Other—non-regulated		3.6		3.4

Total cost of sales			412.9		384.8

Gross profit			193.0		198.2

Operating expenses:
	Operating expense		97.5		92.6
	Gain on sale of assets		—		(2.2	)
	Depreciation and amortization expense		32.9		32.3

Total operating expenses			130.4		122.7

Other income (expense)			.8		(.5	)

Earnings before interest and taxes		$	63.4	$	75.0

Electric sales and transportation volumes (GWh)			3,230.5		2,827.5
Gas sales and transportation volumes (Bcf)			82.1		88.4
Electric customers at end of period			448,928		443,133
Gas customers at end of period			905,367		897,281

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for the Domestic Utilities business increased $22.9 million and $28.1 million, respectively, and gross profit decreased $5.2 million in 2004 compared to 2003. These changes were primarily due to the following factors:

•: Regulated electric utility sales and cost of sales increased $9.5 million and $10.1 million, respectively, in 2004 compared to 2003, for a net decrease in gross profit of $.6 million. Sales and gross profit increased by $4.4 million due to a rate increase in Colorado effective in July 2003 and $1.2 million of additional margin from customer growth. These increases were offset by a $5.3 million increase in cost of sales due to the higher cost of fuel and purchased power, net of offsetting derivative hedge positions in 2003. In addition, unfavorable weather and other items decreased gross profit $.9 million.
•: Sales and cost of sales for our regulated gas utilities increased $17.9 million and $21.6 million, respectively, in 2004 compared to 2003, for a net decrease in gross profit of

$3.7 million. Sales and cost of sales increased due to a 16% increase in natural gas prices. However, 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. Regulated gas margins decreased $6.2 million due to unfavorable weather and lower volumes in 2004 compared to 2003. The overall decline in gas margins due to volume and weather was partially offset by $1.5 million in rate increases in Nebraska.

•: Non-regulated gas sales, cost of sales and gross profit decreased $4.1 million, $3.8 million and $.3 million, respectively, in 2004 compared to 2003, primarily as the result of the sale of certain non-regulated gas pipeline and gathering operations in August 2003.

Operating Expense

Operating expenses increased $4.9 million in 2004 compared to 2003 as a result of a number of cost increases, the most significant of which were labor and benefits, insurance and self-insured claims reserves. Employee benefits and insurance costs increased $2.4 million during the first quarter of 2004 compared to 2003, as comparable costs were incurred after the first quarter in 2003. The remaining cost increase was primarily the result of additional staffing to improve customer service.

Regulatory Matters

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

In millions	Type of Service	Date Requested	Date Approved	Amount Requested		Amount Approved

Missouri	Electric	7/2003	4/2004	$	80.9	$	37.5
Missouri	Gas	8/2003	4/2004		6.4		3.4
Colorado	Electric	12/2003	Pending		11.4		Pending

In July 2003, we filed for rate increases totaling $80.9 million for our electric territories in Missouri. These applications were to recover increased costs of natural gas used to fuel our power plants, necessary capital expenditures since our prior rate case, increased pension costs and decreased off-system sales. In March 2004, we reached a settlement with the Missouri Commission staff and intervenors for an increase of $37.5 million. This settlement was approved by the Commission in April 2004. This settlement included a two-year Interim Energy Charge (IEC) that allows the company to recover variable generation and purchased power costs up to a specified amount per mwh specific to each Missouri regulatory jurisdiction. The IEC rate per unit sold is $13.98/mwh and $19.71/mwh for St. Joseph Light & Power and Missouri Public Service, respectively. If the amounts collected under the IEC exceed our average cost incurred for the two-year period, we will refund the excess with interest to the customers. This fuel and purchased power cost recovery mechanism represents $18.5 million of the $37.5 million rate increase. Also, as part of the settlement we agreed not to seek a general increase in our Missouri electric rates that would be effective in less than two years from the current rate increase, unless certain significant events occur that impact our operations.

In August 2003, we filed for a rate increase totaling $6.4 million for our gas territories in Missouri. These increases are needed primarily to recover the cost of system improvements and higher operating costs. In March 2004, we reached a settlement with the Missouri Commission staff and intervenors for an increase of $3.4 million. This settlement was approved by the Commission in April 2004.

In December 2003, we filed a "limited" rate filing in Colorado in order to recover approximately $11.4 million in ongoing costs (e.g., capital improvements) that have occurred in 2003 or will occur in 2004. The Colorado Commission is expected to review this filing and make its decision in the second half of 2004.

Earnings Trend

The recent settlement of our electric and gas rate cases in Missouri is expected to increase annual sales approximately $37.5 million and $3.4 million, respectively. However, we are currently experiencing costs of natural gas used for fuel and purchased power that are in excess of the level of costs recovered under the IEC discussed above. If these costs remain above the IEC base cost for the two-year period, we will not recover the excess. A portion of the rate increase is to cover increased costs in the twelve-month test period, such as additional staffing to improve customer service. To the extent that operating costs increase or decrease subsequent to the test period, the impact of the change will affect our operating results.

Merchant Services

The table below summarizes the operations of our Merchant Services businesses.

		Three Months Ended March 31,
In millions		2004			2003

Sales		$	(61.6	)	$	(67.9	)
Cost of sales			16.3			26.0

Gross loss			(77.9	)		(93.9	)

Operating expenses:
	Operating expense		9.2			14.6
	Restructuring charges		.2			5.3
	Net loss on sale of assets		35.9			—
	Depreciation and amortization expense		4.4			14.6

Total operating expenses			49.7			34.5

Other income (expense):
	Equity in earnings of investments		1.9			19.2
	Other income (expense)		(.6	)		1.3

Loss before interest and taxes		$	(126.3	)	$	(107.9	)

We show our gains and losses from energy trading contracts on a net basis. To the extent losses exceeded gains, sales are shown as a negative number.

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Gross loss for our Merchant Services operations for the three months ended March 31, 2004 was $77.9 million, primarily due to the following factors:

•: Approximately $21.2 million was a non-cash loss related to the discounting of our trading portfolio, primarily driven by our long-term gas contracts. We discount the future cash flows of our price risk management assets based on our counterparties' credit standing, versus our future cash flows of our price risk management liabilities that are discounted based on our current credit standing. The future cash flows of our price risk management assets and liabilities fluctuate primarily based on the forward price of natural gas. During the first quarter of 2004, average gas prices increased over the life of our price risk management assets and liabilities by $.27 MMBtu. After updating the future cash flow stream based on the new forward natural gas prices, we discounted our price risk

management assets and liabilities as described above. In prior periods, primarily in 2002, when our credit standing deteriorated compared to our counterparties' that make up the vast majority of our price risk management assets, we recorded non-cash earnings related to the discounting of our price risk management assets and liabilities. During the first quarter of 2004, the benchmark indexes we use to determine the discount rate appropriate for our credit standing decreased by approximately 300 basis points, resulting in the partial reversal of the previous earnings and asset recorded.

As of March 31, 2004, we have recorded a cumulative $57.7 million of mark-to-market gains related to discounting of our trading portfolio. The vast majority of these gains relate to our long-term gas contracts. These gains will be reversed in later periods as contracts settle, our credit rating improves and/or as gas prices decline.

•: In the first quarter of 2004, we incurred margin losses of $14.1 million resulting from the difference between revenue recognized on our long-term contracts compared to the net cost of gas delivered under these contracts.
•: We make fixed capacity payments evenly throughout the year that entitle us to generate power at merchant power plants owned by others. For the first quarter of 2004, we made net capacity payments of $10.7 million. The cost to purchase natural gas to fuel these power plants generally exceeded the value of the power that could be generated. Accordingly, we did not generate any revenues. Capacity payments were lower in the first quarter of 2004 compared to 2003 because we terminated our Acadia capacity contract in the second quarter of 2003.
•: Included in the $77.9 million loss was approximately $9.9 million of costs to exit natural gas hedge positions related to the Onondaga swap derivative sold in connection with the sale of our independent power plants, cash flow hedge option premium expirations and the exit of other hedges related to previous contracts.
•: Our remaining first quarter gross loss mainly stems from mark-to-market losses and unfavorable settlements of approximately $16.0 million related to a long-term power supply transaction and our remaining stream flow transaction, which expires in 2006. The long-term power supply transaction, which expires in 2009, provides power at predetermined prices and matches the demand requirements of the customer.

Gross loss for our Merchant Services operations for the three months ended March 31, 2003 was $93.9 million, primarily due to the following factors:

•: Approximately $25.6 million was a non-cash loss related to the sale of our capacity under certain long-term gas transportation agreements at substantially less than our future commitments. Although the loss was recognized for accounting purposes, the cash associated with the loss will be paid out over the term of the contracts. In addition, we recorded a $5.9 million loss related to terminating additional trading contracts.
•: In the first quarter of 2003, we incurred margin losses of $12.8 million, resulting from the difference between revenue recognized on our long-term contracts compared to the net cost of gas delivered under these contracts.
•: We make fixed capacity payments evenly throughout the year that entitle us to generate power at merchant power plants owned by others. For the first quarter of 2003, we made net capacity payments of $21.0 million. The cost to purchase natural gas to fuel these power plants generally exceeded the value of the power that could be generated. Accordingly, we did not generate any material revenues.

•: Additionally, in the first quarter of 2003, we incurred approximately $29.6 million of unfavorable settlements of our highly structured stream flow and long-term power supply transactions and our continued wind-down of our European trading operations.

Operating Expense

Operating expense decreased $5.4 million primarily due to reduced staffing needed to manage our remaining trading positions and merchant generating assets.

Net Loss on Sale of Assets

Net loss on sale of assets in 2004 consists of a $47.0 million loss on the transfer of our equity interest in the Aries power project and termination of our tolling obligation, offset by a $6.1 million gain related to the sale of our equity method investments in independent power plants. In the third quarter of 2003, we decided to sell our interest in these plants and therefore wrote our investments down to estimated fair value, which was less than their carrying value. Additionally, in the first quarter of 2004, we recorded a $5.0 million gain on the sale of our Marchwood development project in the United Kingdom.

Depreciation and amortization expense

Depreciation and amortization expense decreased by $10.2 million primarily due to the elimination of the amortization of premiums associated with our equity method investments in independent power plants, resulting from the impairment of our investments in these plants in September 2003.

Equity in Earnings of Investments

Equity in earnings of investments decreased $17.3 million mainly due to our share of mark-to-market earnings recorded at the independent power plant level in the first quarter of 2003.

Earnings Trend and Impact of Changing Business Environment

We began winding down and terminating our trading positions with various counterparties during the third quarter of 2002. However, it will take a number of years to complete the wind-down while we continue to deliver gas under our long-term gas contracts. Because most of our trading positions are hedged, we should experience limited fluctuation in earnings and losses other than the impacts from our credit or counterparty credit, the discounting or accretion of interest, the termination or liquidation of additional trading contracts, or the changes in market valuations and settlements of our highly customized alternative risk products. We have two remaining highly customized actuarial-based contracts in Merchant Services. The long-term supply contract, discussed under "Quarter-to-Quarter—Sales, Cost of Sales and Gross Losses," continues through 2009 and we may continue to experience significant earnings fluctuations related to this contract. Our remaining stream flow contract expires in 2006. There may be earnings volatility associated with this contract due to its highly customized nature and our inability to completely hedge the associated risk. Using a long-term value-at-risk methodology, with a 95% confidence level, we estimate $25.0 million of potential variability related to this contract.

The merchant energy sector has been negatively impacted by new generation capacity that became operational in 2002 and by the continued construction of additional power plants. This increase in supply has placed downward pressure on power prices and subsequently the value of

unsold merchant generation capacity. As a result of the above factors, we expect our Merchant Services unit to generate significant losses for the foreseeable future.

We attempt to optimize and hedge our power plants with forward contracts which qualify as derivative instruments. When we enter into these positions, they are accounted for at fair value under mark-to-market accounting. The hedges are an offset to our power plants, which use accrual accounting. Because different accounting methods are required for each side of the transaction, significant fluctuations in earnings can occur with limited impacts on future cash flow.

Corporate and Other

The table below summarizes the operating results of Corporate and Other:

		Three Months Ended March 31,
In millions		2004			2003

Sales		$	8.9		$	7.7
Cost of sales			2.7			2.4

Gross Profit			6.2			5.3

Operating expenses:
	Operating expense		11.1			29.1
	Restructuring charges		.1			1.0
	Gain on sale of assets		(3.8	)		—
	Depreciation and amortization expense		1.1			.8

Total operating expenses			8.5			30.9

Other income (expense):
	Equity in earnings of investments		.2			5.3
	Other income		1.3			19.0

Loss before interest and taxes		$	(.8	)	$	(1.3	)

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit increased $1.2 million, $.3 million and $.9 million, respectively in 2004 compared to 2003 due to an increase in Everest Connections' customers.

Operating Expense

Operating expense decreased $18.0 million due to a $7.2 million decrease in restructuring consulting fees and insurance and other costs. The first quarter of 2003 also included $6.0 million of provisions for claims and other regulatory reviews that were not required in 2004. In addition, the restructuring of Everest Connections decreased operating expenses $1.9 million and the sale of our international network investments decreased operating expenses $1.9 million.

Restructuring Charges

Restructuring charges decreased $.9 million in the first quarter of 2004 compared to 2003. This was primarily due to $1.0 million of severance and other related costs that were paid in 2003 in connection with the restructuring of Everest Connections.

Gain on Sale of Assets

The gain on sale of assets of $3.8 million was recorded primarily in connection with the sale of our interest in Midlands Electricity in January 2004. This investment was written down to estimated fair value in 2002 and again in September 2003; however, due to strengthening of the British pound exchange rate in the fourth quarter of 2003 and early 2004, we realized a $3.3 million gain on the closing of the sale.

Equity in Earnings of Investments

Equity in earnings decreased $5.1 million in 2004 compared to 2003 due to the sale of our investments in Australia in May and July 2003.

Other Income (Expense)

Other income (expense) decreased $17.7 million mainly due to $14.6 million of foreign currency gains recognized in 2003 resulting from favorable movements in the Australian and New Zealand dollar against the U.S. dollar. In 2004, we realized a $1.9 million gain on the early redemption of the note payable issued in connection with our acquisition of Midlands which was offset in part by $1.8 million in fees paid to lenders in connection with the waiver and amendment of financial covenants under our three-year secured credit facility.

Interest Expense and Income Tax Benefit

The table below summarizes our consolidated interest expense and income tax benefit:

	Three Months Ended March 31,
In millions	2004			2003

Interest expense	$	64.3		$	60.8

Income tax benefit	$	(43.4	)	$	(30.6	)

Quarter-to-Quarter

Interest Expense

Interest expense increased $3.5 million in 2004 compared to 2003. The increase was primarily the result of the borrowing in the 2003 second quarter of $430.0 million under our three-year secured facility, causing $8.6 million of additional interest expense and amortization of debt issue costs of $1.6 million. These increases were partially offset by reductions in interest expense related to the 2003 and first quarter 2004 repayment of debt associated with our investments in Australia, Midlands Electricity, our merchant power plants and our prior revolving credit facility.

Income Tax Benefit

The income tax benefit increased $12.8 million in 2004 compared to 2003, primarily as a result of higher losses before income taxes in 2004 compared to 2003.

As of December 31, 2003, we had approximately $81.4 million of deferred tax benefits for federal and state net operating losses. As a result of additional losses in the first quarter of 2004, these deferred tax benefits increased to approximately $121.5 million. These losses will be available to offset future taxable income for up to 20 years.

Significant Balance Sheet Movements

Total assets decreased by $445.5 million since December 31, 2003. This decrease is primarily due to the following:

•: Cash increased $126.5 million. See our Consolidated Statement of Cash Flows for analysis of this increase.
•: Funds on deposit decreased $44.3 million primarily due to the return of margin deposits paid to counterparties due to the seasonal decrease in gas purchases and the return of $12.5 million of collateral from Calpine in connection with the assignment of our interest in the Aries power project.
•: Accounts receivable, net decreased $149.1 million primarily reflecting lower volumes of electricity delivered due to our exit from wholesale energy trading.
•: Inventories and supplies decreased $68.7 million primarily due to the seasonal withdrawal of natural gas in storage by our Domestic Utilities businesses for deliveries to customers.
•: Price risk management assets increased $102.8 million primarily due to an increase in natural gas prices since December 31, 2003.
•: Investments in unconsolidated subsidiaries decreased by $294.3 million primarily due to the sale of our investments in Midlands Electricity and our independent power plants.
•: Current assets of discontinued operations decreased $81.5 million primarily due to a decrease in the exchange rate on our Canadian utility assets and the sale of our consolidated independent power plants.

Total liabilities decreased by $381.7 million and common shareholders' equity decreased by $63.8 million since December 31, 2003. These changes are primarily attributable to the following:

•: Accounts payable decreased by $160.6 million primarily reflecting lower volumes of electricity delivered due to our exit from wholesale energy trading.
•: Accrued liabilities decreased $62.5 million primarily due to the payment of semi-annual interest on long-term debt and the payment of civil penalties related to the settlement of regulatory investigations.
•: Price risk management liabilities increased $131.3 million primarily due to an increase in natural gas prices since December 31, 2003.
•: Long-term debt, including current maturities of long-term debt, decreased by $77.0 million primarily due to the early retirement of the Midlands acquisition note payable.
•: Deferred income taxes decreased $77.5 million primarily due to deferred tax benefits on 2004 net operating losses and the sale of our investment in Midlands Electricity.
•: Common shareholders' equity decreased $63.8 million primarily as a result of the $51.8 million net loss in the first quarter of 2004 and $12.9 million of comprehensive losses due to lower exchange rates on our foreign investments and the sale of our investment in Midlands Electricity.

Forward-Looking Information and Risk Factors

This report contains forward-looking information, including statements that (i) we expect to complete the sale of our Canadian operations in the second quarter of 2004, (ii) we believe our liquidity will be sufficient in 2004 and (iii) we will attempt to improve operating cash flows by improving our efficiency, increasing utility rates, retiring debt and restructuring our merchant

obligations. 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:

•: Failure to complete the sale of our Canadian operations would have a material adverse impact on our short-term and long-term liquidity.
•: Regulatory commissions may refuse to approve the sale of our Canadian operations, our restructuring activities and some or all of the utility rate increases we have requested or may request.
•: Counterparties may default on their obligations to pay, supply commodities, 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 more difficult for us to obtain additional financing. We must obtain regulatory approvals to use the majority of our remaining unencumbered assets as collateral for additional loans, as well as issue additional debt.
•: Market prices for our long-term debt have increased, which limits our ability to repurchase the debt or obtain significant benefits from its early retirement.
•: 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 settle the contracts.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Certain Trading Activities

We engage in price risk management activities for both trading and non-trading activities. Transactions carried out in connection with trading activities that are derivatives under SFAS 133 are accounted for under the fair value method of accounting. Under SFAS 133, our energy commodity trading contracts, including physical transactions (mainly gas and power) and financial instruments, are recorded at fair value. As part of the valuation of our portfolio, we value the credit risks associated with the financial condition of counterparties and the time value of money. We primarily use quoted market prices from published sources or comparable transactions in liquid markets to value our contracts. If actively quoted market prices are not available, we contact brokers and other external sources or use comparable transactions to obtain current values of our contracts. In addition, the market prices or fair values used in determining the value of the portfolio are our best estimates utilizing information such as historical volatility, time value, counterparty credit and the potential impact on market prices of liquidating our positions in an orderly manner over a reasonable period of time under current market conditions. When market prices are not readily available or determinable, certain contracts are recorded at fair value using an alternative approach such as model pricing.

The changes in fair value of our trading and other contracts for 2004 are summarized below:

In millions

Fair value at December 31, 2003	$	130.0
Change in fair value during the period		(53.5	)
Contracts realized or cash settled		25.0

Fair value at March 31, 2004	$	101.5

The fair value of contracts maturing in the remainder of 2004, each of the next three years and thereafter are shown below:

In millions

2004	$	25.0
2005		(.9	)
2006		19.3
2007		25.2
Thereafter		32.9

Total fair value	$	101.5

In 2003, we agreed to sell our Canadian utility businesses for approximately C$1,360 million (US$1,037 million at the March 31, 2004 exchange rate), including the repayment or assumption of C$174.8 million of debt (US$133.3 million at the March 31, 2004 exchange rate) or net proceeds of approximately US$903.7 million in proceeds to us before closing adjustments, transaction costs and taxes. In addition, we will be required to repay US$215 million borrowed by our Canadian subsidiaries under a 364-day unsecured loan. We expect to close this sale in the second quarter of 2004. In connection with this sale, we entered into a foreign currency put option on C$800 million of the expected cash proceeds from this sale to minimize the effects of declines in the Canadian dollar against the U.S. dollar. This put option created a floor of .73 at which we could exchange C$800 million through March 31, 2004. In March 2004, we terminated this option and entered into a foreign currency forward contract to sell C$800 million on May 28, 2004 at a .7470 exchange rate. At the March 31, 2004 exchange rate of .7626, the settlement of this contract would have reduced the U.S. dollar proceeds from the sale by $12.6 million. As of April 30, 2004, the Canadian dollar exchange rate had fallen to .7288. Approximately C$305 million of the remaining proceeds have also been hedged with a forward contract to lock in the repayment of US$215 million of U.S. dollar denominated debt at our Canadian subsidiaries.

Item 4. Controls and Procedures

Our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) are responsible for establishing and maintaining the company's disclosure controls and procedures. These controls and procedures were designed to ensure that material information relating to the company and its subsidiaries are communicated to the CEO and the CFO. We evaluated these disclosure controls and procedures as of the end of the period covered by this report under the supervision of our CEO and CFO. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic reports filed with the Securities and Exchange Commission. There has been no change in our internal controls over financial reporting during the quarter covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Part II—Other Information

Item 6. Exhibits and Reports on Form 8-K

(a) List of Exhibits

Exhibit No.		Description

* 4.1		Form of Rights Agreement between the company and First Chicago Trust Company of New York, as Rights Agent. (Exhibit 4 to the company's Form 10-Q for the period ended September 30, 1996.)
* 4.2		Amendment to Rights Agreement. (Exhibit 4(d) to the company's Post Effective Amendment No. 1 to Registration Statement on Form S-3 No. 333-29657 filed March 15, 2002.)
31.1		Certification of Chief Executive Officer under Section 302
31.2		Certification of Chief Financial Officer under Section 302
32.1		Certification of Chief Executive Officer under Section 906
32.2		Certification of Chief Financial Officer under Section 906

*: Exhibits marked with an asterisk are incorporated by reference as indicated pursuant to Rule 12(b)-23.

(b) Reports on Form 8-K

We filed or furnished Current Reports on Form 8-K to the Securities and Exchange Commission during the quarter ended March 31, 2004, as follows:

Date Filed		Item No.

March 8, 2004		Item 5—Reported results of internal investigation by the Audit Committee of the Board of Directors of Aquila, Inc. into an anonymous letter dated May 12, 2003 alleging misconduct by certain executives and employees of the company.
		Item 7—Report of Audit Committee of Board of Directors of Aquila, Inc. dated March 1, 2004 regarding the anonymous May 12, 2003 letter.
March 10, 2004		Item 7—Press release dated March 10, 2004.
		Item 12—Announcement of net losses for the fourth quarter and year ended December 31, 2003.

SIGNATURES

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.

Aquila, Inc.
By:		/s/ Rick J. Dobson Rick J. Dobson Senior Vice President and Chief Financial Officer Signing on behalf of the registrant and as principal financial and accounting officer
Date:		May 5, 2004