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 June 30, 2004
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 1-03562

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

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

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

Class		Outstanding at July 29, 2004
Common Stock, $1 par value		195,689,185

Part I—Financial Information

Item 1. Financial Statements

Information regarding the consolidated financial statements is on pages 3 through 24.

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 25 through 45.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are subject to market risk as described on pages 71 through 74 of our 2003 Annual Report on Form 10-K. See discussion on page 45 of this document for changes in market risk since December 31, 2003.

Item 4. Controls and Procedures

Information regarding disclosure controls and procedures is on page 46.

Part II—Other Information

Item 1. Legal Proceedings

Information regarding legal proceedings is on page 47.

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

Information regarding submission of matters for a vote of security holders is on page 48.

Item 5. Other Information

Information regarding other items is on page 48.

Item 6. Exhibits and Reports on Form 8-K

Exhibits and Reports on Form 8-K are on page 48.

Part I. Financial Information

Item 1. Financial Statements

Aquila, Inc.
Consolidated Statements of Income—Unaudited

		Three Months Ended June 30,
In millions, except per share amounts			2004			2003

Sales:
	Electricity—regulated	$	181.9		$	158.7
	Natural gas—regulated		155.7			156.9
	Electricity—non-regulated		7.8			(10.0	)
	Natural gas—non-regulated		(7.2	)		61.4
	Other—non-regulated		(2.9	)		.4

Total sales			335.3			367.4

Cost of sales:
	Electricity—regulated		98.3			80.3
	Natural gas—regulated		101.4			102.0
	Electricity—non-regulated		14.5			21.0
	Natural gas—non-regulated		2.5			11.0
	Other—non-regulated		5.6			5.3

Total cost of sales			222.3			219.6

Gross profit			113.0			147.8

Operating expenses:
	Operating expense		133.8			145.4
	Restructuring charges		.6			20.8
	Net loss (gain) on sale of assets		(10.4	)		103.0
	Depreciation and amortization expense		36.4			37.5

Total operating expenses			160.4			306.7

Other income (expense):
	Equity in earnings of investments		—			36.6
	Other income		4.5			43.5

Total other income (expense)			4.5			80.1

Interest expense			63.5			71.0

Loss from continuing operations before income taxes			(106.4	)		(149.8	)
Income tax benefit			(39.3	)		(44.5	)

Loss from continuing operations			(67.1	)		(105.3	)
Earnings from discontinued operations, net of tax			23.8			24.7

Net loss		$	(43.3	)	$	(80.6	)

Basic and diluted earnings (loss) per common share:
	Continuing operations	$	(.34	)	$	(.54	)
	Discontinued operations		.12			.13

	Net loss	$	(.22	)	$	(.41	)

Dividends per common share		$	—		$	—

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Statements of Income—Unaudited

		Six Months Ended June 30,
In millions, except per share amounts			2004			2003

Sales:
	Electricity—regulated	$	341.9		$	309.2
	Natural gas—regulated		594.2			577.5
	Electricity—non-regulated		6.0			(30.6	)
	Natural gas—non-regulated		(52.5	)		30.9
	Other—non-regulated		(1.1	)		3.2

Total sales			888.5			890.2

Cost of sales:
	Electricity—regulated		180.1			152.0
	Natural gas—regulated		428.9			407.9
	Electricity—non-regulated		30.7			47.0
	Natural gas—non-regulated		2.5			14.8
	Other—non-regulated		12.0			11.1

Total cost of sales			654.2			632.8

Gross profit			234.3			257.4

Operating expenses:
	Operating expense		251.6			281.7
	Restructuring charges		.9			27.1
	Net loss on sale of assets		21.7			100.8
	Depreciation and amortization expense		74.8			85.2

Total operating expenses			349.0			494.8

Other income (expense):
	Equity in earnings of investments		2.1			61.1
	Other income		6.0			63.3

Total other income (expense)			8.1			124.4

Interest expense			127.8			131.8

Loss from continuing operations before income taxes			(234.4	)		(244.8	)
Income tax benefit			(82.7	)		(75.1	)

Loss from continuing operations			(151.7	)		(169.7	)
Earnings from discontinued operations, net of tax			56.6			37.2

Net loss		$	(95.1	)	$	(132.5	)

Basic and diluted earnings (loss) per common share:
	Continuing operations	$	(.78	)	$	(.87	)
	Discontinued operations		.29			.19

	Net loss	$	(.49	)	$	(.68	)

Dividends per common share		$	—		$	—

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Balance Sheets

In millions			June 30, 2004		December 31, 2003

			(Unaudited)
Assets
Current assets:
	Cash and cash equivalents	$	637.8	$	601.7
	Restricted cash		775.1		249.2
	Funds on deposit		551.6		382.5
	Accounts receivable, net		416.1		598.4
	Inventories and supplies		116.5		149.4
	Price risk management assets		358.5		311.0
	Prepayments and other		190.1		194.7
	Current assets of discontinued operations		—		231.9

Total current assets			3,045.7		2,718.8

	Property, plant and equipment, net		2,754.5		2,752.7
	Investments in unconsolidated subsidiaries		3.1		312.9
	Price risk management assets		518.7		492.6
	Goodwill, net		111.0		111.0
	Deferred charges and other assets		202.3		271.9
	Non-current assets of discontinued operations		8.7		1,059.2

Total Assets		$	6,644.0	$	7,719.1

Liabilities and Shareholders' Equity
Current liabilities:
	Current maturities of long-term debt	$	421.8	$	414.8
	Accounts payable		328.1		488.2
	Accrued liabilities		339.5		335.4
	Price risk management liabilities		327.2		290.1
	Current portion of long-term gas contracts		86.1		84.8
	Customer funds on deposit		282.6		279.5
	Current liabilities of discontinued operations		—		368.5

Total current liabilities			1,785.3		2,261.3

Long-term liabilities:
	Long-term debt, net		2,206.8		2,291.2
	Deferred income taxes and credits		270.2		376.2
	Price risk management liabilities		433.6		383.5
	Long-term gas contracts, net		542.7		586.3
	Deferred credits		183.4		273.9
	Non-current liabilities of discontinued operations		—		187.4

Total long-term liabilities			3,636.7		4,098.5

Common shareholders' equity			1,222.0		1,359.3

Total Liabilities and Shareholders' Equity		$	6,644.0	$	7,719.1

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Statements of Comprehensive Income—Unaudited


			Three Months Ended June 30,						Six Months Ended June 30,

In millions				2004			2003			2004			2003

Net loss			$	(43.3	)	$	(80.6	)	$	(95.1	)	$	(132.5	)
Other comprehensive income (loss), net of related tax:
	Foreign currency adjustments:
		Foreign currency translation adjustments, net of deferred tax expense (benefit) of $(12.3) million and $44.5 million for the three months ended June 30, 2004 and 2003, respectively, and $(14.2) million and $44.5 million for the six months ended June 30, 2004 and 2003, respectively		(18.6	)		26.2			(21.8	)		87.2
		Reclassification of foreign currency (gains) losses to income due to sale of businesses, net of deferred tax (expense) benefit of $(9.6) million and $(21.5) million for the three and six months ended June 30, 2004, respectively		(15.1	)		—			(33.7	)		—

		Total foreign currency adjustments		(33.7	)		26.2			(55.5	)		87.2

	Cash flow hedges:
		Unrealized gains (losses) on hedging instruments net of deferred tax expense (benefit) of $(.6) million and $(.3) million for the three months ended June 30, 2004 and 2003, respectively, and $(1.0) million and $(.6) million for the six months ended June 30, 2004 and 2003, respectively		(.9	)		(.5	)		(1.6	)		(1.0	)
		Unrealized gains (losses) on hedging instruments of equity method investments, net of deferred tax expense (benefit) of $(8.0) million and $(8.1) million for the three months and six months ended June 30, 2004, respectively		—			(9.3	)		—			(11.7	)
		Reclassification of net (gains) losses on hedging instruments to net income, net of deferred tax (expense) benefit of $(.1) million and $7.0 million for the three months ended June 30, 2004 and 2003, respectively, and $.2 million and $9.1 million for the six months ended June 30, 2004 and 2003, respectively		(.2	)		10.8			.3			14.0
		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 $.2 million for the three months ended June 30, 2003, and $5.5 million and $.2 million for the six months ended June 30, 2004 and 2003, respectively		—			.4			9.1			.4

		Total cash flow hedges		(1.1	)		1.4			7.8			1.7

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

		Total held for sale securities		—			—			—			(7.3	)

	Decrease in minimum pension liability, net of deferred tax expense of $2.7 million for the three months and six months ended June 30, 2004, respectively			4.4			—			4.4			—

	Other comprehensive income (loss)			(30.4	)		27.6			(43.3	)		81.6

Total Comprehensive Income (Loss)			$	(73.7	)	$	(53.0	)	$	(138.4	)	$	(50.9	)

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Statements of Common Shareholders' Equity

In millions		June 30, 2004			December 31, 2003

		(Unaudited)
Common stock: authorized 400 million shares at June 30, 2004 and December 31, 2003, par value $1 per share; 195,673,952 shares issued at June 30, 2004 and 195,252,630 shares issued at December 31, 2003; authorized 20 million shares of Class A common stock, par value $1 per share, none issued	$	195.7		$	195.3
Premium on capital stock		3,162.2			3,161.3
Retained deficit		(2,143.2	)		(2,047.9	)
Accumulated other comprehensive income		7.3			50.6

Total Common Shareholders' Equity	$	1,222.0		$	1,359.3

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Statements of Cash Flows—Unaudited

				Six Months Ended June 30,
In millions					2004			2003

Cash Flows From Operating Activities:
	Net loss			$	(95.1	)	$	(132.5	)
	Adjustments to reconcile net loss to net cash used for operating activities:
		Depreciation and amortization expense			74.8			93.6
		Restructuring charges			.9			27.1
		Cash paid for restructuring and other charges			(9.1	)		(153.2	)
		Net (gain) loss on sale of assets			(52.4	)		100.8
		Net changes in price risk management assets and liabilities			26.2			4.1
		Deferred income taxes and investment tax credits			(87.0	)		(63.3	)
		Equity in earnings of investments			(2.1	)		(61.1	)
		Dividends and fees from investments			1.1			33.2
		Changes in certain assets and liabilities, net of effects of divestitures:
			Restricted cash		(15.5	)		(160.5	)
			Funds on deposit		99.6			(166.7	)
			Accounts receivable/payable, net		27.1			(111.5	)
			Inventories and supplies		27.3			34.3
			Prepayments and other		(11.2	)		163.2
			Deferred charges and other assets		7.2			22.9
			Accrued liabilities		(14.4	)		135.3
			Customer funds on deposit		2.9			104.6
			Deferred credits		(18.3	)		(31.5	)
			Other		(.2	)		(68.1	)

Cash used for operating activities					(38.2	)		(229.3	)

Cash Flows From Investing Activities:
	Restricted cash for long-term gas contract surety				(504.0	)		—
	Utilities capital expenditures				(128.0	)		(99.3	)
	Merchant capital expenditures				—			(32.7	)
	Cash proceeds received on sale of assets				1,271.1			402.5
	Merchant investments in unconsolidated subsidiaries				—			(44.5	)
	Other				(5.5	)		(34.5	)

Cash provided from investing activities					633.6			191.5

Cash Flows From Financing Activities:
	Funds on deposit with 7.00% senior note trustee				(250.0	)		—
	Issuance of long-term debt				—			412.0
	Retirement of long-term debt				(113.6	)		(433.8	)
	Short-term borrowings (repayments), net				(215.0	)		(79.4	)
	Cash paid on long-term gas contracts				(42.3	)		(41.0	)
	Other				5.8			2.8

Cash used for financing activities					(615.1	)		(139.4	)

Decrease in cash and cash equivalents					(19.7	)		(177.2	)
Cash and cash equivalents at beginning of period (includes $55.8 million and $55.6 million, respectively, of cash included in current assets of discontinued operations)					657.5			441.7

Cash and cash equivalents at end of period (includes $— million and $65.9 million, respectively, of cash included in current assets of discontinued operations)				$	637.8		$	264.5

See accompanying notes to consolidated financial statements.

AQUILA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with the accounting policies described in the consolidated financial statements and related notes included in our 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 10, 2004. You should read our 2003 Form 10-K in conjunction with this report. The accompanying Consolidated Balance Sheets and Consolidated Statements of Common Shareholders' Equity as of December 31, 2003, were derived from our audited financial statements, but do not include all disclosures required by accounting principles generally accepted in the United States. In our opinion, the accompanying consolidated financial statements reflect all adjustments (which include only normal recurring adjustments) necessary for a fair representation of our financial position and the results of our operations. Certain estimates and assumptions have been made in preparing the consolidated financial statements that affect reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of sales and expenses during the reporting periods shown. Actual results could differ from these estimates.

Certain prior year amounts in the consolidated financial statements have been reclassified where necessary to conform to the 2004 presentation. In particular, as discussed in Note 4, the results of operations from certain assets that were sold in 2003 and 2004 have been reclassified as discontinued operations in the accompanying balance sheets and statements of income for all periods presented.

Stock Based Compensation

We issue stock options to employees from time to time and account for these options under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25). All stock options issued are granted at the common stock's market price at date of grant. Therefore we record no compensation expense related to stock options.

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

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


		Three Months Ended June 30,						Six Months Ended June 30,

In millions, except per share amounts			2004			2003			2004			2003

Net loss:
	As reported	$	(43.3	)	$	(80.6	)	$	(95.1	)	$	(132.5	)
	Total stock-based employee compensation expense determined under fair value method, net of related tax benefits		(1.4	)		(1.3	)		(2.8	)		(2.8	)

	Pro forma net loss	$	(44.7	)	$	(81.9	)	$	(97.9	)	$	(135.3	)

Basic and diluted loss per share:
	As reported	$	(.22	)	$	(.41	)	$	(.49	)	$	(.68	)
	Pro forma		(.23	)		(.42	)		(.50	)		(.70	)

New Accounting Standards

Variable Interest Entities

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

2. Restructuring Charges

We recorded the following restructuring charges:


		Three Months Ended June 30,					Six Months Ended June 30,

In millions			2004		2003			2004		2003

Merchant Services:
	Interest rate swap reductions	$	—	$	17.8		$	—	$	23.1
	Severance costs		.4		1.5			.6		1.5
	Other		—		(.6	)		—		(.6	)

	Total Merchant Services		.4		18.7			.6		24.0
Corporate and Other severance costs			.2		2.1			.3		3.1

Total restructuring charges		$	.6	$	20.8		$	.9	$	27.1

Severance Costs and Retention Payments

For the three and six months ended June 30, 2004, we incurred severance and other related costs of $.6 million and $.9 million, respectively, related to the continued exit of our Merchant Services business and the sale of our investments in international networks.

For the three and six months ended June 30, 2003, we incurred severance and other related costs of $2.1 million and $3.1 million, respectively, in connection with the restructuring of Everest Connections, our communications business which is included in Corporate and Other, and the alignment of our management team with our new strategic direction. The Everest Connections restructuring costs resulted from a reduction of approximately 160 employees. We also incurred $1.5 million of severance and retention costs in the second quarter of 2003 related to the continued wind-down of our energy trading operations in Merchant Services.

Interest Rate Swap Reductions

We incurred $17.8 million and $23.1 million of restructuring charges for the three and six months ended June 30, 2003, respectively, to exit interest rate swaps related to our Clay County and Piatt County construction financing arrangements. As debt related to these facilities was paid down, the notional amount of our interest rate swaps exceeded the outstanding debt. Thus, we reduced our position and realized the loss associated with the cancelled swaps.

Restructuring Reserve Activity

The following is a summary of the activity for accrued restructuring charges for the six months ended June 30, 2004:

In millions

Severance and Retention Costs:
	Accrued severance costs as of December 31, 2003	$	.9
	Additional expense during the period		.9
	Cash payments during the period		(.6	)

Accrued severance and retention costs as of June 30, 2004		$	1.2

Other Restructuring Costs:
	Accrued other restructuring costs as of December 31, 2003	$	16.0
	Additional expense during the period		—
	Cash payments during the period		(3.5	)

Accrued other restructuring costs as of June 30, 2004 (a)		$	12.5

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

3. Net Loss (Gain) on Sale of Assets

We have sold the assets 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:


		Three Months Ended June 30,						Six Months Ended June 30,

In millions			2004			2003			2004			2003

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

	Total Domestic Utilities		—			—			—			(2.2	)

Merchant Services:
	Aries power project and tolling agreement		—			—			47.0			—
	Independent power plants		—			—			(6.1	)		—
	Marchwood development project		—			—			(5.0	)		—
	Investment in BAF Energy		(9.1	)		—			(9.1	)		—
	Acadia tolling agreement		—			105.5			—			105.5
	Turbines		—			(5.1	)		—			(5.1	)

	Total Merchant Services		(9.1	)		100.4			26.8			100.4

Corporate and Other:
	Midlands Electricity		—			—			(3.3	)		—
	Australia		—			2.6			—			2.6
	Other		(1.3	)		—			(1.8	)		—

	Total Corporate and Other		(1.3	)		2.6			(5.1	)		2.6

Total net loss (gain) on sale of assets		$	(10.4	)	$	103.0		$	21.7		$	100.8

Aries Power Project and Tolling Agreement

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

Independent Power Plants

In November 2003, we agreed to sell our interests in 12 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.

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.

Investment in BAF Energy

We own a 23.11% non-voting limited partnership interest in BAF Energy, a California limited partnership that formerly owned a 120 MW natural gas-fired combined cycle cogeneration facility in King City, California. In May 2004, Calpine King City Cogen, LLC purchased 100% of the King City cogeneration facility from BAF Energy. Our share of the proceeds, approximately $24.3 million, was received as a distribution from the partnership in June 2004. As a result of the distribution, we recorded a pretax gain of $9.1 million, or $5.7 million after tax, in the second quarter of 2004.

Acadia Tolling Agreement

In May 2003, we terminated our 20-year tolling agreement for the Acadia power plant in Louisiana. After making a termination payment of $105.5 million, or $63.8 million after tax, we were released from the remaining aggregate payment obligation of $833.9 million, or approximately $43.5 million on an annual basis.

Turbines

We had a contract to acquire four GE turbines. Our intent was to use these turbines in future power plant development projects. However, due to the restructuring of our business and change in our business strategy, in 2002 we decided to cease these development projects and sell these turbines or return them to the manufacturer. As a result, we incurred a $42.1 million pretax charge, or $25.5 million after tax, related to the expected loss on sale or contract termination related to these turbines.

During the second quarter of 2003, we completed the contract termination and sale of certain turbines which had been written down to an estimated realizable value at December 31, 2002. In connection with the disposition, we recorded a pretax gain of $5.1 million, or $3.2 million after tax.

Midlands Electricity

In October 2003, we and FirstEnergy Corp. agreed to sell 100% of the shares of Aquila Sterling Limited (ASL), the owner of Midlands Electricity plc, to a subsidiary of Powergen UK plc for approximately £36 million. We completed the sale of ASL in January 2004. We received proceeds of $55.5 million and paid approximately $7.6 million in transaction fees. We recorded a pretax and after-tax gain from this sale of $3.3 million in the first quarter of 2004. 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.

Australia

In April 2003, we reached an agreement to sell our interests in Multinet Gas, United Energy Limited and AlintaGas Limited to a consortium consisting of AlintaGas, AMP Henderson and their affiliates. In May 2003, as the first step in the sale process, we sold our interest in AlintaGas and received approximately $97.0 million in cash proceeds in May and July. We recorded a pretax loss of $2.6 million, or $1.6 million after tax, in the second quarter of 2003 in connection with this sale.

4. Discontinued Operations

We have sold our investments in independent power plants and our Canadian utility businesses, which are therefore considered discontinued operations in accordance with SFAS 144. The only remaining asset classified as held for sale is a Merchant note receivable of $8.7 million which was not sold with our Merchant loan business in December 2002. 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 based in Newfoundland and Labrador, 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 include $85 million (CDN$116 million) of preliminary adjustments for working capital and capital expenditures as provided under the sale agreements. These proceeds are subject to final adjustments, which are expected to be determined in the third quarter of 2004. We recorded a pretax gain from this sale of $65.7 million, or $9.2 million after tax, in the second quarter of 2004, subject to adjustment for final working capital and capital expenditure adjustments.

The effective tax rate on the pretax gain on the 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. In addition, the difference between book and tax basis relating to the elimination of depreciation under SFAS 144 also contributed to the higher tax provision on the pretax gain.

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, we were released at the closing of the sale from our guarantor obligations with respect to our former British Columbia utility's debentures and secured 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. We recorded a pretax impairment charge of $47.5 million, or $39.8 million after tax, to reduce the carrying value of these assets to their estimated fair value less costs to sell in the third quarter of 2003. We closed this sale in March 2004. Because the actual proceeds realized were greater than estimated when we recorded the 2003 impairment charge, we recorded a pretax gain of $8.4 million, or $16.2 million after tax, 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 a detailed allocation of the purchase price for tax purposes is completed based on an independent appraisal and the final tax returns are filed related to the sale.

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

In millions			June 30, 2004		December 31, 2003

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

Total current assets of discontinued operations		$	—	$	231.9

Non-current assets of discontinued operations:
	Property, plant and equipment, net	$	—	$	752.1
	Price risk management assets		—		45.8
	Goodwill, net		—		229.5
	Other non-current assets		8.7		31.8

Total non-current assets of discontinued operations		$	8.7	$	1,059.2

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

Total current liabilities of discontinued operations		$	—	$	368.5

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

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

Operating results from our discontinued operations are as follows:


		Three Months Ended June 30,					Six Months Ended June 30,

In millions			2004			2003		2004			2003

Sales		$	42.7		$	103.6	$	131.0		$	160.3
Cost of sales			6.2			14.1		25.1			32.1

Gross profit			36.5			89.5		105.9			128.2

Operating expenses:
	Operating expense		24.6			30.3		56.4			61.8
	Gain on sale of assets		(65.7	)		—		(74.1	)		—
	Depreciation and amortization expense		—			11.2		—			8.4

Total operating expenses			(41.1	)		41.5		(17.7	)		70.2

Other income			14.2			.8		2.0			3.9
Interest expense			5.6			7.2		14.6			11.5

Earnings before income taxes			86.2			41.6		111.0			50.4
Income tax expense			62.4			16.9		54.4			13.2

Earnings from discontinued operations		$	23.8		$	24.7	$	56.6		$	37.2

5. Earnings (Loss) per Common Share

The table below shows how we calculated basic and diluted earnings (loss) per share. Basic earnings (loss) per share and basic weighted average shares are the starting point in calculating the dilutive measures. To calculate basic earnings (loss) per share, divide our net loss for the period by our weighted average shares outstanding, without adjusting for dilutive items. Diluted earnings (loss) per share is calculated by dividing our net loss, after assumed conversion of dilutive securities, by our weighted average shares outstanding, adjusted for the effect of dilutive securities. However, as a result of the net losses in the three and six months ended June 30, 2004 and 2003, the potential issuances of common stock for dilutive securities were considered anti-dilutive and therefore not included in the calculation of diluted earnings (loss) per share.


		Three Months Ended June 30,						Six Months Ended June 30,

In millions, except per share amounts			2004			2003			2004			2003

Loss from continuing operations		$	(67.1	)	$	(105.3	)	$	(151.7	)	$	(169.7	)
Earnings from discontinued operations			23.8			24.7			56.6			37.2

Net loss		$	(43.3	)	$	(80.6	)	$	(95.1	)	$	(132.5	)

Basic and diluted earnings (loss) per share:
	Loss from continuing operations	$	(.34	)	$	(.54	)	$	(.78	)	$	(.87	)
	Earnings from discontinued operations		.12			.13			.29			.19

	Net loss	$	(.22	)	$	(.41	)	$	(.49	)	$	(.68	)

Weighted average number of common shares used in basic and diluted earnings (loss) per share			195.6			194.6			195.5			194.3

6. Reportable Segment Reconciliation

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

Our reportable segment reconciliation is shown below:

		Three Months Ended June 30,						Six Months Ended June 30,

In millions			2004			2003			2004			2003

Sales:
	Domestic Utilities	$	347.0		$	329.5		$	952.9		$	912.5
	Merchant Services		(21.2	)		28.8			(82.8	)		(39.1	)
	Corporate and Other		9.5			9.1			18.4			16.8

Total sales		$	335.3		$	367.4		$	888.5		$	890.2

Earnings (Loss) Before Interest and Taxes (EBIT):
	Domestic Utilities	$	9.6		$	10.9		$	73.0		$	85.9
	Merchant Services		(39.6	)		(126.7	)		(165.9	)		(234.6	)
	Corporate and Other		(12.9	)		37.0			(13.7	)		35.7

Total EBIT			(42.9	)		(78.8	)		(106.6	)		(113.0	)
Interest expense			63.5			71.0			127.8			131.8

Loss from continuing operations before income taxes		$	(106.4	)	$	(149.8	)	$	(234.4	)	$	(244.8	)

In millions			June 30, 2004		December 31, 2003

Assets:*
	Domestic Utilities	$	2,908.5	$	3,060.2
	Merchant Services		2,111.0		2,717.8
	Corporate and Other		1,624.5		1,941.1

Total assets		$	6,644.0	$	7,719.1

* Included in total assets as of June 30, 2004 and December 31, 2003 are total current and non-current assets of discontinued operations as follows: Merchant Services, $8.7 million and $128.5 million, and Corporate and Other, $— million and $1,162.6 million, respectively.

7. Financings

Note Payable

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

Letter of Credit Facilities

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 June 30, 2004, $72.5 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 June 30, 2004.

On July 30, 2004, we entered into a $25 million letter of credit facility with a commercial bank. This three-year facility was arranged in connection with the termination of our Municipal Gas Authority of Mississippi (MGAM) gas supply contract, and a $25 million letter of credit was issued under the facility for the benefit of St. Paul Travelers on July 30, 2004, as discussed in Note 10 below. The letter of credit is fully secured by cash deposits with the bank.

Senior Notes

On June 30, 2004, we irrevocably deposited $258.8 million, which included accrued interest, with the trustee for the 7.00% series of senior notes due July 15, 2004 in order to economically defease this obligation under the terms of our $430 million three-year secured loan. This deposit was classified as funds on deposit in the accompanying Consolidated Balance Sheet. The senior notes were retired on July 15, 2004.

8. Employee Benefits

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

		Pension Benefits						Other Post-retirement Benefits

	Three Months Ended June 30,
In millions		2004			2003			2004			2003

Components of Net Periodic Benefit Cost:
Service cost	$	1.9		$	2.0		$	—		$	—
Interest cost		4.9			4.8			1.2			1.2
Expected return on plan assets		(6.0	)		(5.7	)		(.2	)		(.3	)
Amortization of transition amount		(.3	)		(.3	)		.2			.4
Amortization of prior service cost		.3			.3			.4			.2
Recognized net actuarial loss		2.0			2.6			.5			.3
Curtailment (gain) loss		—			.1			—			—
Regulatory adjustment		1.3			(.9	)		.2			—

Net Periodic Benefit Cost	$	4.1		$	2.9		$	2.3		$	1.8

		Pension Benefits						Other Post-retirement Benefits

	Six Months Ended June 30,
In millions		2004			2003			2004			2003

Components of Net Periodic Benefit Cost:
Service cost	$	3.9		$	4.0		$	.1		$	.1
Interest cost		9.7			9.6			2.4			2.4
Expected return on plan assets		(12.0	)		(11.5	)		(.5	)		(.6	)
Amortization of transition amount		(.6	)		(.6	)		.4			.8
Amortization of prior service cost		.6			.6			.8			.4
Recognized net actuarial loss		4.0			5.2			1.0			.6
Curtailment (gain) loss		—			.2			—			(.1	)
Regulatory adjustment		1.4			(1.8	)		.4			.1

Net Periodic Benefit Cost	$	7.0		$	5.7		$	4.6		$	3.7

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

In our most recent settlement with the Missouri Public Service Commission (the Commission), we agreed to recover our Missouri-related pension funding at an agreed-upon annual amount for ratemaking purposes. This settlement determines the annual amount we will recover and recognize as pension expense beginning in the second quarter of 2004. As ordered by the Commission, the difference between the agreed-upon expense for ratemaking purposes and the amount determined under Statement of Financial Accounting Standards No. 87, "Employers' Accounting for Pensions," will be recognized as a regulatory asset or liability in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation." The impact of this settlement on net periodic benefit cost was an increase of $1.2 million for the three and six months ended June 30, 2004, and is estimated to be an increase of $4.3 million for the full year of 2004.

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) became effective. The Act expands Medicare, primarily by offering a prescription drug benefit to Medicare-eligible retirees starting in 2006. We have not determined whether the benefits provided under our plans are actuarially equivalent to Medicare Part D under the Act. As a result, the retiree medical obligations and costs reported do not reflect the impact of this legislation. We expect to disclose the Act's impact on our post-retirement benefit obligations and costs in the third quarter of 2004.

9. Legal

Chubb Settlement

On February 19, 2002, we filed a suit in the U.S. District Court for the Western District of Missouri (the Court) against two companies in the Chubb Group of Insurance Companies, the issuer of surety bonds in support of certain of our long-term gas supply contracts. Chubb had demanded that it be released from its surety obligation or, alternatively, that we post collateral to secure its obligation. On June 14, 2004, the Court granted Chubb's request for an order temporarily restraining us from using the proceeds from our recent Canadian utility sale for any purpose, including the satisfaction of existing liabilities. On June 24, 2004, the Court issued a preliminary injunction prohibiting us from using $504 million of proceeds from the sale of our

Canadian utilities and requiring us to deposit this amount in an escrow account for the benefit of Chubb until the underlying lawsuit could be resolved on its merits.

On July 19, 2004, we entered into a settlement stipulation with Chubb that resulted in the dismissal, with prejudice, of litigation over Chubb's demand for us to post collateral in support of our indemnity obligations. Under the settlement stipulation, we posted $500 million of cash with Chubb to secure its obligations in respect of the surety bonds until the underlying gas supply contracts can be terminated. Chubb also agreed to post a $15 million letter of credit for our benefit in recognition of our costs and efforts in putting these collateral arrangements in place. The Court approved the settlement stipulation on July 20, 2004. See Note 10 for further discussion.

Appraisal Rights Litigation

In June 2004, the Delaware Court of Chancery approved the settlement of a lawsuit brought against us by persons formerly holding certificates representing approximately 1.7 million shares of Aquila Merchant common stock. These minority holders were pursuing their statutory appraisal rights in connection with our recombination with our Aquila Merchant subsidiary in January 2002. We paid approximately $38 million, including interest from 2002, to settle this litigation. This required an additional expense of $7.5 million plus litigation costs in the second quarter of 2004.

EPCOR Litigation

On August 18, 2003, EPCOR filed a lawsuit against us, Aquila Canada ULC (formerly Aquila Networks Canada Limited), and FortisAlberta Ltd. (formerly Aquila Networks Canada (Alberta) Ltd.) in the Court of Queen's Bench of Alberta. EPCOR alleged that we breached our agreements with EPCOR in which the Alberta utility agreed to provide to EPCOR certain customer and billing information in connection with EPCOR's provision of retail service to the utility's customers. EPCOR claimed CDN$77 million for breach of the agreements and for negligence, including damage to its reputation, and CDN$6 million in aggravated and punitive damages. This litigation was assumed by the purchaser of our Alberta utility upon the closing of the sale transaction, and an affiliate of the purchaser has agreed to indemnify us and Aquila Canada ULC against any damages or liabilities arising from this litigation.

California and Washington Litigation

We and a number of other energy companies have been jointly sued by the City and County of San Francisco, California, the County of Santa Clara, California and the County of San Diego, California alleging the defendants manipulated the price of natural gas during California's 2000-2001 energy crisis. We are also one of a number of other defendants in a lawsuit brought by the City of Tacoma, Washington alleging we were part of a conspiracy to drive up the price of electricity. These cases were only recently filed and we are in the process evaluating the claims.

10. Long-Term Gas Contracts

Chubb Surety Settlement

As discussed in Note 9, in June 2004, we were required to segregate $504 million of cash pursuant to a preliminary injunction issued on behalf of Chubb.

In July 2004, we agreed with two subsidiaries of Chubb to escrow cash of approximately $485 million, net of the $15 million Chubb letter of credit (from the $504 million segregated pursuant to the preliminary injunction) related to two surety agreements we entered into with

Chubb in connection with two long-term gas contracts with American Public Energy Agency (APEA). Under these surety agreements, we provided an indemnity to Chubb for payments they would incur related to their contractual obligation to APEA. Our payment obligation under a termination of these contracts in July 2004 would be approximately $500 million, net of our hedge position.

St. Paul Surety Settlement

In June 2004, we entered into negotiations with St. Paul Travelers (St. Paul) to avoid future litigation regarding two surety agreements we entered into with St. Paul in connection with two long-term gas contracts with APEA (APEA II) and MGAM. These contracts are similar but not identical to the Chubb surety contracts. On July 19, 2004, we agreed with St. Paul to post collateral of approximately $90.3 million, net of our hedge position, with St. Paul in respect of our MGAM contract. Our payment obligation under a default of this contract in July 2004 would be approximately $91.3 million, net of our hedge position. Additionally, we agreed to post collateral of $25 million with St. Paul in respect of our APEA II contract and, upon the sooner of December 31, 2004 or our completion of a capital markets transaction greater than $225 million, we would increase our posted collateral to $130 million to cover St. Paul's remaining exposure under the APEA II contract. At the point we would be required to post additional collateral with St. Paul with respect to APEA II, we intend to begin a termination process that would be similar to the contracts below.

Termination of Long-term Gas Contracts

In July 2004, we began a process to terminate three long-term gas contracts, which include the APEA contracts for which Chubb provided surety bonds (APEA III and APEA IV) and our MGAM contract.

On July 30, 2004, we reached an agreement with MGAM on the termination of our long-term gas supply contract with them. As a result, we and St. Paul were required to pay MGAM amounts due under the liquidated damages and other provisions of the gas supply contract and termination agreement.

We have had discussions with APEA regarding our actions to attempt to terminate the APEA III and APEA IV contracts. The final termination process could take up to 100 days. Absent an earlier settlement with APEA, APEA will be entitled to terminate these contracts at the end of the period. The contracts provide for a predetermined calculation of damages that Chubb would be required to pay APEA on the contracts we have terminated. This payment would be approximately $500 million as of July 19, 2004, when we began the termination process. Under our settlement, Chubb would only have recourse against Aquila for approximately $485 million, the amount of cash escrowed with them, net of their $15 million letter of credit for our benefit.

We do not intend to terminate our two remaining long-term gas contracts with the Municipal Gas Authority of Georgia (MGAG) and APEA (APEA I), which had a total obligation of approximately $54.6 million and total remaining cash payments of $81.3 million at June 30, 2004 and which expire in 2007 and 2008, respectively.

The following table shows the obligation reflected on our balance sheet as of June 30, 2004 and the annual cash requirements to procure the gas contracted under each of the four contracts discussed above.

		Long-Term Gas Contracts
In millions			APEA III		APEA IV	MGAM	APEA II

Surety provided by			Chubb		Chubb	St. Paul	St. Paul
Long-Term Gas Contract Obligation at June 30, 2004		$	162.3	$	235.7	$ 77.8	$ 98.4

Total Long-Term Gas Contract Cash Payments:
2004 (July-December)		$	16.6	$	20.5	$ 8.5	$ 9.9
2005			33.2		39.4	17.3	25.5
2006			33.9		42.6	17.4	26.1
Thereafter			174.5		301.0	70.5	86.0

	Total	$	258.2	$	403.5	$113.7	$147.5

When these four long-term gas contracts have been terminated and the sureties have drawn on our collateral amounts, we will recognize losses for the excess of the collateral amounts drawn over the long-term gas contract obligations. The amounts of the termination obligations are greater than the long-term gas contract balances on our Consolidated Balance Sheet due to our required use of the units of revenue method of relieving the long-term obligation versus a present value method applied under default provisions of the contracts.

In addition, the price risk management assets and liabilities associated with these long-term gas contracts, and the related commodity hedges that will be terminated, will be realized resulting in non-cash mark-to-market losses related to the discounting of our trading portfolio. 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.

Following is a condensed pro forma consolidated balance sheet as of June 30, 2004, reflecting the surety settlements and assumed termination of APEA III, APEA IV and MGAM. Also, reflected is the retirement of the 7.00% series of senior notes from the funds on deposit with the trustee on June 30, 2004. The pro forma balance sheet is not necessarily indicative of the actual results when the long-term gas contracts are terminated.

Condensed Pro Forma Consolidated Balance Sheet
As of June 30, 2004

In millions			As Reported		Pro Forma Adjustments				Adjusted Pro Forma Balances

	Cash and cash equivalents	$	637.8	$	(71.0	)	(a)	$	566.8
	Restricted cash		775.1		(655.5	)	(a) (d)		119.6
	Funds on deposit		551.6		(258.8	)	(b)		292.8
	Other current assets		1,081.2						1,081.2

Total current assets			3,045.7		(985.3	)			2,060.4

	Property, plant and equipment, net		2,754.5						2,754.5
	Price risk management assets		518.7		(334.4	)	(c)		184.3
	Other non-current assets		325.1						325.1

Total Assets		$	6,644.0	$	(1,319.7	)		$	5,324.3

	Current maturities of long-term debt	$	421.8	$	(250.0	)	(b)	$	171.8
	Accrued liabilities		339.5		(8.8	)	(b)		330.7
	Current portion of long-term gas contracts		86.1		(55.3	)	(a)		30.8
	Customer funds on deposit		282.6		(151.5	)	(d)		131.1
	Other current liabilities		655.3						655.3

Total current liabilities			1,785.3		(465.6	)			1,319.7

Long-term liabilities:
	Long-term debt, net		2,206.8						2,206.8
	Deferred income taxes		270.2		(54.2	)	(a) (c)		216.0
	Price risk management liabilities		433.6		(292.5	)	(c)		141.1
	Long-term gas contracts		542.7		(420.5	)	(a)		122.2
	Other deferred credits		183.4						183.4

Total long-term liabilities			3,636.7		(767.2	)			2,869.5

Common shareholders' equity			1,222.0		(86.9	)	(a) (c)		1,135.1

Total Liabilities and Shareholders' Equity		$	6,644.0	$	(1,319.7	)		$	5,324.3

(a): Reflects the termination of the APEA III, APEA IV and MGAM long-term gas contracts for $485 million to Chubb and $90 million to St. Paul paid from the $504 million of restricted cash as of June 30, 2004 plus an additional $71.0 million of cash. The excess of the termination amount over the long-term gas contract obligation is reflected as a loss and reduces common shareholders' equity, net of a deferred tax benefit at 38.4%.
(b): Reflects the retirement of the 7.00% series of senior notes due July 15, 2004, including accrued interest from the $258.8 million of funds on deposit with the trustee at June 30, 2004.
(c): Reflects the reversal of approximately $334.4 million of price risk management assets and $292.5 million of price risk management liabilities associated with the long-term gas contracts and related natural gas commodity hedges, with the difference reflected as a non-cash mark-to-market loss, net of a deferred tax benefit at 38.4%.
(d): Reflects the return of $151.5 million of customer funds on deposit from restricted cash.

11. Restricted Cash

Our restricted cash on the Consolidated Balance Sheets was comprised of the following:

In millions		June 30, 2004		December 31, 2003

Restricted customer funds on deposit	$	270.8	$	248.7
Surety escrow account		504.0		—
Other		.3		.5

Total	$	775.1	$	249.2

A large counterparty has required us to segregate from our daily cash accounts the customer funds on deposit that they advanced to us. This amount is considered "restricted cash" and is not available for day-to-day operations. The amount of these deposits at June 30, 2004 and December 31, 2003 was $270.8 million and $248.7 million, respectively.

In June 2004, we were required to escrow approximately $504.0 million as a result of the preliminary injunction ruling related to the Chubb surety bonds. See Notes 9 and 10 for further discussion.

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

See Forward-Looking Information and Risk Factors beginning on page 45.

LIQUIDITY AND CAPITAL RESOURCES

Overall

Because of our non-investment grade credit rating and limitations on our ability to raise incremental capital through the bank market, for short-term liquidity needs we must rely primarily on our existing cash position. The following table reflects our anticipated cash sources and key short-term contractual obligations for the next 12 months, excluding operating cash flow and capital expenditures:

In millions

Anticipated Cash Sources: (a)
Cash and cash equivalents at June 30, 2004		$	637.8

Anticipated Debt, Toll and Long-term Gas Contract Requirements:
Current maturities of long-term debt: (b)
	Senior notes due on October 1, 2004		150.0
	Miscellaneous		21.8
Surety settlements and long-term gas contract terminations (c)			71.0
Long-term gas contract commitments for APEA I and MGAG and anticipated termination of APEA II			157.9
Elwood tolling agreement			37.3

Total		$	438.0

(a): Anticipated cash sources does not include any assumption regarding a capital markets transaction discussed below.
(b): The $250 million of senior notes due July 15, 2004 were retired from the funds on deposit with the trustee.
(c): Termination of APEA III, APEA IV and MGAM contracts net of escrowed funds as of June 30, 2004.

The remaining cash combined with future operating cash flows will be used for future working capital and capital expenditure requirements.

Long-Term Gas Contracts

See Note 10 to the Consolidated Financial Statements for further details of settlement with Chubb and St. Paul and the termination process for three long-term gas contracts. As part of our efforts to reposition the company as a stable domestic utility, we reviewed all of our alternatives to reduce liabilities and improve future cash flow. Increased cash flow from the reduction of these amortizing liabilities and improved operating cash flows from our remaining assets will be a significant contributor towards our goal of stabilizing the company and improving our overall credit profile.

Capital Markets Capability

As part of our plan to strengthen our balance sheet and credit profile, we have filed applications with the FERC, Kansas Corporation Commission, Iowa Utilities Board and Colorado Public Utility Commission for approval to enable us to enter the capital markets in 2004 and 2005. The proceeds from any issuance of securities would be used to further reduce our debt and contractual liabilities, which could include tolling contracts and long-term gas contracts.

Working Capital Requirements

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

Cash Flows

Cash Flows used for Operating Activities

Our negative six-month 2004 operating cash flows were driven by the following events and factors:

•: We had a net loss from continuing operations of $151.7 million before income tax benefits.
•: During 2004, we paid a $26.5 million civil penalty settlement to the Commodity Futures Trading Commission related to the reporting of natural gas trading information to publications and we paid $38 million to settle an appraisal rights lawsuit.
•: Offsetting cash outflows in 2004 were collateral returns resulting from the end of the winter season for our utility business and continued wind-down of our trading positions, use of inventory and other positive working capital in our utility business.

Our negative six-month 2003 operating cash flows were driven by the following events and factors:

•: We had a net loss from continuing operations of $244.8 million before income tax benefits.
•: We were required to post significant collateral as a result of our credit rating downgrades. These collateral demands were related to trading contracts as well as certain debt and tolling agreements.
•: We paid $105.5 million to terminate our 20-year tolling agreement for the Acadia power plant.
•: We made $47.7 million of restructuring payments in 2003 for severance, retention and other related charges primarily due to our exit from the wholesale energy trading business and for the restructuring of our domestic utilities business to more closely align it with its regulatory service areas.
•: Partially offsetting cash outflows were the receipt of approximately $191.1 million of income tax refunds, cash collections related to price risk management assets and inflows due to the liquidation of our wholesale gas storage inventory.

We have material margin losses related to our long-term gas contracts in our operating cash flows. These margin losses represent the cash payments for gas purchased to settle these contracts on a monthly basis, net of the contract settlement reported in financing activities discussed below. As discussed previously, we have begun the process to terminate our obligation under three long-term gas contracts and anticipate terminating a fourth. The remaining two contracts will have a negative impact on future cash flows until 2008.

We will continue to evaluate our options related to our Elwood tolling agreement. A settlement of this obligation could result in a one-time cash payment but would eliminate our future cash obligations of approximately $473.2 million.

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

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

Cash Flows provided from Investing Activities

Cash flows provided from investing activities in the six months ended June 30, 2004 and 2003 consist primarily of cash proceeds we received from the sale of our assets offset by cash used by our utilities and merchant businesses for capital expenditures. The $442.1 million increase in 2004 compared to 2003 stemmed primarily from the sale of our Canadian utility businesses, reduced merchant capital expenditures in 2004, as we completed the construction of a merchant plant in June 2003, and lower merchant investments in unconsolidated subsidiaries, partially offset by $504.0 million of cash restricted for Chubb on certain of our long-term gas contracts and additional utilities capital expenditures.

Cash Flows used for Financing Activities

Cash flows used for financing activities in the six months ended June 30, 2004 and 2003 consist primarily of cash we paid to retire our long-term debt obligations and our payments under our long-term gas contracts. The increase in cash used for financing activities in 2004 as compared to 2003 stems primarily from $250.0 million of funds on deposit posted with the trustee for our 7.00% senior notes due July 15, 2004, and from the 2004 retirement of the Midlands Electricity acquisition note and debt related to our Canadian operations, as compared to the debt we retired in 2003 associated with our investment in Australia and the construction of our merchant power plants.

We also have material cash outflows related to our long-term gas contracts in our financing activities. These cash outflows represent the settlement of our recorded liability based on the units of revenue method of accounting. The combined operating cash outflow and financing cash outflow related to long-term gas contracts represents the total cost to purchase gas to service these contracts.

Collateral Positions

As of June 30, 2004, we had posted collateral for the following in the form of cash or cash collateralized letters of credit:

In millions

Trustee deposit on senior notes due July 15, 2004	$	258.8
Trading positions		173.2
Utility cash collateral requirements		48.6
Tolling agreements		37.8
Insurance and other		33.2

Total Funds on Deposit	$	551.6

On June 30, 2004, we irrevocably deposited $258.8 million, which included accrued interest, with the trustee for the 7.00% series of senior notes due July 15, 2004 in order to economically defease this obligation under the terms of our $430 million three-year secured credit facility. This deposit was classified as funds on deposit in the accompanying Consolidated Balance Sheet. The senior notes were retired on July 15, 2004.

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

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

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

On April 8, 2004, Standard & Poor's downgraded our senior unsecured debt rating from B to B-. On June 23, 2004, Standard & Poor's further downgraded our senior unsecured debt rating to CCC+. These actions had no impact on our liquidity or collateral position.

FINANCIAL REVIEW

Except where noted, the following discussion refers to the consolidated entity, Aquila, Inc. Our businesses are structured as follows: (a) Domestic Utilities, our electric and gas utilities in seven mid-continent states, and (b) Merchant Services, our 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 all periods presented. All other operations are included in Corporate and Other, including costs that are not allocated to our operating businesses; our investment in Everest Connections; and our former investments in Australia and the United Kingdom. Our former Canadian utility businesses are also classified in discontinued operations.

This review of performance is organized by business segment, reflecting the way we manage our business. Each business group leader is responsible for operating results down to earnings before interest and taxes (EBIT). We use EBIT as a performance measure as it captures the income and expenses within the management control of our segment business leaders. Corporate

management is responsible for making all financing decisions. Therefore, each segment discussion focuses on the factors affecting EBIT, while interest expense and income taxes are separately discussed at the corporate level.

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

		Three Months Ended June 30,						Six Months Ended June 30,
In millions			2004			2003			2004			2003

Earnings (Loss) Before Interest and Taxes:
	Domestic Utilities	$	9.6		$	10.9		$	73.0		$	85.9
	Merchant Services		(39.6	)		(126.7	)		(165.9	)		(234.6	)
	Corporate and Other		(12.9	)		37.0			(13.7	)		35.7

Total EBIT			(42.9	)		(78.8	)		(106.6	)		(113.0	)
Interest expense			63.5			71.0			127.8			131.8
Income tax benefit			(39.3	)		(44.5	)		(82.7	)		(75.1	)

Loss from continuing operations			(67.1	)		(105.3	)		(151.7	)		(169.7	)
Earnings from discontinued operations, net of tax			23.8			24.7			56.6			37.2

Net loss		$	(43.3	)	$	(80.6	)	$	(95.1	)	$	(132.5	)

Key Factors Impacting Continuing Operating Results

For the six months ended June 30, 2004, our total loss before interest and taxes decreased compared to 2003. Key factors affecting 2004 results were as follows:

•: As a result of asset sales, we recorded net losses on sale of assets of $21.7 million in 2004 compared to losses of $100.8 million in 2003. These losses resulted from our decision to sell international and other non-core assets in order to return to operating primarily as a domestic electric and gas utility. See Note 3 to Consolidated Financial Statements for further discussion and detail of asset sales.
•: Discounting of our trading portfolio resulted in a non-cash loss of $27.2 million, primarily related to our long-term gas contracts.
•: The loss in 2003 included $25.6 million non-cash loss related to the sale of our capacity rights under certain long-term gas transportation agreements at substantially less than our future commitments.
•: Equity earnings from our investments in independent power plants and in Australian utility assets decreased by $59.0 million in 2004 compared to 2003, primarily due to the sale of these businesses in March 2004 and May and July 2003, respectively, and mark-to-market earnings recognized at the project level of certain independent power plants in 2003.
•: Domestic Utilities EBIT decreased $12.9 million primarily due to increased cost of natural gas used for fuel and higher purchased power cost for the electric utility and unfavorable weather for the gas utility.

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. The unaudited operating results of these operations are as follows:

		Three Months Ended June 30,			Six Months Ended June 30,

In millions		2004		2003	2004		2003

Sales		$42.7		$103.6	$131.0		$160.3
Cost of sales		6.2		14.1	25.1		32.1

Gross profit		36.5		89.5	105.9		128.2

Operating expenses:
	Operating expense	24.6		30.3	56.4		61.8
	Gain on sale of assets	(65.7	)	—	(74.1	)	—
	Depreciation and amortization expense	—		11.2	—		8.4

Total operating expenses		(41.1	)	41.5	(17.7	)	70.2

Other income		14.2		.8	2.0		3.9

Earnings before interest and taxes		91.8		48.8	125.6		61.9
Interest expense		5.6		7.2	14.6		11.5

Earnings before income taxes		86.2		41.6	111.0		50.4
Income tax expense		62.4		16.9	54.4		13.2

Earnings from discontinued operations		$23.8		$24.7	$56.6		$37.2

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit decreased $60.9 million, $7.9 million and $53.0 million, respectively, in 2004 compared to 2003. Sales, cost of sales, and gross profit for our consolidated independent power plants decreased $35.8 million, $5.2 million and $30.6 million, respectively, due to the sale of these plants in March 2004. Sales, cost of sales, and gross profit for our Canadian utility businesses decreased $25.1 million, $2.7 million and $22.4 million, respectively, primarily due to the sale of these businesses in May 2004.

Gain on Sale of Assets

Gain on sale of assets consisted of $65.7 million related to the sale of our Canadian utility businesses in May 2004.

Operating Expenses

Operating expenses decreased $5.7 million in 2004 compared to 2003, primarily due to the sale of our consolidated independent power plants in March 2004 and our Canadian utility businesses in May 2004.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $11.2 million in 2004 compared to 2003. This decrease is primarily related to the elimination of depreciation associated with our Canadian utility operation due to its classification as held for sale in accordance with SFAS 144. SFAS 144 requires that depreciation expense no longer be recorded for those assets classified for accounting purposes as held for sale.

Other Income

Other income increased $13.4 million in 2004 compared to 2003, primarily due to the $12.6 million favorable market value adjustment on a foreign currency forward contract intended to protect us from unfavorable currency movements on the Canadian sale proceeds and increased interest income on invested cash.

Income Tax Expense

The income tax expense for 2004 increased $45.5 million from 2003. The income tax expense on pretax income from discontinued operations was primarily the result of taxes associated with the gain on the sale of our Canadian utility businesses. The effective tax rate on the pretax gain on the 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. In addition, the difference between book and tax basis relating to the elimination of depreciation under SFAS 144 also contributed to the higher tax provision on the pretax gain.

Year-to-Date

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit decreased $29.3 million, $7.0 million and $22.3 million, respectively, in 2004 compared to 2003. Sales and gross profit for our Canadian network business increased $18.2 million and $18.7 million, respectively, primarily due to the decision in March 2003 by the Alberta Energy Utilities Board (AEUB) to reduce our 2002 and 2003 customer billing rates. The AEUB decision resulted in an adjustment to reduce first quarter 2003 sales and gross profit by approximately $33.7 million. The increases in Canadian sales and cost of sales were offset by decreases in sales, cost of sales and gross profit of $27.1 million, $2.3 million and $24.8 million, respectively, resulting from the sale of these businesses in May 2004. Sales, cost of sales and gross profit for Lake Cogen and Onondaga were lower in 2004 by $47.3 million, $6.4 million and $40.9 million, respectively, due to the sale of these businesses in early March 2004 and a price dispute settlement that increased Lake Cogen's 2003 sales by $5.7 million.

Gain on Sale of Assets

Gain on sale of assets consisted of $8.4 million related to the sale of our consolidated independent power plants, Lake Cogen and Onondaga in March 2004 and $65.7 million related to the sale of our Canadian utility businesses in May 2004.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $8.4 million in 2004 compared to 2003. The elimination of depreciation from our Canadian utility business, due to its classification as held for sale in accordance with SFAS 144, decreased depreciation expense $21.4 million. SFAS 144 requires that depreciation expense no longer be recorded for those assets classified for accounting purposes as held for sale. The decrease was offset by the $15.2 million adjustment in the first quarter of 2003 due to the decision by the AEUB to reduce the depreciation rates on most of our distribution assets in Alberta.

Income Tax Expense

The income tax expense for 2004 increased $41.2 million from 2003. The income tax expense on pretax income from discontinued operations was primarily the result of taxes associated with the gain on the sale of our Canadian utility businesses. 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. In addition, the difference between book and tax basis relating to the elimination of depreciation under SFAS 144 also contributed to the higher tax provision on the pretax gain.

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

Domestic Utilities

The table below summarizes the operations of our Domestic Utilities.

		Three Months Ended June 30,			Six Months Ended June 30,

Dollars in millions		2004		2003	2004	2003

Sales:
	Electricity—regulated	$181.9		$158.7	$341.9	$309.2
	Natural gas—regulated	155.7		156.9	594.2	577.5
	Natural gas—non-regulated	2.7		6.4	3.3	11.1
	Other—non-regulated	6.7		7.5	13.5	14.7

Total sales		347.0		329.5	952.9	912.5

Cost of sales:
	Electricity—regulated	98.3		80.3	180.1	152.0
	Natural gas—regulated	101.4		102.0	428.9	407.9
	Natural gas—non-regulated	2.5		4.9	2.5	8.7
	Other—non-regulated	2.6		2.4	6.2	5.8

Total cost of sales		204.8		189.6	617.7	574.4

Gross profit		142.2		139.9	335.2	338.1

Operating expenses:
	Operating expense	101.3		98.9	198.8	191.5
	Gain on sale of assets	—		—	—	(2.2	)
	Depreciation and amortization expense	30.8		30.6	63.7	62.9

Total operating expenses		132.1		129.5	262.5	252.2

Other income (expense)		(.5	)	.5	.3	—

Earnings before interest and taxes		$ 9.6		$ 10.9	$ 73.0	$ 85.9

Electric sales and transportation volumes (GWh)		3,123.0		2,679.7	6,353.5	5,507.2
Gas sales and transportation volumes (Bcf)		41.2		43.1	123.3	131.5
Electric customers at end of period					448,887	442,152
Gas customers at end of period					892,519	883,729

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit for the Domestic Utilities business increased $17.5 million, $15.2 million, and $2.3 million, respectively, in 2004 compared to 2003. These changes were primarily due to the following factors:

•: Regulated electric utility sales, cost of sales and gross profit increased $23.2 million, $18.0 million and $5.2 million, respectively, in 2004 compared to 2003. Sales and gross profit increased by $11.1 million due to rate increases in Colorado effective in July 2003 and in Missouri effective in April 2004, plus $1.3 million of additional margin from an increase in customers. These were offset by a $9.5 million increase in cost of sales due to the higher cost of fuel and purchased power, net of offsetting derivative hedge positions in 2003. Favorable weather and other items also increased gross profit by $2.3 million.

•: Sales and cost of sales for our regulated gas utilities decreased $1.2 million and $.6 million, respectively, in 2004 compared to 2003, for a net decrease in gross profit of $.6 million. Regulated gas margins decreased $2.4 million due to unfavorable weather and lower volumes in 2004 compared to 2003. The overall decline in gas margins due to volume and weather was partially offset by $1.9 million in rate increases in Nebraska.
•: Non-regulated gas sales, cost of sales and gross profit decreased $3.7 million, $2.4 million and $1.3 million, respectively, in 2004 compared to 2003, primarily as the result of the sale of certain non-regulated gas pipeline and gathering operations in August 2003.

Year-to-Date

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for the Domestic Utilities business increased $40.4 million and $43.3 million, respectively, and gross profit decreased $2.9 million in 2004 compared to 2003. These changes were primarily due to the following factors:

•: Regulated electric utility sales and cost of sales increased $32.7 million and $28.1 million, respectively, in 2004 compared to 2003, for a net increase in gross profit of $4.6 million. Sales and gross profit increased by $15.5 million due to rate increases in Colorado effective in July 2003 and in Missouri effective in April 2004, plus $2.5 million of additional margin from an increase in customers. These were offset by a $14.8 million increase in cost of sales due to the higher cost of fuel and purchased power, net of offsetting derivative hedge positions in 2003. Favorable weather and other items also increased gross profit by $1.5 million.
•: Sales and cost of sales for our regulated gas utilities increased $16.7 million and $21.0 million, respectively, in 2004 compared to 2003, for a net decrease in gross profit of $4.3 million. Sales and cost of sales increased due to a 14% increase in natural gas prices. However, because gas purchase costs for our gas utility operations are passed through to our customers, the change in gas prices did not have a corresponding impact on gross profit. Regulated gas margins decreased $8.6 million due to unfavorable weather and lower volumes in 2004 compared to 2003. The overall decline in gas margins due to volume and weather was partially offset by $3.3 million in rate increases in Nebraska.
•: Non-regulated gas sales, cost of sales and gross profit decreased $7.8 million, $6.2 million and $1.6 million, respectively, in 2004 compared to 2003, primarily as the result of the sale of certain non-regulated gas pipeline and gathering operations in August 2003.

Operating Expense

Operating expenses increased $7.3 million in 2004 compared to 2003 as a result of a number of cost increases. The most significant of these were insurance and materials costs, which increased $4.1 million during 2004 compared to 2003.

Regulatory Matters

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

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

Missouri	Electric	7/2003	4/2004	$	80.9	$37.5
Missouri	Gas	8/2003	4/2004		6.4	3.4
Colorado	Electric	12/2003	Pending		11.4	Pending
Kansas	Electric	6/2004	Pending		19.2	Pending

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

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

In June 2004, we filed for a rate increase totaling $19.2 million for our electric territories in Kansas. This application is primarily to recover infrastructure improvements and increased maintenance and operating costs. We expect hearings to be concluded in December 2004 with rates effective in February 2005. We also filed a request for a $10.0 million interim rate increase. The Kansas Commission has scheduled a hearing on this request for August 18, 2004.

On August 4, 2004, we filed a request with the Missouri Commission for an Accounting Authority Order (AAO) requesting clarification of the IEC accounting treatment for the two-year period ending April 2006. We also requested that any significant amounts under-collected during the period be considered for recovery in our next rate case.

Earnings Trend

The recent settlement of our electric and gas rate cases in Missouri is expected to increase annual sales approximately $37.5 million and $3.4 million, respectively. However, we are experiencing costs of natural gas used for fuel and purchased power that are in excess of the level of costs recovered under the IEC discussed above. Absent a favorable ruling by the Missouri Commission on the AAO and subsequent allowance for recovery in our next rate case, 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 the Aries power plant, which provides up to 500 MW of power, expires in June 2005. We are currently evaluating a number of alternatives to replace this power, including construction of a peaking generation plant and long-term power purchase contracts. To the extent the cost of this replacement power exceeds the cost of power under the Aries agreement, and until such cost is recovered through the IEC or subsequent rate cases, our earnings could be adversely affected.

Merchant Services

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

			Three Months Ended June 30,						Six Months Ended June 30,

In millions			2004			2003			2004			2003

Sales		$	(21.2	)	$	28.8		$	(82.8	)	$	(39.1	)
Cost of sales			14.4			27.1			30.7			53.1

Gross profit (loss)			(35.6	)		1.7			(113.5	)		(92.2	)

Operating expenses:
	Operating expense		9.8			32.1			19.0			46.7
	Restructuring charges		.4			18.7			.6			24.0
	Net loss (gain) on sale of assets		(9.1	)		100.4			26.8			100.4
	Depreciation and amortization expense		4.4			6.1			8.8			20.7

Total operating expenses			5.5			157.3			55.2			191.8

Other income (expense):
	Equity in earnings of investments		—			27.7			1.9			46.9
	Other income		1.5			1.2			.9			2.5

Loss before interest and taxes		$	(39.6	)	$	(126.7	)	$	(165.9	)	$	(234.6	)

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

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Gross loss for our Merchant Services operations for the three months ended June 30, 2004 was $35.6 million, primarily due to the following factors:

•: Approximately $6.1 million was a non-cash loss related to the discounting of our trading portfolio, primarily driven by the impact of contraction in our credit spreads on the

discounting of price risk management liabilities relating to 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.

As of June 30, 2004, we have recorded a cumulative $41.7 million of net mark-to-market gains related to discounting of our trading portfolio. The vast majority of these gains relate to our long-term gas contracts. These gains will be reversed in later periods as contracts settle, our credit rating improves and/or as gas prices decline. We expect to reverse approximately $41.9 million of mark-to-market gains in the third quarter of 2004 related to our settlement with three of our long-term gas contract and hedge counterparties. See Note 10 to the Consolidated Financial Statements for further details.

•: In the second quarter of 2004, we incurred margin losses of $10.3 million resulting from the difference between revenue recognized on our long-term gas contracts and the net cost of gas delivered under these contracts. See "Earnings Trend and Impact of Changing Business Environment" on page 40 for further detail on future impacts of terminating our long-term gas 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 second quarter of 2004, we recorded net capacity expenses of $8.9 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. Capacity payments were lower in the second quarter of 2004 compared to 2003 because we terminated our Acadia capacity contract in the second quarter of 2003 and our Aries capacity contract in the first quarter of 2004.
•: Our remaining second quarter gross loss mainly stems from mark-to-market losses and unfavorable settlements of approximately $12.5 million, related to a long-term power supply transaction with New York State Electric and Gas Corp. (NYSEG) and our remaining stream flow transaction, which expires in 2006. In May 2004, we settled our obligation under the long-term power supply contract with NYSEG by making a cash payment of $37.7 million to a third party who assumed the contract.

Gross profit for our Merchant Services operations for the three months ended June 30, 2003 was $1.7 million, primarily due to the following factors:

•: Approximately $50.4 million was non-cash earnings related to the discounting of our trading portfolios, primarily driven by long-term gas contracts. During the second quarter of 2003, average gas prices rose over the life of our price risk management assets and liabilities by $.63 per MMBtu.
•: In the second quarter of 2003, we incurred margin losses of $10.1 million, resulting from the difference between revenue recognized on our long-term gas contracts and 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 second quarter of 2003, we recorded net capacity expenses of $16.2 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.
•: Additionally, in the second quarter of 2003, we incurred approximately $24.1 million of unfavorable settlements of our highly structured stream flow and long-term power supply transactions and our continued wind-down of our European trading operations.

Operating Expense

Operating expense decreased $22.3 million primarily due to establishment of a reserve in the second quarter of 2003 related to our ultimate settlement with the Commodity Futures Trading Commission (CFTC) in January 2004 and reduced staffing needed to manage our remaining trading positions and non-regulated power generation assets.

Restructuring Charges

Restructuring charges decreased $18.3 million primarily due to a charge of $17.8 million taken in the second quarter of 2003 for the termination of our remaining interest rate swaps associated with the construction financings for our Clay County and Piatt County power plants. As debt related to these facilities was retired earlier than anticipated, the notional amount of our swaps exceeded our outstanding debt. We therefore reduced our position and realized the loss associated with the cancelled portion of the swaps.

Net Loss (Gain) on Sale of Assets

In June 2004, we received a distribution of approximately $24.3 million from our non-voting limited partnership interest in BAF Energy, a California limited partnership that sold its 120 MW natural gas-fired combined cycle cogeneration facility located in King City, California. We recorded a pretax gain of $9.1 million on this distribution.

In May 2003, we terminated our 20-year tolling contract for the Acadia power plant and made a termination payment of $105.5 million. Partially offsetting the termination payment was a $5.1 million gain related to the contract termination and sale of our remaining turbines that we had previously written down to estimated fair value in 2002.

Equity in Earnings of Investments

Equity in earnings of investments decreased $27.7 million mainly due to the sale of our independent power plant investments in the first quarter of 2004.

Year-to-Date

Sales, Cost of Sales and Gross Profit

Gross loss for our Merchant Services operations for the six months ended June 30, 2004 was $113.5 million, primarily due to the following factors:

•: Approximately $27.2 million was a non-cash loss related to the discounting of our trading portfolio, primarily driven by our long-term gas contracts. During the first six months of 2004, average gas prices increased over the life of our price risk management assets and liabilities by $.35 per 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 2004, the benchmark indexes we use to determine the discount rate appropriate for our credit standing decreased by approximately 380 basis points, resulting in the partial reversal of the previous earnings and asset recorded.

•: In the six months of 2004, we incurred margin losses of $24.4 million resulting from the difference between revenue recognized on our long-term gas contracts and 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 six months of 2004, we recorded net capacity expenses of $19.7 million. The cost to purchase natural gas to fuel these power plants generally exceeded the value of the power that could be generated. Accordingly, we did not generate material revenues. Capacity payments were lower in the six months of 2004 compared to 2003 because we terminated our Acadia capacity contract in the second quarter of 2003 and our Aries capacity contract in the first quarter of 2004.
•: We incurred approximately $5.0 million of costs to exit natural gas hedge positions related to the Onondaga swap derivative sold in connection with the sale of our independent power plants, cash flow hedge option premium expirations and the exit of other hedges related to previous contracts.
•: Our remaining gross loss for the six months mainly stems from mark-to-market losses and unfavorable settlements of approximately $28.2 million, related to a long-term power supply transaction with NYSEG and our remaining stream flow transaction which expires in 2006. In May 2004, we settled our obligation under the long-term power supply contract with NYSEG by making a cash payment of $37.7 million to a third party who assumed this contract.

Gross loss for our Merchant Services operations for the six months ended June 30, 2003 was $92.2 million, primarily due to the following factors:

•: Partially offsetting the losses discussed below was approximately $74.2 million was non-cash earnings related to the discounting of our trading portfolios, primarily driven by long-term gas contracts. During the first six months of 2003, average gas prices rose over the life of our price risk management assets and liabilities by $.90 per MMBtu.
•: In the first six months of 2003, we incurred margin losses of $22.8 million, resulting from the difference between revenue recognized on our long-term gas contracts and 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 six months of 2003, we recorded net capacity expenses of $37.3 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.
•: In the first six months of 2003, we incurred approximately $35.8 million of unfavorable settlements of our highly structured stream flow and long-term power supply transactions and our continued wind-down of our European trading operations.
•: We recorded a $25.6 million non-cash loss related to the sale of our capacity under certain long-term gas transportation agreements at substantially less than our future commitments. Although the loss was recognized for accounting purposes, the cash associated with the loss will be paid out over the term of the contracts.
•: We recognized approximately $32.8 million of net mark-to-market losses on natural gas hedge positions related to the Onondaga swap derivative, cash flow hedge option premium expirations and other hedges related to previous contracts.

Operating Expense

Operating expense decreased $27.7 million primarily due to establishment of a reserve in the second quarter of 2003 related to our ultimate settlement with the CFTC in January 2004 and reduced staffing needed to manage our remaining trading positions and merchant generating assets.

Net Loss on Sale of Assets

Net loss on sale of assets in 2004 consists of a $47.0 million loss on the transfer of our equity interest in the Aries power project and termination of our tolling obligation, offset by a $6.1 million gain related to the sale of our equity method investments in independent power plants, a $5.0 million gain on the sale of our Marchwood development project in the United Kingdom and a $9.1 million gain on a distribution from BAF Energy.

Depreciation and amortization expense

Depreciation and amortization expense decreased by $11.9 million primarily due to the elimination of the amortization of premiums associated with our equity method investments in independent power plants, resulting from the impairment of our investments in these plants in September 2003.

Equity in Earnings of Investments

Equity in earnings of investments decreased $45.0 million mainly due to our sale of our independent power plant investments in the first quarter of 2004.

Earnings Trend and Impact of Changing Business Environment

We began winding down and terminating our trading positions with various counterparties during the second quarter of 2002. However, it will take a number of years to complete the wind-down while we continue to deliver gas under our remaining long-term gas contracts after the terminations discussed in Note 10 to the Consolidated Financial Statements. Because most of our trading positions are hedged, we should experience limited fluctuation in earnings and losses other than the impacts from our credit or counterparty credit, the discounting or accretion of interest, the termination or liquidation of additional trading contracts, or the changes in market valuations and settlements of our remaining highly customized stream flow contract which expires in 2006. There may be earnings volatility associated with this stream flow 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 $23.5 million of potential variability related to this contract.

The merchant energy sector has been negatively impacted by new generation capacity that became operational in 2002 and by the continued construction of additional power plants. This increase in supply has placed downward pressure on power prices and subsequently the value of unsold merchant generation capacity. In addition, our merchant power plants use natural gas as a fuel source. Because of the significant increase in price of natural gas, our merchant power plants are at a competitive disadvantage to power plants relying on other fuel sources. As a result of the

above factors, we expect our Merchant Services unit to generate significant losses for the foreseeable future.

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

Corporate and Other

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

			Three Months Ended June 30,					Six Months Ended June 30,

In millions			2004			2003		2004			2003

Sales		$	9.5		$	9.1	$	18.4		$	16.8
Cost of sales			3.1			2.9		5.8			5.3

Gross profit			6.4			6.2		12.6			11.5

Operating expenses:
	Operating expense		22.7			14.4		33.8			43.5
	Restructuring charges		.2			2.1		.3			3.1
	Net loss (gain) on sale of assets		(1.3	)		2.6		(5.1	)		2.6
	Depreciation and amortization expense		1.2			.8		2.3			1.6

Total operating expenses			22.8			19.9		31.3			50.8

Other income (expense):
	Equity in earnings of investments		—			8.9		.2			14.2
	Other income		3.5			41.8		4.8			60.8

Earnings (loss) before interest and taxes		$	(12.9	)	$	37.0	$	(13.7	)	$	35.7

Quarter-to-Quarter

Operating Expense

Operating expense increased $8.3 million due to an $8.4 increase in costs associated with the settlement of the appraisal rights shareholder lawsuit and $4.4 million of costs associated with exiting our international networks investments. These costs were partially offset by a $7.2 million decrease in restructuring consulting fees and insurance and other costs incurred in 2003. The second quarter of 2003 also included the allocation of $5.0 million of provisions for claims and other regulatory reviews to Merchant Services. In addition, the sale of our international network investments decreased operating expenses $3.7 million.

Restructuring Charges

Restructuring charges decreased $1.9 million in the second quarter of 2004 compared to 2003. This was primarily due to $1.1 million of severance and other related costs that were paid in 2003 in connection with the restructuring of Everest Connections, and $.9 million of executive severance that was paid in 2003 in connection with the separation agreement of our former Chief Risk Officer.

Net Loss (Gain) on Sale of Assets

The $1.3 million gain in 2004 is related to the fair value adjustment of Everest Connections target-based put rights. The $2.6 million loss on sale of assets in 2003 was related to the sale of our interest in AlintaGas in May 2003.

Equity in Earnings of Investments

Equity in earnings of investments decreased $8.9 million in 2004 compared to 2003 due to the sale of our investments in Australia in May and July 2003.

Other Income

Other income decreased $38.3 million mainly due to $35.0 million of foreign currency gains recognized in 2003 resulting from favorable movements in the Australian and New Zealand dollar against the U.S. dollar.

Year-to-Date

Operating Expense

Operating expense decreased $9.7 million due to an $8.4 million increase in costs associated with the settlement of the appraisal rights shareholder lawsuit and $4.4 million of costs associated with exiting our international networks investments. These costs were more than offset by a $14.3 million decrease in restructuring consulting fees and insurance and other costs from 2003. In addition, the restructuring of Everest Connections decreased operating expenses $2.1 million and the sale of our international network investments decreased operating expenses $5.6 million.

Restructuring Charges

Restructuring charges decreased $2.8 million in 2004 compared to 2003. This was primarily due to $2.1 million of severance and other related costs that were paid in 2003 in connection with the restructuring of Everest Connections, and $.9 million of executive severance that was paid in 2003 in connection with the separation agreement of our former Chief Risk Officer.

Net Loss (Gain) on Sale of Assets

The gain on sale of assets of $5.1 million was recorded primarily in connection with the sale of our interest in Midlands Electricity in January 2004. This investment was written down to estimated fair value in 2002 and again in September 2003. However, due to strengthening of the British pound exchange rate in the fourth quarter of 2003 and in early 2004, we realized a $3.3 million gain on the closing of the sale. The $2.6 million loss on sale of assets in 2003 was related to the sale of our interest in AlintaGas in May 2003.

Equity in Earnings of Investments

Equity in earnings of investments decreased $14.0 million in 2004 compared to 2003 due to the sale of our investments in Australia in May and July 2003.

Other Income

Other income decreased $56.0 million mainly due to $49.7 million of foreign currency gains recognized in 2003 resulting from favorable movements in the Australian and New Zealand dollar against the U.S. dollar. In 2004, we realized a $1.9 million gain on the early redemption of the

note payable issued in connection with our acquisition of Midlands which was offset in part by $1.8 million in fees paid to lenders in connection with the waiver and amendment of financial covenants under our three-year secured credit facility.

Interest Expense and Income Tax Benefit

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

		Three Months Ended June 30,						Six Months Ended June 30,

In millions		2004			2003			2004			2003

Interest expense	$	63.5		$	71.0		$	127.8		$	131.8

Income tax benefit	$	(39.3	)	$	(44.5	)	$	(82.7	)	$	(75.1	)

Quarter-to-Quarter

Interest Expense

Interest expense decreased $7.5 million in 2004 compared to 2003. The decrease was primarily the result of reductions in interest expense related to the repayment of debt associated with our investments in Midlands Electricity in the first quarter of 2004 and our prior 364-day secured credit facility in the second and third quarters of 2003.

Income Tax Benefit

The income tax benefit decreased $5.2 million in 2004 compared to 2003, primarily as a result of lower losses before income taxes in 2004 compared to 2003, partially offset due to tax benefits not being recognized on certain 2003 losses as a result of valuation allowances provided.

Year-to-Date

Interest Expense

Interest expense decreased $4.0 million in 2004 compared to 2003. The decrease was primarily the result of reductions in interest expense related to the repayment of debt associated with our investments in Australia, Midlands Electricity, our merchant power plants, our prior revolving credit facility and our former 364-day secured credit facility. These decreases were partially offset by the borrowing in April 2003 of $430.0 million under our three-year secured facility, resulting in $8.9 million of additional interest expense and amortization of debt issue costs of $1.5 million.

Income Tax Benefit

The income tax benefit increased $7.6 million in 2004 compared to 2003, as lower losses before income taxes in 2004 compared to 2003 were more than offset by tax benefits not being recognized on certain 2003 losses as a result of valuation allowances provided.

As of December 31, 2003, we had approximately $81.4 million of deferred tax benefits for federal and state net operating losses. As a result of additional losses in 2004, these deferred tax benefits increased to approximately $117.4 million. These losses will be available to offset future taxable income for up to 20 years.

Significant Balance Sheet Movements

Total assets decreased by $1,075.1 million since December 31, 2003. This decrease is primarily due to the following:

•: Cash increased $36.1 million. See our Consolidated Statement of Cash Flows for analysis of this increase.
•: Restricted cash increased $525.9 million primarily due to our requirement to escrow $504 million to Chubb in accordance with the court's preliminary injunction related to surety bonds supporting our long-term gas contracts and additional cash restricted for customer funds on deposit of $22.1 million.
•: Funds on deposit increased $169.1 million primarily due to the deposit we made with the trustee of our $250.0 million senior note obligation due July 15, 2004. This increase was partially offset by the return of margin deposits paid to counterparties related to the seasonal decrease in gas purchases and Calpine's return of collateral in connection with the assignment of our interest in the Aries power project.
•: Accounts receivable, net decreased $182.3 million primarily reflecting lower volumes of electricity delivered due to our exit from wholesale energy trading, and seasonal declines in regulated gas customer deliveries.
•: Inventories and supplies decreased $32.9 million primarily due to the seasonal withdrawal of natural gas in storage by our Domestic Utilities businesses for deliveries to customers.
•: Price risk management assets increased $73.6 million primarily due to an increase in natural gas prices since December 31, 2003.
•: Investments in unconsolidated subsidiaries decreased by $309.8 million primarily due to the sale of our investments in Midlands Electricity and our independent power plants.
•: Deferred charges decreased $69.6 million primarily related to the elimination of deferred income tax regulatory assets in connection with the sale of our Canadian utility businesses.
•: Current and non-current assets of discontinued operations decreased $1,282.4 million primarily due to the sale of our Canadian utility businesses and our consolidated independent power plants.

Total liabilities decreased by $937.8 million and common shareholders' equity decreased by $137.3 million since December 31, 2003. These changes are primarily attributable to the following:

•: Accounts payable decreased by $160.1 million primarily reflecting lower volumes of electricity delivered due to our exit from wholesale energy trading and seasonal declines in regulated natural gas purchases.
•: Price risk management liabilities increased $87.2 million primarily due to an increase in natural gas prices since December 31, 2003.
•: Long-term debt, including current maturities of long-term debt, decreased by $77.4 million primarily due to the early retirement of the Midlands acquisition note payable.
•: Deferred income taxes decreased $106.0 million primarily due to deferred tax benefits on 2004 net operating losses and the sale of our investments in Midlands Electricity and Canadian utility businesses.

•: Deferred credits decreased $90.5 million primarily related to the elimination of deferred income tax regulatory liabilities in connection with the sale of our Canadian utility businesses.
•: Common shareholders' equity decreased $137.3 million primarily as a result of the year-to-date net loss for 2004 and other comprehensive losses due to the sale of our investment in Midlands Electricity and our Canadian utility businesses.

Forward-Looking Information

This report contains forward-looking information, including statements that (i) we believe our liquidity will be sufficient in 2004, (ii) we will attempt to improve operating cash flows by improving our efficiency, increasing utility rates and cost recovery, retiring debt and restructuring our merchant obligations, (iii) we may attempt to raise capital in the public markets and (iv) we expect to settle certain of our long-term gas contracts. The words "may," "will," "should," "expect," "anticipate," "intend," "plan," "believe," "seek," "estimate," or the negative of these terms or similar expressions identify further forward-looking statements. Similar statements that identify our objectives, plans and goals are forward-looking statements.

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

•: Regulatory agencies may refuse to approve some or all of our requests for rate increases.
•: We currently do not recover a significant portion of the fuel and purchased power costs we incur to provide utility services in our largest jurisdiction. Although we have sought an accounting order that would permit us to seek recovery of these costs in the future, the public service commission may not approve our request.
•: We require regulatory approval from a number of jurisdictions to sell our securities. Although we have applied for approval, the regulatory agencies may deny our applications.
•: We may be unable to sell securities at prices sufficient to justify the sale or in quantities that will provide sufficient proceeds to meet our capital needs.
•: Market prices for our long-term debt have increased, which limits our ability to repurchase the debt or obtain significant benefits from its early retirement.
•: Our long-term gas contracts represent favorable contracts to the counterparties and they may be unwilling to voluntarily restructure or settle the contracts or might seek legal or other remedies to preclude unilateral termination efforts initiated by us.

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 2004 are summarized below:

In millions

Fair value at December 31, 2003	$	130.0
Change in fair value during the period		(70.6	)
Contracts realized or cash settled		57.0

Fair value at June 30, 2004	$	116.4

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

In millions

2004	$	24.0
2005		7.8
2006		24.5
2007		28.0
Thereafter		32.1

Total fair value	$	116.4

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

Chubb Settlement

Appraisal Rights Litigation

EPCOR Litigation

On August 18, 2003, EPCOR filed a lawsuit against us, Aquila Canada ULC (formerly Aquila Networks Canada Limited), and FortisAlberta Ltd. (formerly Aquila Networks Canada (Alberta) Ltd.) in the Court of Queen's Bench of Alberta. EPCOR alleged that we breached our agreements with EPCOR in which the Alberta utility agreed to provide to EPCOR certain customer and billing information in connection with EPCOR's provision of retail service to the utility's customers. EPCOR claimed C$77 million for breach of the agreements and for negligence, including damage to its reputation, and C$6 million in aggravated and punitive damages. This litigation was assumed by the purchaser of our Alberta utility upon the closing of the sale transaction, and an affiliate of the purchaser has agreed to indemnify us and Aquila Canada ULC against any damages or liabilities arising from this litigation.

California and Washington Litigation

the City of Tacoma, Washington alleging we were part of a conspiracy to drive up the price of electricity. These cases were only recently filed and we are in the process evaluating the claims.

Item 4. Submission of Matters to a Vote of Securities Holders

We held our annual meeting of shareholders on May 5, 2004. At the meeting, the following matter was voted on by the shareholders:

1. Election of Directors:

Director	Term	Votes For	Votes Withheld

John R. Baker	1 year	134,843,974	37,287,271
Irvine O. Hockaday, Jr.	3 years	166,576,485	5,554,760
Heidi E. Hutter	3 years	163,784,456	8,346,789
Dr. Stanley O. Ikenberry	3 years	164,174,642	7,956,603

Following the election, our Board of Directors consisted of Richard C. Green (Chairman); John R. Baker; Herman Cain; Dr. Michael M. Crow; Irvine O. Hockaday, Jr.; Heidi E. Hutter; Dr. Stanley O. Ikenberry; and Gerald L. Shaheen.

Item 5. Other Information

Patrick J. Lynch, former Senior Vice President and Chief Financial Officer of Texaco, Inc., was appointed to our Board of Directors for a term of office until the 2005 annual election of directors by shareholders. Patrick will also serve on the Audit Committee of our Board of Directors.

Item 6. Exhibits and Reports on Form 8-K

(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
10.1		Severance Compensation Agreement (change in control agreement) dated as of July 10, 2004, by and between Aquila, Inc. and Rick J. Dobson.

(b) Reports on Form 8-K

We filed or furnished Current Reports on Form 8-K to the Securities and Exchange Commission during the quarter ended June 30, 2004, as follows:

Date Filed	Item No.

May 5, 2004	Item 7—	Press release dated May 5, 2004.
	Item 12—	Announcement of net loss for the first quarter ended March 31, 2004.
June 10, 2004	Item 2—	Reported the sale of Canadian utility businesses on May 31, 2004.

	Item 7—	Pro forma financial statements reflecting the sale will be filed within 60 days.
		Share purchase agreements relating to the sale of Canadian utility businesses.
June 10, 2004	Item 7—	Letter to shareholders of Aquila, Inc. dated June 8, 2004.
	Item 9—	Letter to shareholders of Aquila, Inc. updating them on recent developments.
June 14, 2004	Item 5—	The United States District Court for the Western District of Missouri, Western Division, entered a temporary order restraining Aquila, Inc. and Aquila Merchant Services, Inc. from using the proceeds of recent asset sales for any purpose.
	Item 7—	Order of the United States District Court for the Western District of Missouri, Western Division.
June 25, 2004	Item 5—	On June 24, 2004, the United States District Court of the Western District of Missouri, Western Division entered a preliminary injunction ordering Aquila to place the sum of $504 million in an escrow account under the supervision of the Court, pending the Court's final hearing on a request by Federal Insurance Company and Pacific Indemnity Company (Chubb) for a permanent injunction and specific performance under indemnity agreements between Aquila and Chubb.
	Item 7—	Order of the United States District Court for the Western District of Missouri, Western Division.

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:		August 4, 2004