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, 2005
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 28, 2005
Common Stock, $1 par value		241,851,284

Part I—Financial Information

Item 1. Financial Statements

Information regarding the consolidated financial statements is on pages 3 through 20.

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 is on pages 21 through 37.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are subject to market risk as described on pages 69 through 72 of our 2004 Annual Report on Form 10-K. See discussion on page 37 of this document for changes in market risk since December 31, 2004.

Item 4. Controls and Procedures

Information regarding disclosure controls and procedures is on page 38.

Part II—Other Information

Item 1. Legal Proceedings

Information regarding legal proceedings is on page 39.

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

Exhibits are on page 41.

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			2005			2004

Sales:
	Electricity—regulated	$	174.0		$	160.0
	Natural gas—regulated		476.5			438.5
	Electricity—non-regulated		15.0			(1.7	)
	Natural gas—non-regulated		(21.2	)		(45.1	)
	Other—non-regulated		6.7			1.5

Total sales			651.0			553.2

Cost of sales:
	Electricity—regulated		86.0			81.8
	Natural gas—regulated		367.2			327.5
	Electricity—non-regulated		12.3			16.3
	Natural gas—non-regulated		.1			.2
	Other—non-regulated		6.9			6.1

Total cost of sales			472.5			431.9

Gross profit			178.5			121.3

Operating expenses:
	Operating expense		106.5			117.8
	Restructuring charges		6.6			.3
	Net (gain) loss on sale of assets and other charges		(25.6	)		32.1
	Depreciation and amortization expense		39.0			38.4

Total operating expenses			126.5			188.6

Other income (expense):
	Equity in earnings of investments		—			2.1
	Other income, net		6.8			1.5

Total other income (expense)			6.8			3.6

Interest expense			58.2			64.3

Income (loss) from continuing operations before income taxes			.6			(128.0	)
Income tax benefit			(.1	)		(43.4	)

Income (loss) from continuing operations			.7			(84.6	)
Earnings from discontinued operations, net of tax			—			32.8

Net income (loss)		$	.7		$	(51.8	)

Basic and diluted earnings (loss) per common share:
	Continuing operations	$	.02		$	(.43	)
	Discontinued operations		—			.17

	Net income (loss)	$	.02		$	(.26	)

Dividends per common share		$	—		$	—

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Balance Sheets

In millions			March 31, 2005		December 31, 2004

			(Unaudited)
Assets
Current assets:
	Cash and cash equivalents	$	196.1	$	225.1
	Short-term investments		52.5		—
	Restricted cash		22.9		22.8
	Funds on deposit		283.3		353.1
	Accounts receivable, net		415.8		463.4
	Inventories and supplies		84.3		155.0
	Price risk management assets		177.9		124.9
	Prepaid pension		96.4		98.7
	Other current assets		83.8		105.8

Total current assets			1,413.0		1,548.8

	Property, plant and equipment, net		2,804.5		2,777.4
	Price risk management assets		164.9		136.1
	Goodwill, net		111.3		111.0
	Deferred charges and other assets		193.1		204.0

Total Assets		$	4,686.8	$	4,777.3

Liabilities and Shareholders' Equity
Current liabilities:
	Current maturities of long-term debt	$	21.6	$	42.0
	Accounts payable		243.5		375.6
	Accrued interest		49.7		66.6
	Other accrued liabilities		182.5		193.7
	Price risk management liabilities		177.1		137.3
	Current portion of long-term gas contracts		15.6		15.0
	Customer funds on deposit		47.6		24.2

Total current liabilities			737.6		854.4

Long-term liabilities:
	Long-term debt, net		2,329.0		2,329.9
	Deferred income taxes and credits		147.5		148.0
	Price risk management liabilities		130.3		102.3
	Long-term gas contracts, net		28.7		32.9
	Deferred credits		182.6		179.3

Total long-term liabilities			2,818.1		2,792.4

Common shareholders' equity			1,131.1		1,130.5

Total Liabilities and Shareholders' Equity		$	4,686.8	$	4,777.3

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Statements of Comprehensive Income—Unaudited

			Three Months Ended March 31,
In millions				2005			2004

Net income (loss)			$	..7		$	(51.8	)
Other comprehensive income (loss), net of related tax:
	Foreign currency adjustments:
		Foreign currency translation adjustments, net of deferred tax benefit of $(.3) million and $(1.9) million for the three months ended March 31, 2005 and 2004, respectively		(.5	)		(3.2	)
		Reclassification of foreign currency (gains) losses to income due to sale of businesses and other, net of deferred tax (expense) benefit of $(11.9) million for the three months ended March 31, 2004		—			(18.6	)

		Total foreign currency adjustments		(.5	)		(21.8	)

	Cash flow hedges:
		Unrealized gains (losses) on hedging instruments net of deferred tax expense (benefit) of $(.4) million for the three months ended March 31, 2004		—			(.7	)
		Reclassification of net (gains) losses on hedging instruments to net income, net of deferred tax (expense) benefit of $.3 million for the three months ended March 31, 2004		—			.5
		Reclassification of net (gains) losses to income on cash flow hedges in equity method investments due to sale, net of deferred tax (expense) benefit of $5.5 million for the three months ended March 31, 2004		—			9.1

		Total cash flow hedges		—			8.9

	Other comprehensive loss			(.5	)		(12.9	)

Total Comprehensive Income (Loss)			$	.2		$	(64.7	)

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Statements of Common Shareholders' Equity

In millions		March 31, 2005			December 31, 2004

		(Unaudited)
Common stock: authorized 400 million shares at March 31, 2005 and December 31, 2004, par value $1 per share; 241,840,761 shares issued at March 31, 2005 and 241,739,573 shares issued at December 31, 2004; authorized 20 million shares of Class A common stock, par value $1 per share, none issued	$	241.8		$	241.7
Premium on capital stock		3,228.9			3,228.6
Retained deficit		(2,339.9	)		(2,340.6	)
Accumulated other comprehensive income		.3			.8

Total Common Shareholders' Equity	$	1,131.1		$	1,130.5

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Statements of Cash Flows—Unaudited

				Three Months Ended March 31,
In millions					2005			2004

Cash Flows From Operating Activities:
	Net income (loss)			$	.7		$	(51.8	)
	Adjustments to reconcile net income (loss) to net cash used for operating activities:
		Depreciation and amortization expense			39.0			38.4
		Restructuring charges			6.6			.3
		Cash received (paid) for restructuring and other charges			2.8			(7.6	)
		Net (gain) loss on sale of assets and other charges			(25.6	)		23.7
		Net changes in price risk management assets and liabilities			(14.0	)		53.6
		Deferred income taxes and investment tax credits			(.2	)		(68.9	)
		Equity in earnings of investments			—			(2.1	)
		Dividends and fees from investments			—			1.1
		Changes in certain assets and liabilities, net of effects of divestitures:
			Restricted cash		(.1	)		13.0
			Funds on deposit		69.8			44.3
			Accounts receivable/payable, net		(84.5	)		(8.6	)
			Inventories and supplies		70.7			64.0
			Prepaid pension and other current assets		24.3			(15.0	)
			Deferred charges and other assets		3.0			3.0
			Accrued interest and other accrued liabilities		(21.3	)		(73.2	)
			Customer funds on deposit		23.4			(6.0	)
			Deferred credits		3.3			(17.8	)
			Other		(.9	)		3.0

Cash provided from (used for) operating activities					97.0			(6.6	)

Cash Flows From Investing Activities:
	Utilities capital expenditures				(56.6	)		(53.6	)
	Cash proceeds received on sale of assets				13.8			297.7
	Purchases of short-term investments				(52.5	)		—
	Other				(6.1	)		(3.0	)

Cash provided from (used for) investing activities					(101.4	)		241.1

Cash Flows From Financing Activities:
	Retirement of long-term debt				(21.3	)		(98.5	)
	Cash paid on long-term gas contracts				(3.7	)		(25.5	)
	Other				.4			3.6

Cash used for financing activities					(24.6	)		(120.4	)

Increase (decrease) in cash and cash equivalents					(29.0	)		114.1
Cash and cash equivalents at beginning of period (includes $55.8 million of cash included in current assets of discontinued operations in 2004)					225.1			657.5

Cash and cash equivalents at end of period (includes $43.4 million of cash included in current assets of discontinued operations in 2004)				$	196.1		$	771.6

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 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 14, 2005. You should read our 2004 Form 10-K in conjunction with this report. The accompanying Consolidated Balance Sheets and Consolidated Statements of Common Shareholders' Equity as of December 31, 2004, 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 2005 presentation.

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 on the date of the grant. Therefore we record no compensation expense related to stock options.

Because we account for options under APB 25, we disclose a pro forma net income (loss) and a basic and diluted earnings (loss) per share as if we reflected the estimated fair value of options as compensation expense in accordance with Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation." Our pro forma net income (loss) and basic and diluted earnings (loss) per share are as follows:


		Three Months Ended March 31,

In millions, except per share amounts			2005			2004

Net income (loss):
	As reported	$	.7		$	(51.8	)
	Premium Income Equity Securities adjustment (Note 7)		6.7			—

Earnings (loss) available for common shares			7.4			(51.8	)
	Total stock-based employee compensation expense determined under fair value method, net of related tax benefits		(1.4	)		(1.4	)

	Pro forma earnings (loss) available for common shares	$	6.0		$	(53.2	)

Basic and diluted income (loss) per share:
	As reported	$	.02		$	(.26	)
	Pro forma		.02			(.27	)

The Financial Accounting Standards Board (FASB) issued SFAS No. 123R, "Share-Based Payments," that would require all companies to expense the value of employee stock options in annual periods beginning after June 15, 2005. Based on the small number of options that are expected to be unvested at that date, we do not expect the impact of this standard to have a material effect on our financial statements.

New Accounting Standard

In March 2005, the FASB issued Financial Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" (FIN 47). FIN 47 clarifies the term, conditional asset retirement obligation, as used in SFAS No. 143 "Accounting for Asset Retirement Obligations," which refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. We are evaluating the effect FIN 47 will have on our consolidated financial statements.

2. Restructuring Charges

We recorded the following restructuring charges:


		Three Months Ended March 31,

In millions			2005		2004

Merchant Services:
	Severance and retention costs	$	—	$	.2
	Lease agreements		6.6		—

	Total Merchant Services		6.6		.2
Corporate and Other severance costs			—		.1

Total restructuring charges		$	6.6	$	.3

Lease Agreements

In the first quarter of 2005, we terminated the majority of the remaining leases, with terms through 2010, associated with our former Merchant Services headquarters. In connection with this termination we made a lump-sum payment of $13.0 million which exceeded our restructuring reserve obligation as of the termination date. This resulted in an additional lease restructuring charge of $6.6 million.

Restructuring Reserve Activity

The following table summarizes activity in accrued restructuring charges for the three months ended March 31, 2005:

In millions

Severance and Retention Costs:
	Accrued severance costs as of December 31, 2004	$	.8
	Additional expense during the period		—
	Cash payments during the period		(.2	)

Accrued severance and retention costs as of March 31, 2005		$	.6

Other Restructuring Costs:
	Accrued other restructuring costs as of December 31, 2004	$	7.0
	Additional expense during the period		6.6
	Cash payments during the period		(13.3	)

Accrued other restructuring costs as of March 31, 2005		$	.3

3. Net (Gain) Loss on Sale of Assets and Other Charges

We have sold the assets and terminated the contracts listed in the table below. 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 losses (gains) on sale of assets and other charges:


		Three Months Ended March 31,

In millions			2005			2004

Merchant Services:
	Batesville tolling contract	$	(16.3	)	$	—
	ICE sale		(9.3	)		—
	Aries power project and tolling agreement		—			47.0
	Independent power plants		—			(6.1	)
	Marchwood development project		—			(5.0	)

	Total Merchant Services		(25.6	)		35.9

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

	Total Corporate and Other		—			(3.8	)

Total net (gain) loss on sale of assets and other charges		$	(25.6	)	$	32.1

ICE Sale

In February 2005, we sold our 4.5% interest in IntercontinentalExchange, Inc. (ICE) to other shareholders for approximately $13.8 million. ICE owns a web-based commodity exchange platform. This transaction resulted in a pretax and after-tax gain of approximately $9.3 million.

The gain was realized as a capital gain for income tax purposes resulting in the reversal of previously provided valuation allowances on capital loss carryforwards.

Batesville Tolling Contract

In February 2005, we terminated our power sales contract and assigned our rights and obligations under the tolling contract in exchange for approximately $16.3 million. This transaction resulted in a pretax gain of approximately $16.3 million, or $10.2 million after tax.

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 the project, cash of $5.0 million 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 in the first quarter of 2004.

Independent Power Plants

In November 2003, we agreed to sell our interests in 12 power 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 did 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. The after-tax gain was adjusted further in the fourth quarter of 2004 because an income tax benefit of $16.2 million was recognized for the 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 and detailed allocation of the purchase price for tax purposes based on an independent appraisal resulted in a portion of these losses being realized as ordinary losses. The related valuation allowance was therefore reversed in 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. Upon completion of the sale 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. The gain resulted from 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

We have sold our investments in independent power plants and 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

On May 31, 2004, we completed the sale of our Canadian utility operations in Alberta and British Columbia to two wholly-owned subsidiaries of Fortis Inc., a Canadian energy company, for approximately $1.08 billion (CDN$1.476 billion), including the assumption of debt of $113 million (CDN$155 million) by the purchasers. The closing proceeds included $85 million (CDN$116 million) of preliminary adjustments for working capital and capital expenditures as provided under the sales agreements. These proceeds were subject to final adjustments, which were completed in the third quarter of 2004. We recorded a pretax gain from this sale of $65.6 million, or $9.1 million after tax, in the second quarter of 2004, subject to adjustment for final working capital and capital expenditure adjustments. In September 2004, we agreed with Fortis on a final purchase price adjustment which resulted in a $3.2 million payment to Fortis and decreased our pretax and after-tax gain by $.1 million in the third quarter of 2004.

The effective tax rate on the pretax gain on sale of our Canadian utility businesses is substantially higher than the statutory federal tax rate due to the following factors. The U.S. taxes reflect the partial deduction of Canadian taxes, including withholding taxes, from the U.S. taxable income instead of the full utilization of foreign tax credits. Taxes on the sale also reflect our inability to fully utilize the tax loss on the sale of the Alberta business against the tax gain on the sale of the British Columbia business.

Prior to the closing of the sale, we retired debt related to our Canadian utility operations including $215 million under a 364-day credit facility and $15 million (CDN$20 million) under a revolving bank credit facility. In addition, at the closing of the sale we were released from our guarantor obligations with respect to our former British Columbia utility's debentures and second mortgage loan totaling $113.0 million (CDN$155.0 million).

Independent Power Plants

In November 2003, we agreed to sell our interests in 12 plants to Teton Power Funding LLC. Two of the 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. In the third quarter of 2003 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. 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, in the first quarter of 2004. 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 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. Operating results from our discontinued operations are as follows:


		Three Months Ended March 31,

In millions			2005		2004

Sales		$	—	$	88.3
Cost of sales			—		18.9

Gross profit			—		69.4

Operating expenses:
	Operating expense		—		31.8
	Gain on sale of assets		—		(8.4	)

Total operating expenses			—		23.4

Other income (expense)			—		(12.2	)
Interest expense			—		9.0

Earnings before income taxes			—		24.8
Income tax expense (benefit)			—		(8.0	)

Earnings from discontinued operations		$	—	$	32.8

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 earnings (loss) available for common shares for the period by our weighted average shares outstanding, without adjusting for dilutive items. Weighted average shares used in basic earnings per share includes 110.9 million shares issuable on the conversion of the mandatorily convertible Premium Income Equity Securities (PIES) from August 24, 2004, the date of issuance of the PIES. See Note 7 for further discussion. 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. However, as a result of the net loss in the three months ended

March 31, 2004, the potential issuances of common stock for dilutive securities were considered anti-dilutive in that period and therefore not included in the calculation of diluted earnings (loss) per share.


		Three Months Ended March 31,

In millions, except per share amounts			2005		2004

Income (loss) from continuing operations		$	.7	$	(84.6	)
Earnings from discontinued operations			—		32.8

Net income (loss) as reported			.7		(51.8	)
Interest and debt amortization costs associated with the PIES			6.7		—

Earnings (loss) available for common shares		$	7.4	$	(51.8	)

Basic and diluted earnings (loss) per share:
	Income (loss) from continuing operations	$	.02	$	(.43	)
	Earnings from discontinued operations		—		.17

	Net income (loss)	$	.02	$	(.26	)

Weighted average number of common shares used in basic earnings (loss) per share			352.7		195.4
Effect of dilutive securities:
	Stock options and restricted stock units		.4		—

Weighted average number of common shares used in diluted earnings (loss) per share			353.1		195.4

6. Reportable Segment Reconciliation

We have restated our financial reporting segments to reflect the significant changes in our business over the last three years, including the continuing wind-down of our wholesale energy trading operations and 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 business groups: Utilities and Merchant Services. Utilities consists of our regulated electric utility operations in three states and our natural gas utility operations in seven states. We manage our electric and gas utility divisions by state. However, as each of our electric utility divisions and each of our gas utility divisions have similar economic characteristics, we aggregate our three electric utility divisions into the Electric Utilities reporting segment and our seven gas utility divisions into the Gas Utilities reporting segment. Merchant Services includes our remaining investments in merchant power plants, our commitments under merchant capacity tolling obligations and 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 not allocated to our operating businesses and costs of our investment in Everest Connections and our former investments in Quanta Services, Australia and the United Kingdom.

Our reportable segment reconciliation is shown below:

			Three Months Ended March 31,

In millions				2005			2004

Sales:
	Utilities:
		Electric Utilities	$	174.2		$	160.2
		Gas Utilities		483.2			445.7

	Total Utilities			657.4			605.9

	Merchant Services			(17.3	)		(61.6	)
	Corporate and Other			10.9			8.9

Total			$	651.0		$	553.2

Earnings (Loss) Before Interest and Taxes, Depreciation and Amortization (EBITDA):
	Utilities:
		Electric Utilities	$	36.3		$	26.6
		Gas Utilities		67.4			69.7

	Total Utilities			103.7			96.3

	Merchant Services			(6.6	)		(121.9	)
	Corporate and Other			.7			.3

Total EBITDA				97.8			(25.3	)
Total depreciation and amortization				39.0			38.4
Interest expense				58.2			64.3

Income (loss) from continuing operations before income taxes			$	.6		$	(128.0	)

Depreciation and Amortization:
	Utilities:
		Electric Utilities	$	18.2		$	18.7
		Gas Utilities		14.7			14.2

	Total Utilities			32.9			32.9

	Merchant Services			4.3			4.4
	Corporate and Other			1.8			1.1

Total			$	39.0		$	38.4

In millions				March 31, 2005		December 31, 2004

Assets:
	Utilities:
		Electric Utilities	$	1,893.4	$	1,862.3
		Gas Utilities		1,192.6		1,353.4

	Total Utilities			3,086.0		3,215.7

	Merchant Services			1,086.4		1,080.6
	Corporate and Other			514.4		481.0

Total Assets			$	4,686.8	$	4,777.3

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 8.15%, our incremental borrowing rate at that time. 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 our 364-day Letter of Credit Agreement with a commercial bank for an additional 364 days. Under the 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, 2005, $74.5 million of letters of credit were outstanding under this facility. Additionally, we have other letters of credit outstanding of approximately $6.5 million as of March 31, 2005. This facility expired on April 22, 2005.

Credit Facility

On April 13, 2005, we entered into a five-year credit agreement with a commercial lender. Subject to the satisfaction of certain conditions, the facility provides for up to $180 million of cash advances and letters of credit for working capital purposes. The facility will become available in amounts and at prevailing market rates to be agreed with the lender prior to usage. Cash advances must be repaid within 364 days until we obtain the necessary regulatory approvals to incur long-term indebtedness under the facility. The facility replaces our existing cash-collateralized letter of credit facility, which expired April 22, 2005.

Mandatorily Convertible Senior Notes

In August 2004, we issued 13.8 million PIES at $25 per PIES unit, including an over-allotment of 1.8 million PIES, representing $345.0 million of mandatorily convertible senior notes. These notes are unsecured and bear interest at 6.75% through September 15, 2007. Unless converted earlier by the holder into our common stock, on September 15, 2007, these securities will automatically convert into shares of our common stock at a conversion rate ranging from 8.0386 to 9.8039 shares of common stock per PIES unit, based on the average closing price of our common stock for the 20-day trading period prior to the mandatory conversion date. Our net proceeds on the issuance of the PIES were $334.3 million, after underwriting discounts, commissions and other costs. The proceeds were used to retire long-term debt and other long-term liabilities.

If the mandatory conversion had occurred on March 31, 2005, the average closing price of our common stock for the 20-day trading period would have been $3.95. Using that rate, we would have converted each security into 8.0386 shares of our common stock. The fair value of those shares would have been $424.9 million as of March 31, 2005.

Five-Year Term Loan and Revolving Credit Facility

In September 2004, we completed a $220 million 364-day unsecured term loan and a $110 million 364-day unsecured revolving credit facility. We received extension approval from the

Federal Energy Regulatory Commission (FERC) and various public utility commissions in December 2004, automatically extending to September 2009 both of these facilities (Five-Year Facilities). We borrowed the full amount of the term loan and received $211.3 million of net proceeds after upfront fees and expenses on the two facilities. We had not drawn on the revolving credit facility as of March 31, 2005. The Five-Year Facilities bear interest at the London Inter-Bank Offering Rate (LIBOR) plus 5.75%, subject to reduction if our credit rating improves. Among other restrictions, the Five-Year Facilities contain the following financial covenants with which we were in compliance as of March 31, 2005:

(1): We are required to maintain a ratio of total debt to total capital (expressed as a percentage) of not more than 90% from December 31, 2004 through September 30, 2007; 75% from December 31, 2007 through September 30, 2008; 70% from December 31, 2008 through June 30, 2009; and 65% thereafter.
(2): We must maintain a trailing 12-month ratio of earnings before interest, taxes, depreciation and amortization (EBITDA), as defined in the agreement, to interest expense of no less than 1.0 to 1.0 from December 31, 2004 to September 30, 2005; 1.1 to 1.0 from December 31, 2005 through September 30, 2006; 1.3 to 1.0 from December 31, 2006 through September 30, 2007; 1.4 to 1.0 from December 31, 2007 through September 30, 2008; 1.6 to 1.0 from December 31, 2008 through June 30, 2009; and 1.8 to 1.0 thereafter.
(3): We must maintain a trailing 12-month ratio of debt outstanding to EBITDA of no more than 9.5 to 1.0 from December 31, 2004 to September 30, 2005; 8.5 to 1.0 from December 31, 2005 through September 30, 2006; 7.5 to 1.0 from December 31, 2006 through September 30, 2007; 6.0 to 1.0 from December 31, 2007 through September 30, 2008; 5.5 to 1.0 from December 31, 2008 through June 30, 2009; and 5.0 to 1.0 thereafter.

The Five-Year Facilities also contain covenants that restrict certain activities including, among others, limitations on additional indebtedness, restrictions on acquisitions, sale transactions and investments. 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 facilities.

Secured Revolving Credit Facilities

On October 22, 2004, we completed a $125 million secured revolving credit facility. On December 1, 2004, we amended this facility to increase the maximum borrowing limit to $150 million. The facility was secured by the accounts receivable generated by our regulated utility operations in Colorado, Kansas, Michigan, Missouri and Nebraska. The six-month facility expired April 22, 2005. We did not draw on this facility.

On April 22, 2005, we executed a new four-year, $150 million secured revolving credit facility (the AR Facility). Proceeds from this facility may be used for working capital and other general corporate purposes. Borrowings under this facility are secured by the accounts receivable generated by our regulated utility operations in Colorado, Kansas, Michigan, Missouri and Nebraska. Borrowings under the AR Facility bear interest at LIBOR plus 1.375%, subject to reduction if our credit ratings improve. Borrowings must be repaid within 364 days until we obtain the necessary regulatory approvals to incur long-term indebtedness under the facility. Among other restrictions, we are required under the AR Facility to maintain the same debt-to-total capital and EBITDA-to-interest expense ratios as those contained in the Five-Year Facilities discussed above.

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		2005			2004			2005			2004

Components of Net Periodic Benefit Cost:
Service cost	$	1.9		$	2.0		$	.2		$	.1
Interest cost		5.0			4.8			1.4			1.2
Expected return on plan assets		(6.5	)		(6.0	)		(.3	)		(.3	)
Amortization of transition amount		(.2	)		(.3	)		.4			.2
Amortization of prior service cost		.3			.3			.6			.4
Recognized net actuarial loss		1.4			2.0			.1			.5

Net periodic benefit cost before regulatory expense adjustments		1.9			2.8			2.4			2.1
Regulatory gain/loss adjustment		.9			.1			.3			.2
SFAS 71 regulatory adjustment		1.6			—			—			—

Net periodic benefit cost after regulatory expense adjustments	$	4.4		$	2.9		$	2.7		$	2.3

We previously disclosed in our financial statements for the year ended December 31, 2004, that we expected to contribute $.8 million and $6.1 million to our U.S. defined benefit pension plans and other post-retirement benefit plans, respectively, in 2005. We presently do not anticipate contributing amounts significantly different from those amounts.

9. Legal

AMS Shareholder Lawsuit

A consolidated lawsuit was filed against us in federal court in Missouri in connection with our recombination with our Aquila Merchant subsidiary that occurred pursuant to an exchange offer completed in January 2002. The suit raised allegations concerning the lack of independent members on the board of directors of Aquila Merchant to negotiate the terms of the exchange offer on behalf of the public shareholders of Aquila Merchant. On March 23, 2005, we were granted our motion for summary judgment in this case. The plaintiffs have filed a notice of appeal.

Price Reporting Litigation

On August 18, 2003, Cornerstone Propane Partners filed suit in the Southern District of New York against 35 companies, including Aquila, alleging that the companies manipulated natural gas prices and futures prices on NYMEX through misreporting of natural gas trade data in the physical market. The suit does not specify alleged damages and was filed on behalf of all parties who bought and sold natural gas futures and options on NYMEX from 2000 to 2002. On September 24, 2004, the court denied Aquila's motion to dismiss along with similar motions filed by most of the other defendants. We will defend this case vigorously as we believe we have strong defenses to the plaintiff's claims. We cannot predict with certainty whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

On June 7, 2004, the City of Tacoma, Washington, filed suit against 56 companies, including Aquila, for allegedly conspiring to manipulate the California power market in 2000 and 2001 in violation of the Sherman Act. This case was dismissed in February 2005. The City of Tacoma has appealed to the Ninth Circuit Court of Appeals.

On July 8, 2004, the County of Santa Clara and the City and County of San Francisco each filed suit against seven energy trading companies, including Aquila, in the Superior Court of San Diego alleging manipulation of the California natural gas market in 2000 through 2002. Since that date, 13 other counties, cities and other parties have filed similar complaints making nearly identical allegations. These lawsuits allege violations of the Cartwright Act, the Sherman Act and the California Unfair Competition Law and unjust enrichment. The lawsuits have been designated In re Natural Gas Anti-Trust Cases V and assigned to a Coordination Motion Judge in the Superior Court of San Diego to determine whether they are complex and should be coordinated. Aquila is also a defendant in the Utility Savings & Refund Services, LLP v. Reliant Energy Services, Inc., et al. lawsuit filed November 30, 2004 in the U.S. District Court for the Eastern District of California alleging violations of the Sherman Act, the Cartwright Act, and the California Unfair Competition Law. We believe we have strong defenses and will defend these cases vigorously. We cannot predict with certainty whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with these lawsuits. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

On February 22, 2005, Utility Choice and Cirro Group filed suit against three major Texas utilities and retail electricity providers, including Aquila, for allegedly conspiring to manipulate the Texas power market in 2000 and 2001 in violation of the Sherman Act. We will defend this case vigorously as we believe we have strong defenses to the plaintiff's claims. We cannot predict with certainty whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

Enron Bankruptcy Litigation

On March 7, 2005, we reached an agreement with Enron Corp. and certain of its affiliates (Enron). Under this agreement, we paid $28 million to Enron in April 2005 to settle all outstanding claims between Enron and Aquila associated with the netting of amounts owed to each other under various contracts at the time of Enron's bankruptcy filing in December 2001.

Lender Litigation

On October 5, 2004 and October 15, 2004, lawsuits were filed against us by our lenders alleging that we were obligated to pay a "make whole" amount when we prepaid the $430 million three-year secured term loan in September 2004. We believe that our termination of the term loan required us to pay a prepayment penalty of $8.7 million. The plaintiff lenders have sued us for breach of contract for their proportionate share of the difference between their prepayment calculation and the $8.7 million, which in the aggregate is approximately $20.6 million. We believe we have strong defenses and will defend these cases vigorously. We cannot predict with certainty whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

ERISA Litigation

On September 24, 2004, a lawsuit was filed in the U.S. District Court for the Western District of Missouri against us, certain members of the Board of Directors and certain members of management alleging they violated the Employee Retirement Income Security Act of 1974, as amended (ERISA) and are responsible for losses that participants in the Aquila 401(k) plan experienced as a result of the decline in the value of their Aquila stock held in the Aquila 401(k) plan. A number of similar lawsuits alleging that the defendants breached their fiduciary duties to the plan participants in violation of ERISA by concealing information and/or misleading employees who held Aquila stock through the Aquila 401(k) plan were subsequently filed against us. The suits also seek damages for the plan's losses resulting from the alleged breaches of fiduciary duties. On January 26, 2005 the court ordered that all of these lawsuits be consolidated into a single case captioned In re Aquila ERISA Litigation. The plaintiffs filed an amended consolidated complaint in March 2005, which largely repeats each of the allegations in the first complaint. We believe we have strong defenses and will defend this case vigorously. We cannot predict with certainty whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows. This case has been set for trial in July 2007.

South Harper Peaking Facility

We are constructing a 315 MW natural gas "peaking" power plant and related substation in an unincorporated area of Cass County, Missouri. Cass County and local residents filed suit claiming that county zoning approval is required to construct the project. We believe the County is prohibited by state law from applying its zoning ordinances in this instance to Aquila and utilities generally. On January 11, 2005, a trial court judge granted the County's request for an injunction; however, we are permitted to continue construction while the order is appealed. The matter is now before the Missouri Court of Appeals following our appeal of the trial court decision. We will defend this case vigorously as we believe we have strong defenses to plaintiff's claims. We cannot predict with certainty whether we will be prevented from completing this facility, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit (including costs of replacement power). However, given that the remedy sought is the removal of the nearly completed facility, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

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

See Forward-Looking Information and Risk Factors beginning on page 36.

Strategy

As previously announced, we have retained investment banking advisors to conduct a competitive sale process for certain regulated utility assets. Due to regulatory and price uncertainties associated with the sale of regulated assets, we intend to concurrently conduct a bidding process for utility assets having an aggregated net plant book value of approximately $874 million. The utilities that will be included in this process are our gas operations in Michigan, Minnesota and Missouri and our electric operations in Kansas, Colorado and our St. Joseph, Missouri service territory. At the conclusion of this process, we expect to enter into one or more definitive sale agreements to sell a subset of the offered properties. Additionally, we have outlined the other key elements of our repositioning plan as follows:

•: Maintain synergies of an integrated, multi-state utility.
•: Significantly reduce our debt levels.
•: Continue to improve operational efficiency and lower earnings variability.
•: Gain access to the capital markets on improved terms, allowing the company to more cost effectively fund investments in its rate base to meet customer needs.
•: Actively work with regulators and legislators to address rate and fuel cost issues.
•: Efficiently divest of our interest in our three remaining Merchant peaking facilities and Everest Connections and exit our Elwood tolling obligation.

We are currently soliciting interest in the utility assets and expect to announce more specific transaction details in the third quarter of 2005. Also under consideration are various strategies proposed by financial advisors that could, under the right circumstances, enhance (or potentially accelerate) our repositioning efforts. Alternatives proposed for our consideration include the conversion of up to $345 million of PIES prior to their mandatory conversion date; debt redemption, exchange or tender offers; formation of a holding company; and/or a reverse stock split. Any decision to pursue part or all of the proposed strategies will be subject to review and approval by our board of directors and, if appropriate, our shareholders.

LIQUIDITY AND CAPITAL RESOURCES

Working Capital Requirements

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 months of the winter heating season due to higher natural gas consumption, potential periods of high natural gas prices and our current requirement to prepay certain gas commodity suppliers and pipeline transportation companies. Under a stressed weather and commodity price environment, we believe this working capital peak could be as high as $350 million. We anticipate using the combination of our $110 million five-year unsecured revolving credit facility, $150 million secured accounts receivable facility, up to $180 million unsecured revolving credit and letter of credit facility, and cash on hand to meet our peak winter working capital requirements.

Standard & Poor's (S&P) initiated a new short-term credit rating for its non-investment grade rated companies. S&P expanded the ratings in the "B" category with ratings of "B-1",

"B-2" and "B-3" to allow for greater differentiation. Short-term ratings of "C" and "D" will remain unchanged. We were notified on April 14, 2005 that we would be rated B-3 which indicates a "...weak speculative-grade creditworthiness over the short term (next 12 months)."

Cash Flows

Cash Flows Provided From (Used For) Operating Activities

Our positive three-month 2005 operating cash flows were driven primarily by seasonal declines in working capital requirements for our utility operations. This was the primary cause of the return of $69.8 million of funds on deposit, the $70.7 million utilization of gas inventories in storage and the $24.3 million decrease in prepayments. These decreases in working capital requirements were offset in part by an $84.5 million net increase in cash utilized for accounts receivable and accounts payable.

Our negative three-month 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.
•: 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 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 Elwood tolling contracts will have a material negative impact on our operating cash flows for the foreseeable future. We are attempting to restructure or terminate the Elwood tolling contracts. Any cash payment made to exit this obligation would have a negative impact on operating cash flows in the year the payment is made, but would 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 debt has substantially increased our interest costs and will continue to negatively impact our operating cash flows. It will be important for us to substantially improve our operating cash flows. We are attempting to do this by improving the efficiency of our remaining businesses, increasing sales through utility rates, retiring debt and completing the wind-down of our Merchant Services business.

Cash Flows Provided From (Used For) Investing Activities

The decrease in cash provided from (used for) investing activities was primarily the result of the 2004 receipt of cash proceeds on the sale of former investments in independent power plants and the 2005 purchase of short-term investments with funds in excess of current working capital needs.

Cash Flows Used For Financing Activities

Cash flows used for financing activities in the three months ended March 31, 2005 and 2004 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 2005 was primarily related to the February 2004 early retirement of debt associated with our acquisition of Midlands Electricity and the termination of four long-term gas contracts in late 2004.

Collateral Positions

As of March 31, 2005, we had posted collateral for the following in the form of cash or cash collateralized letters of credit:

In millions

Trading positions	$	109.9
Utility cash collateral requirements		112.9
Elwood tolling contract		37.8
Insurance and other		22.7

Total Funds on Deposit	$	283.3

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 expect to receive our posted collateral related to trading positions as we settle those positions in the future. Additionally, with our new credit facility we will have the ability to post unsecured letters of credit versus cash or cash-collateralized letters of credit. This will accelerate the return of cash related to collateral postings.

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.

FINANCIAL REVIEW

Except where noted, the following discussion refers to the consolidated entity, Aquila, Inc. Our businesses are structured as follows: (a) Electric Utilities, our electric utilities in three mid-continent states, (b) Gas Utilities, our gas utilities in seven mid-continent states, and (c) Merchant Services, our non-regulated 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 or received distributions from our investments in our independent power plants in March and June 2004. Two consolidated plants, Lake Cogen and Onondaga, have been classified in discontinued operations in 2004. 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 former Canadian utility businesses are classified in discontinued operations in 2004.

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 EBITDA and for depreciation and amortization. We use EBITDA 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 EBITDA, while interest expense and income taxes are separately discussed at the corporate level.

The use of EBITDA 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				2005			2004

Earnings (Loss) Before Interest and Taxes, Depreciation and Amortization:
	Utilities:
		Electric Utilities	$	36.3		$	26.6
		Gas Utilities		67.4			69.7

	Total Utilities			103.7			96.3

	Merchant Services			(6.6	)		(121.9	)
	Corporate and Other			.7			.3

Total EBITDA				97.8			(25.3	)
Depreciation and amortization				39.0			38.4
Interest expense				58.2			64.3
Income tax benefit				(.1	)		(43.4	)

Income (loss) from continuing operations				.7			(84.6	)
Earnings from discontinued operations, net of tax				—			32.8

Net Income (Loss)			$	.7		$	(51.8	)

Key Factors Impacting Results of Continuing Operations

For the three months ended March 31, 2005, our total EBITDA increased compared to 2004. Key factors affecting 2005 results were as follows:

•: Total Utilities EBITDA increased $7.4 million primarily due to mark-to-market income related to our NYMEX natural gas contracts for gas-fired generation, favorable settlement of property tax disputes and rate increases in Missouri and Colorado, offset in part by unfavorable weather for our electric and gas utilities, increased labor and compensation costs and higher costs for natural gas used for fuel.
•: The continued wind-down of our energy trading businesses, including $25.6 million of gains on the sale of our investment in ICE and termination of our Batesville tolling agreement and associated forward sale contract, resulted in a $115.3 million decrease in losses before interest and taxes, depreciation and amortization from Merchant Services.

Discontinued Operations

As further discussed in Note 4 to the Consolidated Financial Statements, we have reported the results of operations of our Canadian utility businesses and our consolidated independent power plants, Lake Cogen and Onondaga, in discontinued operations in the Consolidated Statements of Income for the first quarter of 2004. The unaudited operating results of these operations are summarized in the table below. These businesses were sold in May 2004 and March 2004 respectively, therefore no earnings from discontinued operations were reported in 2005.

		Three Months Ended March 31,
In millions			2005		2004

Sales		$	—	$	88.3
Cost of sales			—		18.9

Gross profit			—		69.4

Operating expenses:
	Operating expense		—		31.8
	Gain on sale of assets		—		(8.4	)

Total operating expenses			—		23.4

Other income (expense)			—		(12.2	)

EBITDA			—		33.8
Interest expense			—		9.0

Earnings before income taxes			—		24.8
Income tax benefit			—		(8.0	)

Earnings from discontinued operations		$	—	$	32.8

Electric Utilities

The table below summarizes the operations of our Electric Utilities:

		Three Months Ended March 31,
Dollars in millions		2005	2004

Sales:
	Electricity—regulated	$174.0	$160.0
	Electric—non-regulated	.1	.1
	Other—non-regulated	.1	.1

Total sales		174.2	160.2

Cost of sales:
	Electricity—regulated	86.0	81.8
	Other—non-regulated	.1	.2

Total cost of sales		86.1	82.0

Gross profit		88.1	78.2

Operating expense		54.7	51.8
Other income		2.9	.2

EBITDA		$ 36.3	$ 26.6

Depreciation and amortization expense		$ 18.2	$ 18.7

Electric sales and transportation volumes (GWh)		3,119.1	2,989.2
Electric customers at end of period		457,051	448,928

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit for the Electric Utilities business increased $14.0 million, $4.1 million, and $9.9 million, respectively, in 2005 compared to 2004. These changes were primarily due to the following factors:

•: Sales and gross profit increased by $10.3 million due to rate increases in Colorado effective in September 2004 and in Missouri effective in April 2004, plus $.9 million of additional margin from an increase in customers.
•: In the first quarter of 2005, we recognized $6.8 million of mark-to-market income on certain NYMEX natural gas contracts as a result of increases in forward gas prices. These contracts, primarily for the summer season, were purchased to offset the risk of increased gas costs in our Missouri electric operations.
•: Higher costs of fuel, purchased power and transmission, net of offsetting derivative positions, reduced margins by approximately $6.5 million.
•: The increases above were offset in part by $1.5 million of unfavorable weather-related volume and other variances.

Operating Expense

Operating expense increased $2.9 million primarily due to higher labor and benefit costs.

Other Income

Other income increased $2.7 million primarily due to increased Allowances for Funds Used During Construction (AFUDC) associated with the construction of our South Harper Peaking Facility. AFUDC represents the cost of both debt and equity funds used to finance utility plant additions during the construction period. AFUDC is capitalized as a part of the cost of utility plant and is credited to other income currently.

Current Developments

Iatan 2

Our 2005 power supply plan indicates the need for additional base-load capacity in Missouri after 2009. There is generally a five- to seven-year lead time required between the decision to proceed with a coal-fired generating project and the completion of development, permitting, construction and performance testing of such a project. Kansas City Power & Light Company has filed a long-term energy plan with the Missouri Public Service Commission (MPSC) including the construction of up to 800 MW of coal-fired generating capacity at the existing Iatan site in Weston, Missouri. The additional 800 MW generating capacity is planned for commercial operation in 2010 or 2011. Aquila and Empire District Electric Company are considered "preferred potential partners" in at least 30% of the proposed plant. In March 2005, we filed a regulatory plan with the MPSC indicating our desire to participate in the project. Our filing also requested that specific regulatory principles be applied to the recovery of the investment to facilitate financing our participation while maintaining appropriate cash flow metrics at the Missouri utility.

Clean Air Rules

In March 2005, the Environmental Protection Agency finalized the Clean Air Interstate Rule and the Clean Air Mercury Rule. These rules establish a stringent cap and trade program for sulfur dioxide, nitrogen oxides and mercury emissions beginning in 2009. These rules will impact our generation fleet, including facilities that we own in part but do not operate. Our initial cost estimate to comply with the draft rules ranged between $100 million to $400 million. Although we do not believe the final versions of these rules will result in a material change in our original estimates, we are performing a more detailed engineering study to narrow the range of our estimated compliance costs. It is likely that these rules will undergo a legal challenge to make them more stringent. A successful legal challenge could materially increase our cost estimates. We anticipate that any costs incurred to comply with the final rules will be recoverable in future rate cases.

Earnings Trend

The recent settlement of our electric rate case in Missouri is expected to increase annual sales approximately $37.5 million. However, our costs of natural gas used for fuel and purchased power have exceeded the level of costs recovered under the Interim Energy Charge (IEC) discussed under Regulatory Matters below. 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 12-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.

Our power supply agreement with Aries, which provides up to 500 MW of power, expires in June 2005. We plan to replace this power with the construction of the South Harper Peaking Facility, a 315-megawatt combustion turbine generation plant being constructed near Peculiar,

Missouri, and by entering into power purchase agreements. To the extent the cost of this replacement power exceeds the cost of power recovered in rates under the Aries agreement, and until such cost is recovered in a subsequent rate case, our earnings could be adversely affected.

In April 2005, one of our coal suppliers notified us that it was terminating our coal supply contract because of labor problems at the mine. We have notified the supplier that we do not believe the termination was valid, and we expect to pursue our rights and remedies under the contract. This contract provided for the delivery of 450,000 tons in 2004 and 550,000 tons of coal annually to our Missouri electric utilities in 2005 through 2008, with extension options, at an average cost of $20 per ton. The supplier curtailed production beginning in January 2004 which resulted in the delivery of approximately 30% of the contracted volumes of low-sulfur, high-Btu coal. In response, we have secured substantial quantities of alternate supply through spot purchases, despite a general decrease in availability of comparable coal on the spot market. Some of the available substitute supplies of coal are of higher sulfur content and therefore require the purchase of additional SO₂ emission allowances at a time when the cost of such allowances is substantially higher than historical levels. As we continue to replace our original contracted coal supply with the substitute coal supply during 2005, our operating results will be adversely affected.

Gas Utilities

The table below summarizes the operations of our Gas Utilities:

		Three Months Ended March 31,
Dollars in millions		2005	2004

Sales:
	Natural gas—regulated	$476.5	$438.5
	Natural gas—non-regulated	.2	.8
	Other—non-regulated	6.5	6.4

Total sales		483.2	445.7

Cost of sales:
	Natural gas—regulated	367.2	327.5
	Natural gas—non-regulated	.1	.1
	Other—non-regulated	3.2	3.3

Total cost of sales		370.5	330.9

Gross profit		112.7	114.8

Operating expense		45.6	45.7
Other income		.3	.6

EBITDA		$ 67.4	$ 69.7

Depreciation and amortization expense		$ 14.7	$ 14.2

Gas sales and transportation volumes (Bcf)		81.1	82.1
Gas customers at end of period		917,612	905,367

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for the Gas Utilities business increased $37.5 million and $39.6 million, respectively, in 2005 compared to 2004, for a gross profit decrease of $2.1 million. These changes were primarily due to the following factors:

•: Sales and cost of sales increased approximately $44.3 million due to a 13% 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.
•: Gross profit was adversely impacted by approximately $2.2 million due to unseasonably mild winter weather in 2005 compared to 2004.
•: Gross profit also declined approximately $.5 million due to the sale of a gas operation in the eastern portion of our Missouri territory in May 2004 and $1.3 million due to decreased gas transmission sales.
•: The decreases in gross profit discussed above were offset in part by approximately $1.0 million due to rate increases in Missouri effective in May and July 2004 and $1.2 million of additional margins from customer growth.

Operating Expense

Total operating expense was the same in 2005 and 2004 but was the net result of increased labor and benefit costs, offset by the expected favorable settlement of our lawsuit challenging the valuation of our Minnesota gas utility assets for property tax purposes.

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	8/2004		11.4	8.2
Kansas	Electric	6/2004	3/2005		16.4	8.0
Kansas	Gas	11/2004	5/2005		6.2	2.7
Iowa	Gas	5/2005	Pending		4.1	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 MPSC 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 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 for St. Joseph Light & Power and $19.71/Mwh for Missouri Public Service. If the amounts collected under the IEC exceed our average cost incurred for the two-year period, we will refund the excess to the customers, with interest. 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 MPSC staff and intervenors for an increase of $3.4 million. This settlement was approved by the Missouri 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 occurred in 2003 or were to occur in 2004. In July 2004, we reached a settlement with the Colorado Commission staff and intervenors for an increase of $8.2 million. In addition, our Incentive Clause Adjustment was modified to provide for the recovery from customers of 100% of the variability of energy costs, an increase from 75%. The settlement was approved by the Colorado Commission in August 2004.

In June 2004, we filed for a rate increase totaling $19.2 million, later revised to $16.4 million, for our electric territories in Kansas. This application was primarily to recover infrastructure improvements and increased maintenance and operating costs. In January 2005, the Kansas Commission issued an order approving a rate increase of $7.4 million. On reconsideration, the formal order was issued in March 2005 adjusting the approved rate increase to $8.0 million. We have appealed to the Circuit Court of the State of Kansas on a number of issues included in the final rate order.

In November 2004, we filed for a rate increase totaling $6.2 million for our gas territories in Kansas. This application is primarily to recover infrastructure improvements and increased operating and maintenance costs. On May 2, 2005, the Kansas Commission approved a settlement reached among the Company, the Staff at the Kansas Commission and other intervening parties for an increase in rates of $2.7 million. This rate increase is expected to be effective in June 2005.

In May 2005, we filed for a rate increase totaling $4.1 million for our gas territories in Iowa. This application is primarily to recover system improvement costs we have incurred. Under Iowa regulations, Aquila will institute interim rates, subject to refund, totaling approximately $1.7 million in May 2005. We expect hearings to be held near the end of 2005, with final rates effective in April 2006.

Merchant Services

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

		Three Months Ended March 31,
In millions			2005			2004

Sales		$	(17.3	)	$	(61.6	)
Cost of sales			12.4			16.3

Gross loss			(29.7	)		(77.9	)

Operating expenses:
	Operating expense (income), net		(2.2	)		9.2
	Restructuring charges		6.6			.2
	Net (gain) loss on sale of assets and other charges		(25.6	)		35.9

Total operating expenses (income), net			(21.2	)		45.3

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

Loss before interest and taxes, depreciation and amortization		$	(6.6	)	$	(121.9	)

Depreciation and amortization expense		$	4.3		$	4.4

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 Loss

Gross loss for our Merchant Services operations for the three months ended March 31, 2005 was $29.7 million, primarily due to the following factors:

•: We make fixed capacity payments evenly throughout the year that entitle us to generate power at merchant power plants owned by others. In the first quarter of 2005, we recorded net margin loss associated with these agreements of $7.9 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 material revenues other than through certain capacity sales contracts.
•: Included in our gross loss for the first quarter of 2005 were mark-to-market losses of approximately $11.2 million, related to our remaining stream flow transaction which expires in 2006.
•: In the first quarter of 2005, we recorded a margin loss of $4.5 million on the write-off of certain balances retained in our previous sale of gas pipeline investments.
•: We also incurred margin losses of $1.7 million resulting from the difference between revenue recognized on our two remaining long-term gas contracts compared to the net cost of gas delivered under these contracts.
•: The remaining $4.4 million of gross loss primarily relates to merchant peaking plant capacity sales offset by losses on various open positions during 2005.

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.
•: 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 $10.8 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.
•: 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 first quarter gross loss also includes 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 provided power at predetermined prices and matched the demand requirements of the customer was terminated in May 2004.
•: The remaining $5.9 million of gross loss primarily relates to merchant peaking plant capacity sales offset by losses on various open positions during 2004.

Operating Expense

Operating expense decreased $11.4 million primarily due to the refund of value-added taxes previously paid and expensed by our European merchant trading business, reduced surety payments due to the settlement of four long-term gas contracts, and reduced staffing needed to manage our remaining trading positions and non-regulated power generation assets.

Restructuring Charges

Restructuring charges increased $6.4 million in the first quarter of 2005, primarily due to the termination of the majority of the remaining leases associated with our former Merchant Services

headquarters. In connection with this termination we made a lump-sum payment of $13.0 million which exceeded our restructuring reserve obligation as of the termination date, resulting in an additional lease restructuring charge of $6.6 million.

Net (Gain) Loss on Sale of Assets and Other Charges

In the first quarter of 2005, we recorded pretax gains of $16.3 million on the termination of the Batesville tolling agreement and related forward sale contract and $9.3 million on the sale of our stock investment in ICE. See Note 3 to the Consolidated Financial Statements for further discussion.

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.

Earnings Trend and Impact of Changing Business Environment

The merchant energy sector has been negatively impacted by the increase in generation capacity that became operational in 2002 and 2003. This increase in supply has placed downward pressure on power prices and subsequently the value of unsold merchant generation capacity. Because it is generally expected that the fuel and start-up costs of operating our merchant power plants will exceed the revenues that would be generated from the power sold, we believe that during the foreseeable future we will have limited ability to generate power at a gross profit. We will continue to have operating and maintenance cost associated with our owned merchant generation plants, whether the facilities are being utilized to generate power or are idle. Additionally, we will be required to make capacity payments related to our tolling agreements with Elwood and expect to incur pretax losses and negative operating cash flows of approximately $37.3 million in 2005 related to this arrangement. We are attempting to terminate or restructure this obligation. We have sold capacity in three of these plants which will partially offset these costs in 2005 and 2006. As a result of the above factors and our change in strategy, we do not expect Merchant Services to be profitable in the next two to three years.

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

We began winding down and terminating our trading positions with our various counterparties during the third quarter of 2002. However, it will take a number of years to complete the wind-down. Because most of our trading positions are offsetting, we should experience limited fluctuation in earnings or losses other than the impacts from counterparty credit, the discounting or accretion of interest, or the termination or liquidation of additional trading contracts. We have one remaining highly customized actuarial-based contract in Merchant Services which 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 $24.0 million of total volatility (potential earnings or losses) related to this contract.

Corporate and Other

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

		Three Months Ended March 31,
In millions			2005		2004

Sales		$	10.9	$	8.9
Cost of sales			3.5		2.7

Gross profit			7.4		6.2

Operating expenses:
	Operating expense		8.4		11.1
	Restructuring charges		—		.1
	Net gain on sale of assets and other charges		—		(3.8	)

Total operating expenses			8.4		7.4

Other income (expense):
	Equity in earnings of investments		—		.2
	Other income		1.7		1.3

EBITDA		$	.7	$	.3

Depreciation and amortization expense		$	1.8	$	1.1

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit increased $2.0 million, $.8 million and $1.2 million, respectively, in 2005 compared to 2004, primarily due to an increase in customers at Everest Connections.

Operating Expense

Operating expense decreased $2.7 million in 2005 compared to 2004, primarily due to decreases in insurance and other costs and the payment of amendment fees in the first quarter of 2004 on our former secured term loan.

Net Gain on Sale of Assets and Other Charges

The gain on sale of assets of $3.8 million was recorded primarily in connection with the $3.3 million gain realized on the closing of the sale of our interest in Midlands Electricity in January 2004.

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		2005			2004

Interest expense	$	58.2		$	64.3

Income tax benefit	$	(.1	)	$	(43.4	)

Quarter-to-Quarter

Interest Expense

Interest expense decreased $6.1 million in 2005 compared to 2004, due to debt retirements in 2004.

Income Tax Benefit

The income tax benefit decreased $43.3 million in 2005 compared to 2004, primarily as a result of higher pretax income in 2005. Included in the income tax benefit for the first quarter of 2005 was the reversal of $3.7 million of income tax valuation allowances previously provided on capital losses due to the recognition of a capital gain on the sale of our ICE shares.

Significant Balance Sheet Movements

Total assets decreased by $90.5 million since December 31, 2004. This decrease is primarily due to the following:

•: Cash decreased $29.0 million. See our Consolidated Statement of Cash Flows for analysis of this decrease.
•: Short-term investments increased $52.5 million as we moved funds in excess of immediate liquidity needs into investments with terms longer than three months.
•: Funds on deposit decreased $69.8 million, primarily due to the seasonal decrease in gas purchases by our regulated utilities.
•: Accounts receivable decreased $47.6 million, primarily reflecting lower volumes of gas and electricity delivered due to our exit from wholesale energy trading, and seasonal declines in regulated gas customer deliveries, offset in part by the effects of higher natural gas prices.
•: Inventories and supplies decreased $70.7 million, primarily due to the seasonal withdrawal of natural gas from underground storage by our Gas Utilities businesses for winter deliveries to customers.
•: Price risk management assets increased $81.8 million, primarily due to an increase in natural gas prices since December 31, 2004.
•: Other current assets decreased $22.0 million, primarily due to lower prepaid natural gas purchases for our gas utilities due to the seasonal decrease in gas purchases.
•: Property, plant and equipment increased $27.1 million, primarily due to capital expenditures on our South Harper Peaking Facility.

Total liabilities decreased by $91.1 million and common shareholders' equity increased by $.6 million since December 31, 2004. These changes are primarily attributable to the following:

•: Accounts payable decreased by $132.1 million, primarily reflecting lower volumes of gas and electricity delivered due to our exit from wholesale energy trading and the seasonal decrease in gas purchases by our regulated utilities.
•: Accrued interest and other accrued liabilities decreased $28.1 million, primarily due to periodic interest payments and the termination of the remaining merchant lease obligations.
•: Price risk management liabilities increased $67.8 million, primarily due to an increase in natural gas prices since December 31, 2004.
•: Customer funds on deposit increased $23.4 million, primarily due to additional postings required from our merchant counterparties.
•: Long-term debt, including current maturities of long-term debt, decreased by $21.3 million primarily due to the scheduled retirement of senior notes.

Forward-Looking Information and Risk Factors

This report contains forward-looking information. Forward-looking information involves risk and uncertainties, and certain important factors can cause actual results to differ materially from those anticipated. The forward-looking statements in this report include:

•: We intend to conduct a competitive sale process for six utility properties having an aggregate book value of approximately $874 million and, at the conclusion of the bidding process, we expect to enter into one or more definitive sale agreements to sell a subset of those properties. Some important factors that could cause actual results to differ materially from those anticipated include:
•: We may receive bids for assets at prices that are inadequate or insufficient for accomplishing our targeted goals.
•: The sale of other utility properties in the market may affect the timing of our sale process.
•: Regulatory commissions may not approve some or all of the contemplated divestitures.
•: We plan to replace the power supplied to our Missouri Public Service operations under the Aries power supply agreement with power supplied by our 315 MW South Harper Peaking Facility being constructed near Peculiar, Missouri and power purchased under additional power supply agreements. Some important factors that could cause actual results to differ materially from those anticipated include:
•: The construction of our South Harper Peaking Facility could be delayed by weather.
•: The construction of our South Harper Peaking Facility could be delayed or barred by an adverse outcome of litigation pending against us.
•: Regulatory commissions may refuse to allow us to recover in rates part or all of the costs related to the construction of our South Harper Peaking Facility or the additional power purchases.
•: We believe we have strong defenses to litigation pending against us. Some important factors that could cause actual results to differ materially from those anticipated include:
•: Judges and juries can be difficult to predict and may, in fact, rule against us.

•: Our positions may be weakened by adverse developments in the law or the discovery of facts that hurt our cases.
•: We anticipate that the costs of compliance with the Clean Air Interstate Rule and the Clean Air Mercury Rule will be allowed for recovery in future rate cases. Some important factors that could cause actual results to differ materially from those anticipated include:
•: Regulatory commissions may refuse to allow us to recover in rates part or all of the costs related to compliance with these rules.
•: Changes in applicable law or regulation may prohibit us from recovering in rates part of all of the costs related to compliance with these rules.
•: We anticipate that our current revolving credit capacity and available cash will be sufficient to fund our winter needs and working capital requirements. Some important factors that could cause actual results to differ materially from those anticipated include:
•: Our access to credit capacity depends on maintaining compliance with loan covenants. If we violate these covenants, we may lose revolving credit capacity and not have sufficient cash available for our winter needs.
•: Unanticipated increases in the price of natural gas that we purchase for our utility customers could exhaust our liquidity in the winter months.
•: Counterparties may default on their obligations to supply commodities or return collateral to us or to meet their obligations under commercial contracts, including those designed to hedge against movements in commodity prices.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Price Risk Management

We engage in price risk management activities for both the continued mitigation of our trading portfolio and commodity risk mitigation in our utilities business. 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 2005 are summarized below:

In millions

Fair value at December 31, 2004	$	21.4
Change in fair value during the period		(6.9	)
Contracts realized or cash settled		20.9

Fair value at March 31, 2005	$	35.4

The fair value of contracts maturing in the remainder of 2005, each of the next three years and thereafter are shown below:

In millions

2005	$	(2.5	)
2006		10.0
2007		19.3
2008		2.8
Thereafter		5.8

Total fair value	$	35.4

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 1. Legal Proceedings

AMS Shareholder Lawsuit

Price Reporting Litigation

with certainty whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

Enron Bankruptcy Litigation

Lender Litigation

ERISA Litigation

On September 24, 2004, a lawsuit was filed in the U.S. District Court for the Western District of Missouri against us, certain members of the Board of Directors and certain members of management alleging they violated ERISA and are responsible for losses that participants in the Aquila 401(k) plan experienced as a result of the decline in the value of their Aquila stock held in the Aquila 401(k) plan. A number of similar lawsuits alleging that the defendants breached their fiduciary duties to the plan participants in violation of ERISA by concealing information and/or misleading employees who held Aquila stock through the Aquila 401(k) plan were subsequently filed against us. The suits also seek damages for the plan's losses resulting from the alleged breaches of fiduciary duties. On January 26, 2005 the court ordered that all of these lawsuits be consolidated into a single case captioned, In re Aquila ERISA Litigation. The plaintiffs filed an amended consolidated complaint in March 2005 which largely repeats each of the allegations in the first complaint. We believe we have strong defenses and will defend this case vigorously. We cannot predict with certainty whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows. This case has been set for trial in July 2007.

South Harper Peaking Facility

injunction; however, we are permitted to continue construction while the order is appealed. The matter is now before the Missouri Court of Appeals following our appeal of the trial court decision. We will defend this case vigorously as we believe we have strong defenses to plaintiff's claims. We cannot predict with certainty whether we will be prevented from completing this facility, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit (including costs of replacement power). However, given that the remedy sought is the removal of the nearly completed facility, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

Item 6. Exhibits

(a) List of Exhibits

Exhibit No.		Description
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

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 3, 2005