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 September 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 October 28, 2004
Common Stock, $1 par value		241,719,269

Part I—Financial Information

Item 1. Financial Statements

Information regarding the consolidated financial statements is on pages 3 through 27.

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 28 through 48.

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 49 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 50.

Part II—Other Information

Item 1. Legal Proceedings

Information regarding legal proceedings is on page 51.

Item 2. Changes in Securities and Use of Proceeds

Not applicable.

Item 3. Defaults Upon Senior Securities

Not applicable.

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

Not applicable.

Item 5. Other Information

Not applicable.

Item 6. Exhibits and Reports on Form 8-K

Exhibits are on page 52.

Part I. Financial Information

Item 1. Financial Statements

Aquila, Inc.
Consolidated Statements of Income—Unaudited

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

Sales:
	Electricity—regulated	$	239.6		$	235.3
	Natural gas—regulated		103.3			98.4
	Electricity—non-regulated		(1.0	)		30.1
	Natural gas—non-regulated		(27.5	)		(64.3	)
	Other—non-regulated		8.0			22.5

Total sales			322.4			322.0

Cost of sales:
	Electricity—regulated		110.2			112.6
	Natural gas—regulated		59.5			54.1
	Electricity—non-regulated		12.6			18.2
	Natural gas—non-regulated		1.7			2.7
	Other—non-regulated		6.9			5.7

Total cost of sales			190.9			193.3

Gross profit			131.5			128.7

Operating expenses:
	Operating expense		112.8			122.2
	Restructuring charges		—			.6
	Net loss on sale of assets and other charges		114.5			90.9
	Depreciation and amortization expense		37.5			38.6

Total operating expenses			264.8			252.3

Other income (expense):
	Equity in earnings of investments		—			(.1	)
	Other income, net		8.8			4.0

Total other income (expense)			8.8			3.9

Interest expense			71.6			75.1

Loss from continuing operations before income taxes			(196.1	)		(194.8	)
Income tax benefit			(79.6	)		(50.6	)

Loss from continuing operations			(116.5	)		(144.2	)
Earnings (loss) from discontinued operations, net of tax			.1			(25.7	)

Net loss		$	(116.4	)	$	(169.9	)

Basic and diluted earnings (loss) per common share:
	Continuing operations	$	(.44	)	$	(.74	)
	Discontinued operations		—			(.13	)

	Net loss	$	(.44	)	$	(.87	)

Dividends per common share		$	—		$	—

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Statements of Income—Unaudited

		Nine Months Ended September 30,
In millions, except per share amounts			2004			2003

Sales:
	Electricity—regulated	$	581.5		$	544.5
	Natural gas—regulated		697.5			675.9
	Electricity—non-regulated		5.1			(.5	)
	Natural gas—non-regulated		(80.1	)		(33.4	)
	Other—non-regulated		6.9			25.7

Total sales			1,210.9			1,212.2

Cost of sales:
	Electricity—regulated		290.3			264.6
	Natural gas—regulated		488.4			462.0
	Electricity—non-regulated		43.3			65.2
	Natural gas—non-regulated		4.2			17.5
	Other—non-regulated		18.9			16.8

Total cost of sales			845.1			826.1

Gross profit			365.8			386.1

Operating expenses:
	Operating expense		364.4			403.9
	Restructuring charges		.9			27.7
	Net loss on sale of assets and other charges		136.2			191.7
	Depreciation and amortization expense		112.3			123.8

Total operating expenses			613.8			747.1

Other income (expense):
	Equity in earnings of investments		2.1			61.0
	Other income, net		14.8			67.3

Total other income (expense)			16.9			128.3

Interest expense			199.4			206.9

Loss from continuing operations before income taxes			(430.5	)		(439.6	)
Income tax benefit			(162.3	)		(125.7	)

Loss from continuing operations			(268.2	)		(313.9	)
Earnings from discontinued operations, net of tax			56.7			11.5

Net loss		$	(211.5	)	$	(302.4	)

Basic and diluted earnings (loss) per common share:
	Continuing operations	$	(1.22	)	$	(1.61	)
	Discontinued operations		.26			.06

	Net loss	$	(.96	)	$	(1.55	)

Dividends per common share		$	—		$	—

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Balance Sheets

In millions			September 30, 2004		December 31, 2003

			(Unaudited)
Assets
Current assets:
	Cash and cash equivalents	$	538.0	$	601.7
	Restricted cash		24.7		249.2
	Funds on deposit		405.7		382.5
	Accounts receivable, net		312.8		598.4
	Inventories and supplies		184.0		149.4
	Price risk management assets		279.4		311.0
	Prepayments and other		181.3		194.7
	Current assets of discontinued operations		—		231.9

Total current assets			1,925.9		2,718.8

	Property, plant and equipment, net		2,759.1		2,752.7
	Investments in unconsolidated subsidiaries		2.1		312.9
	Price risk management assets		292.6		492.6
	Goodwill, net		111.0		111.0
	Deferred charges and other assets		205.8		271.9
	Non-current assets of discontinued operations		8.6		1,059.2

Total Assets		$	5,305.1	$	7,719.1

Liabilities and Shareholders' Equity
Current liabilities:
	Current maturities of long-term debt	$	172.2	$	414.8
	Short-term debt		220.0		—
	Accounts payable		237.3		488.2
	Accrued liabilities		289.3		335.4
	Price risk management liabilities		248.5		290.1
	Current portion of long-term gas contracts		31.5		84.8
	Customer funds on deposit		25.6		279.5
	Current liabilities of discontinued operations		—		368.5

Total current liabilities			1,224.4		2,261.3

Long-term liabilities:
	Long-term debt, net		2,126.7		2,291.2
	Deferred income taxes and credits		189.2		376.2
	Price risk management liabilities		245.4		383.5
	Long-term gas contracts, net		117.3		586.3
	Deferred credits		183.7		273.9
	Non-current liabilities of discontinued operations		—		187.4

Total long-term liabilities			2,862.3		4,098.5

Common shareholders' equity			1,218.4		1,359.3

Total Liabilities and Shareholders' Equity		$	5,305.1	$	7,719.1

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Statements of Comprehensive Income—Unaudited


			Three Months Ended September 30,						Nine Months Ended September 30,

In millions				2004			2003			2004			2003

Net loss			$	(116.4	)	$	(169.9	)	$	(211.5	)	$	(302.4	)
Other comprehensive income (loss), net of related tax:
	Foreign currency adjustments:
		Foreign currency translation adjustments, net of deferred tax expense (benefit) of $.2 million and $(1.7) million for the three months ended September 30, 2004 and 2003, respectively, and $(14.0) million and $42.8 million for the nine months ended September 30, 2004 and 2003, respectively		.4			(2.8	)		(21.3	)		84.4
		Reclassification of foreign currency (gains) losses to income due to sale of businesses and other, net of deferred tax (expense) benefit of $(4.7) million and $(9.5) million for the three months ended September 30, 2004 and 2003, respectively, and $(26.2) million and $(9.5) million for the nine months ended September 30, 2004 and 2003, respectively		(7.2	)		(14.9	)		(41.0	)		(14.9	)

		Total foreign currency adjustments		(6.8	)		(17.7	)		(62.3	)		69.5

	Cash flow hedges:
		Unrealized gains (losses) on hedging instruments net of deferred tax expense (benefit) of $3.8 million and $— for the three months ended September 30, 2004 and 2003, respectively, and $2.8 million and $(.6) million for the nine months ended September 30, 2004 and 2003, respectively		6.1			(1.1	)		4.5			(2.0	)
		Unrealized gains (losses) on hedging instruments of equity method investments, net of deferred tax expense (benefit) of $1.3 million and $(6.9) million for the three months and nine months ended September 30, 2003, respectively		—			2.1			—			(9.6	)
		Reclassification of net (gains) losses on hedging instruments to net income, net of deferred tax (expense) benefit of $.6 million for the three months ended September 30, 2004, and $.8 million and $9.1 million for the nine months ended September 30, 2004 and 2003, respectively		1.0			—			1.3			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 $1.6 million for the three months ended September 30, 2003, and $5.5 million and $1.8 million for the nine months ended September 30, 2004 and 2003, respectively		—			3.1			9.1			3.4

		Total cash flow hedges		7.1			4.1			14.9			5.8

	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 nine months ended September 30, 2004			—			—			4.4			—

	Other comprehensive income (loss)			.3			(13.6	)		(43.0	)		68.0

Total Comprehensive Income (Loss)			$	(116.1	)	$	(183.5	)	$	(254.5	)	$	(234.4	)

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Statements of Common Shareholders' Equity

In millions		September 30, 2004			December 31, 2003

		(Unaudited)
Common stock: authorized 400 million shares at September 30, 2004 and December 31, 2003, par value $1 per share; 241,713,732 shares issued at September 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	$	241.7		$	195.3
Premium on capital stock		3,228.7			3,161.3
Retained deficit		(2,259.6	)		(2,047.9	)
Accumulated other comprehensive income		7.6			50.6

Total Common Shareholders' Equity	$	1,218.4		$	1,359.3

See accompanying notes to consolidated financial statements.

Aquila, Inc.
Consolidated Statements of Cash Flows—Unaudited

				Nine Months Ended September 30,
In millions					2004			2003

Cash Flows From Operating Activities:
	Net loss			$	(211.5	)	$	(302.4	)
	Adjustments to reconcile net loss to net cash used for operating activities:
		Depreciation and amortization expense			112.3			132.4
		Restructuring charges			.9			27.7
		Cash paid for restructuring and other charges			(130.5	)		(163.1	)
		Net loss on sale of assets and other charges			62.2			239.2
		Foreign currency gains			(13.0	)		(41.2	)
		Net changes in price risk management assets and liabilities			73.9			34.5
		Deferred income taxes and investment tax credits			(167.1	)		(109.1	)
		Equity in earnings of investments			(2.1	)		(61.0	)
		Dividends and fees from investments			1.1			38.9
		Changes in certain assets and liabilities, net of effects of divestitures:
			Restricted cash		230.9			(111.4	)
			Funds on deposit		127.5			(118.2	)
			Accounts receivable/payable, net		39.6			(42.3	)
			Inventories and supplies		(39.4	)		(39.5	)
			Prepayments and other		(2.4	)		221.0
			Deferred charges and other assets		13.7			22.9
			Accrued liabilities		(77.3	)		133.5
			Customer funds on deposit		(234.5	)		30.0
			Deferred credits		(.6	)		(20.4	)
			Other		5.7			(26.1	)

Cash used for operating activities					(210.6	)		(154.6	)

Cash Flows From Investing Activities:
	Funds on deposit for long-term gas contract surety				(136.5	)		—
	Utilities capital expenditures				(160.0	)		(171.2	)
	Merchant capital expenditures				—			(36.3	)
	Cash proceeds received on sale of assets				1,267.9			905.7
	Merchant investments in unconsolidated subsidiaries				—			(44.5	)
	Other				(14.0	)		(24.4	)

Cash provided from investing activities					957.4			629.3

Cash Flows From Financing Activities:
	Issuance of common stock				112.4			—
	Issuance of long-term debt				339.8			412.0
	Retirement of long-term debt				(793.7	)		(464.2	)
	Short-term borrowings (repayments), net				(3.7	)		(57.9	)
	Cash paid on long-term gas contracts				(522.3	)		(58.8	)
	Other				1.2			2.2

Cash used for financing activities					(866.3	)		(166.7	)

Increase (decrease) in cash and cash equivalents					(119.5	)		308.0
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 $— and $117.7 million, respectively, of cash included in current assets of discontinued operations)				$	538.0		$	749.7

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

Because we account for options under APB 25, we disclose a pro forma net loss and a basic and diluted loss per share as if we reflected the estimated fair value of options as compensation expense in accordance with Statement of Financial Accounting Standards (SFAS) No. 123,

"Accounting for Stock-Based Compensation." Our pro forma net loss and basic and diluted loss per share are as follows:


		Three Months Ended September 30,						Nine Months Ended September 30,

In millions, except per share amounts			2004			2003			2004			2003

Net loss:
	As reported	$	(116.4	)	$	(169.9	)	$	(211.5	)	$	(302.4	)
	Premium Income Equity Securities (PIES) adjustment (Note 5)		2.7			—			2.7			—

Earnings available for common shares			(113.7	)		(169.9	)		(208.8	)		(302.4	)
	Total stock-based employee compensation expense determined under fair value method, net of related tax benefits		(.7	)		(1.3	)		(3.6	)		(4.1	)

	Pro forma net loss	$	(114.4	)	$	(171.2	)	$	(212.4	)	$	(306.5	)

Basic and diluted loss per share:
	As reported	$	(.44	)	$	(.87	)	$	(.96	)	$	(1.55	)
	Pro forma		(.44	)		(.88	)		(.98	)		(1.58	)

The Financial Accounting Standards Board (FASB) issued a proposed standard that would require all companies to expense the value of employee stock options granted after June 2005 and unvested options outstanding after that date. Based on our current options outstanding, we do not expect this standard to have a material impact on our operating results.

2. Restructuring Charges

We recorded the following restructuring charges:


		Three Months Ended September 30,						Nine Months Ended September 30,

In millions			2004			2003			2004		2003

Merchant Services:
	Interest rate swap reductions	$	—		$	—		$	—	$	23.1
	Severance and retention costs		.1			1.0			.7		2.5
	Lease agreements		—			(.3	)		—		(.3	)
	Other		—			—			—		(.6	)

	Total Merchant Services		.1			.7			.7		24.7
Corporate and Other severance costs			(.1	)		(.1	)		.2		3.0

Total restructuring charges		$	—		$	.6		$	.9	$	27.7

Severance Costs and Retention Payments

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

We incurred severance costs of $2.1 million for the nine months ended September 30, 2003, in connection with the restructuring of Everest Connections, our communications business within

Corporate and Other. This resulted from a reduction of approximately 160 employees. We also incurred $1.0 million and $2.5 million of severance and retention costs for the three and nine months ended September 30, 2003, respectively, related to the continued wind-down of our energy trading operations in Merchant Services.

Interest Rate Swap Reductions

We incurred $23.1 million of restructuring charges for the nine months ended September 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 nine months ended September 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		(.9	)

Accrued severance and retention costs as of September 30, 2004		$	.9

Other Restructuring Costs:
	Accrued other restructuring costs as of December 31, 2003	$	16.0
	Additional expense during the period		—
	Cash payments during the period		(7.4	)

Accrued other restructuring costs as of September 30, 2004 (a)		$	8.6

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

3. Net Loss on Sale of Assets and Other Charges

We have sold the assets and terminated the contracts listed in the table below. After-tax losses (gains) discussed below are reported after giving consideration to the effect of capital loss carryback and carryforward limitations. As a result, the net tax effect may differ substantially from our expected statutory tax rates. The after-tax losses (gains) discussed below are based on current estimates of the tax treatment of these transactions and may be adjusted after detailed

allocation of the purchase prices for tax purposes and the filing of tax returns including these sales. We recorded the following pretax net losses (gains) on sale of assets and other charges:


		Three Months Ended September 30,						Nine Months Ended September 30,

In millions			2004			2003			2004			2003

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

	Total Domestic Utilities		—			—			—			(2.2	)

Merchant Services:
	Long-term gas contract terminations		117.2			—			117.2			—
	Aries power project and tolling agreement		(.4	)		—			46.6			—
	Independent power plants		—			87.9			(6.1	)		87.9
	Marchwood development project		—			—			(5.0	)		—
	Investment in BAF Energy		—			—			(9.1	)		—
	Acadia tolling agreement		—			—			—			105.5
	Turbines		—			—			—			(5.1	)

	Total Merchant Services		116.8			87.9			143.6			188.3

Corporate and Other:
	Midlands Electricity		—			4.0			(3.3	)		4.0
	Australia		—			(1.0	)		—			1.6
	Other		(2.3	)		—			(4.1	)		—

	Total Corporate and Other		(2.3	)		3.0			(7.4	)		5.6

Total net loss on sale of assets and other charges		$	114.5		$	90.9		$	136.2		$	191.7

Long-Term Gas Contract Terminations

As discussed in more detail in Note 10, in the third quarter of 2004, we terminated three of our long-term gas supply contracts resulting in payments of $580.8 million and pretax losses of $117.2 million, or $73.2 million after tax.

Aries Power Project and Tolling Agreement

In March 2004, we transferred to Calpine Corp., our joint venture partner in the Aries power project, our 50% ownership interest in this project, cash of $5.0 million and certain transmission and ancillary contract rights in exchange for the termination of our remaining aggregate undiscounted payment obligation of approximately $397.3 million under our 20-year tolling agreement with the Aries facility. At the same time, Calpine returned approximately $12.5 million of collateral we had posted in support of ongoing energy trading contracts. We recorded a pretax loss of $46.6 million, or $35.4 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.

In July 2003, we completed the sale of our interests in United Energy and Multinet Gas and received cash proceeds of $525.0 million before transaction costs and taxes. We recorded a pretax gain of $1.0 million, or $.5 million after tax, in the third quarter of 2003 in connection with this sale.

4. Discontinued Operations

We have sold our investments in independent power plants and Canadian utility businesses, which are therefore considered discontinued operations in accordance with SFAS 144. The only remaining asset classified as held for sale is a merchant note receivable of $8.6 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, for approximately $1.08 billion (CDN$1.476 billion), including the assumption of debt of $113 million (CDN$155 million) by the purchasers. The closing proceeds included $85 million (CDN$116 million) of preliminary adjustments for working capital and capital expenditures as provided under the sales agreements. These proceeds were subject to final adjustments, which were completed in the third quarter of 2004. We recorded a pretax gain from this sale of $65.7 million, or $9.2 million after tax, in the second quarter of 2004, subject to adjustment for final working capital and capital expenditure adjustments. In September 2004, we agreed with Fortis on a final purchase price adjustment which resulted in a $3.2 million payment to Fortis and decreased our pretax gain by $.1 million, or $.1 million after tax, in the third quarter of 2004.

The effective tax rate on the pretax gain on sale of our Canadian utility businesses is substantially higher than the statutory federal tax rate due to the following factors. The U.S. taxes reflect the partial deduction of Canadian taxes, including withholding taxes, from the U.S.

taxable income instead of the full utilization of foreign tax credits. Taxes on the sale also reflect our inability to fully utilize the tax loss on the sale of the Alberta business against the tax gain on the sale of the British Columbia business.

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

Independent Power Plants

In November 2003, we agreed to sell our interests in 12 plants to Teton Power Funding LLC. Two of the plants, Lake Cogen and Onondaga, were consolidated on our balance sheet. We have reported the results of operations and assets of these two plants in discontinued operations. In the third quarter of 2003, we evaluated the carrying value of these assets based on the bids received and other internal valuations. The results of this assessment indicated these assets were impaired. 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 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			September 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		8.6		31.8

Total non-current assets of discontinued operations		$	8.6	$	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 September 30,						Nine Months Ended September 30,

In millions			2004			2003			2004			2003

Sales		$	(.1	)	$	75.1		$	130.9		$	235.4
Cost of sales			—			14.9			25.1			47.0

Gross profit			(.1	)		60.2			105.8			188.4

Operating expenses:
	Operating expense		.3			33.6			56.7			95.4
	Net loss (gain) on sale of assets and other charges		.1			47.5			(74.0	)		47.5
	Depreciation and amortization expense		—			.2			—			8.6

Total operating expenses			.4			81.3			(17.3	)		151.5

Other income (expense)			.7			(9.2	)		2.7			(5.3	)
Interest expense			.1			3.5			14.7			15.0

Earnings (loss) before income taxes			.1			(33.8	)		111.1			16.6
Income tax expense (benefit)			—			(8.1	)		54.4			5.1

Earnings (loss) from discontinued operations		$	.1		$	(25.7	)	$	56.7		$	11.5

5. Earnings (Loss) per Common Share

The table below shows how we calculated basic and diluted earnings (loss) per share. Basic earnings (loss) per share and basic weighted average shares are the starting point in calculating the dilutive measures. To calculate basic earnings (loss) per share, divide our earnings (loss) available for common shares for the period by our weighted average shares outstanding, without adjusting for dilutive items. Weighted average shares used in basic earnings per share includes 110.9 million shares issuable on the conversion of the mandatorily convertible Premium Income Equity Securities (PIES) from August 24, 2004, the date of issuance of the PIES. See Note 7 for further discussion. Diluted earnings (loss) per share is calculated by dividing our net loss, after assumed conversion of dilutive securities, by our weighted average shares outstanding, adjusted for the effect of dilutive securities. However, as a result of the net losses in the three and nine months ended September 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 September 30,						Nine Months Ended September 30,

In millions, except per share amounts			2004			2003			2004			2003

Loss from continuing operations		$	(116.5	)	$	(144.2	)	$	(268.2	)	$	(313.9	)
Earnings (loss) from discontinued operations			.1			(25.7	)		56.7			11.5

Net loss as reported			(116.4	)		(169.9	)		(211.5	)		(302.4	)
Interest and debt amortization costs associated with the PIES			2.7			—			2.7			—

Earnings (loss) available for common shares		$	(113.7	)	$	(169.9	)	$	(208.8	)	$	(302.4	)

Basic and diluted earnings (loss) per share:
	Loss from continuing operations	$	(.44	)	$	(.74	)	$	(1.22	)	$	(1.61	)
	Earnings (loss) from discontinued operations		—			(.13	)		.26			.06

	Net loss	$	(.44	)	$	(.87	)	$	(.96	)	$	(1.55	)

Weighted average number of common shares used in basic and diluted earnings (loss) per share			260.5			195.1			217.3			194.6

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 formerly consolidated independent power plants and our former Canadian utility businesses are included in Merchant Services and Corporate and Other, respectively.

Our reportable segment reconciliation is shown below:

		Three Months Ended September 30,						Nine Months Ended September 30,

In millions			2004			2003			2004			2003

Sales:
	Domestic Utilities	$	352.6		$	343.8		$	1,305.5		$	1,256.3
	Merchant Services		(39.9	)		(30.2	)		(122.7	)		(69.3	)
	Corporate and Other		9.7			8.4			28.1			25.2

Total		$	322.4		$	322.0		$	1,210.9		$	1,212.2

Earnings (Loss) Before Interest and Taxes (EBIT):
	Domestic Utilities	$	50.7		$	45.5		$	123.7		$	131.4
	Merchant Services		(178.8	)		(156.4	)		(344.7	)		(391.0	)
	Corporate and Other		3.6			(8.8	)		(10.1	)		26.9

Total EBIT			(124.5	)		(119.7	)		(231.1	)		(232.7	)
Interest expense			71.6			75.1			199.4			206.9

Loss from continuing operations before income taxes		$	(196.1	)	$	(194.8	)	$	(430.5	)	$	(439.6	)

In millions			September 30, 2004		December 31, 2003

Assets:*
	Domestic Utilities	$	2,979.4	$	3,060.2
	Merchant Services		1,546.9		2,717.8
	Corporate and Other		778.8		1,941.1

Total assets		$	5,305.1	$	7,719.1

* Included in total assets as of September 30, 2004 and December 31, 2003 are total current and non-current assets of discontinued operations as follows: Merchant Services, $8.6 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 8.15%, our incremental borrowing rate at that time. In February 2004, we paid $78.6 million to extinguish the entire note payable and accrued interest, resulting in other income related to this transaction of approximately $1.9 million.

Letter of Credit 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 September 30, 2004, $69.0 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 September 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, discussed under Note 10 below. The letter of credit was fully secured by cash deposits with the bank. In September 2004, we deposited funds with St. Paul Travelers and cancelled this facility.

Senior Notes

On June 30, 2004, we irrevocably deposited $258.8 million, including 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 as of June 30, 2004. The senior notes were retired on July 15, 2004.

On October 1, 2004, we retired $150.0 million of our 6.875% series of senior notes, which were due and payable on that date.

Mandatorily Convertible Senior Notes

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

If the mandatory conversion had occurred on September 30, 2004, the average closing price of our common stock for the 20-day trading period would have been $3.02. Using that rate, we would have converted each security into 8.286 shares of our common stock. The fair value of those shares would have been $356.8 million as of September 30, 2004.

Common Stock

In August 2004, we issued 46.0 million shares of our common stock, including an over-allotment of 6.0 million shares, at a price of $2.55 per share. Our net proceeds on the issuance of the common shares were $112.4 million, after underwriting discounts, commissions and other costs. We used these proceeds to retire long-term debt and other long-term liabilities.

Three-Year Secured Term Loan

In September 2004, we prepaid the $430 million three-year secured term loan as a result of a provision of the loan requiring us to complete an exchange offer, tender offer, refinancing or other retirement transaction with regard to 80% of our $150.0 million, 6.875% senior note series due October 1, 2004, at least two weeks prior to the loan's maturity date. We were required to pay prepayment penalties and fees of $8.7 million and write off unamortized debt issue costs of $10.3 million in connection with this debt retirement. In addition, certain lenders participating in the term loan are contesting the terms of the prepayment and seeking to require us to pay additional prepayment penalties of approximately $22.8 million. However, we have deposited $22.8 million with the term loan facility agent pending resolution of this dispute. The liens

against our regulated utility assets in Michigan, Nebraska, Iowa and Colorado that were pledged as collateral on the term loan have been released. See Note 9 for discussion of litigation relating to this dispute.

364-Day Term Loan and Revolving Credit Facility

In September 2004, we completed a $220 million 364-day unsecured term loan and a $110 million 364-day unsecured revolving credit facility (364-Day Facilities.) We borrowed the full amount of the term loan and received $211.3 million of net proceeds after upfront fees and expenses on the two facilities. We had not drawn on the revolving credit facility as of September 30, 2004. The 364-Day Facilities automatically extend to September 2009 if we receive extension approval from the Federal Energy Regulatory Commission and various state public utility commissions. The 364-Day Facilities bear interest at the London Inter-Bank Offering Rate (LIBOR) plus 5.75%, subject to reduction if our credit rating improves. Among other restrictions, the 364-Day Facilities contain the following financial covenants with which we were in compliance as of September 30, 2004:

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

The 364-Day Facilities also contain covenants that restrict certain activities including, among others, limitations on additional indebtedness, restrictions on acquisitions, sale transactions and investments. In addition, we are prohibited from paying dividends and from making certain other payments if our senior unsecured debt is not rated at least Ba2 by Moody's and BB by Standard & Poor's, or if such a payment would cause a default under the facility.

Six-Month Secured Revolving Credit Facility

On October 22, 2004, we completed a $125 million secured revolving credit facility (the AR Facility). Proceeds may be used for working capital and other general corporate purposes. We have not drawn on the AR Facility as of October 29, 2004. The facility is secured by the accounts receivable generated by our regulated utility operations in Colorado, Kansas, Michigan, Missouri and Nebraska. The six-month facility expires April 22, 2005. We expect to extend or replace this facility prior to its maturity. Borrowings under the AR Facility bear interest at LIBOR plus 2.50%. Among other restrictions, we are required under the AR Facility to maintain the same debt-to-total capital and EBITDA-to-interest expense ratios as those contained in the 364-day facilities discussed above.

Long-Term Debt Maturities

The amounts of long-term debt maturing in the fourth quarter of 2004 and in each of the next five years and thereafter are as follows:

In millions			Maturing Amounts

Fourth quarter 2004		$	150.2
2005			41.7
2006			89.2
2007 (a)			387.1
2008			2.0
2009			201.0
Thereafter			1,427.7

	Total	$	2,298.9

(a): Includes the conversion of $345.0 million of PIES to common stock on September 15, 2007.

8. Employee Benefits

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

		Pension Benefits						Other Post-retirement Benefits

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

Components of Net Periodic Benefit Cost:
Service cost	$	2.0		$	2.0		$	.1		$	.1
Interest cost		4.9			4.8			1.1			1.2
Expected return on plan assets		(6.0	)		(5.7	)		(.3	)		(.3	)
Amortization of transition amount		(.3	)		(.3	)		.1			.4
Amortization of prior service cost		.2			.2			.4			.2
Recognized net actuarial loss		2.1			2.6			.4			.3
Curtailment (gain) loss		—			—			—			(.1	)
Regulatory adjustment		1.5			(.8	)		.3			.1

Net Periodic Benefit Cost	$	4.4		$	2.8		$	2.1		$	1.9

		Pension Benefits						Other Post-retirement Benefits

	Nine Months Ended September 30,
In millions		2004			2003			2004			2003

Components of Net Periodic Benefit Cost:
Service cost	$	5.9		$	6.0		$	.2		$	.2
Interest cost		14.6			14.4			3.5			3.6
Expected return on plan assets		(18.0	)		(17.2	)		(.8	)		(.9	)
Amortization of transition amount		(.9	)		(.9	)		.5			1.2
Amortization of prior service cost		.8			.8			1.2			.6
Recognized net actuarial loss		6.1			7.8			1.4			.9
Curtailment (gain) loss		—			.2			—			(.2	)
Regulatory adjustment		2.9			(2.6	)		.7			.2

Net Periodic Benefit Cost	$	11.4		$	8.5		$	6.7		$	5.6

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.

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 $1.5 million and $2.7 million for the three and nine months ended September 30, 2004, respectively, 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, as well as a federal subsidy to sponsors of retiree healthcare plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Our actuaries are awaiting final regulatory guidance on determining actuarial equivalence, but have determined that the benefits provided under our other post-retirement benefit plans appear to be actuarially equivalent to the Medicare Part D benefits under the Act. Therefore, we anticipate qualifying for the 28% federal subsidy. We have recognized the effect of the Act on our other post-retirement benefit obligations and costs in our financial statements, beginning July 1, 2004 in accordance with FASB Staff Position No. 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003." Based on a remeasurement of the plans at April 1, 2004, the effect of the Act on the accumulated post-retirement benefit obligation was a decrease of $10.1 million, which we expect to amortize to reduce net periodic benefit costs in future periods. The effect of the Act on net periodic benefit cost was a decrease of $.4 million for the three and nine months ended September 30, 2004 and is estimated to be a decrease of $.7 million for the full year 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 were 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, and the underlying gas supply contracts were terminated on September 30, 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 of approximately $1.0 million in the second quarter of 2004.

Price Reporting Litigation

On August 18, 2003, Cornerstone Propane Partners filed suit in the Southern District of New York against 35 companies, including Aquila, that allegedly manipulated natural gas prices and futures prices on NYMEX through misreporting of natural gas trade data in the physical market. The suit does not specify alleged damages and was filed on behalf of all parties who bought and sold natural gas futures and options on NYMEX from 2000 to 2002. On September 24, 2004, the court denied Aquila's motion to dismiss along with similar motions filed by most of the other defendants. We will defend this case vigorously and believe it will be very difficult for the plaintiffs to establish that any alleged misreporting affected the price of gas futures on the NYMEX.

On June 7, 2004, the City of Tacoma filed suit against 56 companies, including Aquila, for allegedly conspiring to manipulate the California power market in 2000 and 2001 in violation of the Sherman Act. Tacoma has requested that the court suspend its scheduling order in light of relevant cases pending in the Ninth Circuit and the possibility that this case will be transferred to federal court in California.

On July 8, 2004, the County of Santa Clara and the City and County of San Francisco each filed suit against seven energy trading companies, including Aquila, in the Superior Court of San

Diego alleging manipulation of the California natural gas market in 2000 through 2002. On July 28, 2004, and September 8, 2004, the County of San Diego and a retail natural gas consumer, respectively, filed similar complaints making nearly identical allegations. All of these lawsuits allege violations of the Cartwright Act and unjust enrichment. In addition, the City and County of San Francisco and the lawsuit brought by a retail natural gas customer allege violations of the California Unfair Competition Law. The defendants have filed motions seeking to remove and transfer these cases as part of MDL proceeding MDL-1566, In re Western States Wholesale Natural Gas Antitrust Litigation. We believe we have strong defenses and will defend these cases vigorously.

Enron Canada Litigation

We continue to work with Enron Corp. and affiliates (Enron) to settle all outstanding claims between Enron and Aquila associated with the various bankruptcy filings of Enron in December 2001 and a lawsuit filed by Enron Canada Corp. In 2001, we reserved for substantially all of our then outstanding assets from Enron, which resulted in a charge of $66.8 million. This charge did not reflect potential gains we would record in the event we are successful in netting certain liabilities we also had with Enron against these asset positions. Approximately $33.4 million of liabilities remain on our books related to contracts with Enron. It continues to be uncertain as to whether the netting of certain assets and liabilities will be permitted.

Lender Litigation

On October 5, 2004 and October 15, 2004, lawsuits were filed against Aquila by its lenders alleging that Aquila was obligated to pay a "make whole" amount when Aquila prepaid its $430 million secured facility in September 2004. Aquila believes that it was required to pay a prepayment penalty of $8.7 million. The plaintiff lenders have sued Aquila for breach of contract for their proportionate share of the difference between these prepayment amounts, which in the aggregate is approximately $20 million. We believe we have strong defenses and that we will ultimately prevail.

ERISA Litigation

On September 24, 2004, a lawsuit was filed in the U.S. District Court for the Western District of Missouri against Aquila, the Board of Directors and certain members of management alleging they violated the Employee Retirement Income Security Act (ERISA) and are responsible for losses that participants in the Aquila 401(k) plan experienced as a result of the decline in the value of their Aquila stock held in the Aquila 401(k) plan. On October 8, 2004, October 12, 2004, and October 26, 2004, similar lawsuits were filed and will likely be consolidated into a single case. All of these lawsuits allege that the defendants breached their fiduciary duties to the plan in violation of ERISA by concealing information and/or misleading employees who held Aquila stock through the Aquila 401(k) plan. The suits also seek damages for the plan's losses resulting from the alleged breaches of fiduciary duties. We continue to review and assess these cases as they are filed.

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 in amounts necessary to support our obligations under the 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 obligation under the termination of these contracts in September was approximately $494.7 million, net of our hedge position.

St. Paul Surety Settlement

On July 19, 2004, we agreed with St. Paul Travelers (St. Paul) to escrow cash in the amount necessary to support our obligation under the surety agreement related to our MGAM contract. Our obligation under a default of this contract in July 2004 was approximately $91.3 million, net of our hedge position. Additionally, we deposited approximately $136.5 million in September 2004 with St. Paul related to the APEA II surety bond.

Termination of Long-Term Gas Contracts

In the third quarter of 2004, we terminated 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 were required to pay St. Paul and MGAM approximately $92.6 million under the liquidated damages and other provisions of the gas supply contract and termination agreement.

On August 13, 2004, we reached an agreement with APEA on the termination of our APEA III and APEA IV long-term gas supply contracts with them. As a result, we were required to pay Chubb and APEA approximately $488.2 million under the liquidated damages and other provisions of the gas supply contract and termination agreement.

We recorded a pretax charge of $117.2 million, or $73.2 million after tax, on the termination of these three contracts. On November 1, 2004, we ceased gas deliveries under our APEA II gas supply contract. We anticipate that final termination of the contract and payment of our obligations will occur before December 31, 2004 under the default and termination provisions of the contract and related surety agreement with St. Paul. We expect to record an additional pretax loss of approximately $42.4 million in the fourth quarter of 2004 in connection with the termination of this contract.

In addition, the realization of the price risk management assets and liabilities associated with the terminated long-term gas contracts, and the related commodity hedges that were terminated, resulted in non-cash, mark-to-market losses of $29.2 million primarily related to the discounting of our trading portfolio, $11.7 million for margin recorded on these contracts and $6.0 million of net replacement gas payments under the termination provisions of these contracts. We expect to record additional margin losses of $17.5 million in connection with the termination of our APEA II gas supply contract in the fourth quarter of 2004.

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 $51.5 million and total remaining cash payments of $76.6 million at September 30, 2004. MGAG expires in 2007 and APEA I expires in 2008.

11. Restricted Cash

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

In millions		September 30, 2004		December 31, 2003

Restricted customer funds on deposit	$	.8	$	248.7
Escrow for prepayment penalty dispute		22.8		—
Other		1.1		.5

Total	$	24.7	$	249.2

A large counterparty required us to segregate from our daily cash accounts the customer funds on deposit that they advanced to us. This amount was considered "restricted cash" and was not available for day-to-day operations. In September 2004, the underlying contracts with this counterparty were settled and their funds on deposit with us were refunded to them from restricted cash. The amount of these deposits at December 31, 2003 was $248.7 million.

Certain lenders have contested our retirement of the $430 million three-year secured term loan and are seeking additional prepayment penalties of approximately $22.8 million. As a result, we have deposited $22.8 million with the term loan facility agent and classified the amount as restricted cash. See Note 7 for further discussion.

12. Income Taxes

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, and after filing the 2003 federal income tax return in September 2004, these deferred tax benefits increased to approximately $341.0 million. The deferred tax benefits from the federal and state net operating losses are partially offset by $13.8 million of valuation allowances for state NOL carryforwards provided in 2003 and $145.1 million of deferred tax liabilities resulting from the cumulative tax provision for tax deduction or income positions that we believe are proper but for which we believe it is reasonably likely that these positions will be challenged upon audit by the Internal Revenue Service (IRS). With the filing of our 2003 state income tax returns in the fourth quarter of 2004, we will be evaluating the realizability of the deferred tax asset related to state net operating losses.

As a result of the PIES offering and concurrent common stock offering, which closed on August 24, 2004, we may be limited in our ability to utilize our net operating loss (NOL) carryforward to offset future taxable income. The Internal Revenue Code imposes an annual limitation on the use of a corporation's tax attributes if a corporation undergoes an ownership change for tax purposes during a three-year test period. The PIES and common stock offerings, in conjunction with additional transactions in our company stock during the testing period, may constitute an ownership change for this purpose.

If an ownership change is determined to have occurred, our ability to use the NOL carryforward from 2003 and the NOL generated through August 24, 2004, would be subject to an annual limitation. In such case, the amount of NOL subject to the limitation would not be determined until the 2004 tax return is filed and the determination would be subject to audit by the IRS. Based on our current estimate of the NOL existing at August 24, 2004, and our current estimate of the annual limitation, we do not expect that the annual limitation would cause any of our NOL to expire unutilized. Thus, we have not established a valuation allowance against the tax benefits of the NOL existing at August 24, 2004.

We also have significant capital loss and minimum tax credit (MTC) carryforwards that would be subject to the annual limitation described above. However, a full valuation allowance has already been provided against the tax benefits from the capital loss carryforwards and the MTC carryforwards do not expire. Therefore, no additional valuation allowance is required.

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

See Forward-Looking Information and Risk Factors beginning on page 48.

LIQUIDITY AND CAPITAL RESOURCES

Working Capital Requirements

The most significant activity impacting working capital is the purchase of natural gas for our gas utility customers. We could experience significant working capital requirements during peak winter heating months due to higher natural gas consumption, potential periods of high natural gas prices and the current requirement to prepay certain gas commodity suppliers and pipeline transportation companies. We anticipate using the combination of our $110 million 364-day unsecured revolving credit facility, $125 million secured accounts receivable facility and cash on hand to meet the peak winter working capital requirements of our business.

Cash Flows

Cash Flows used for Operating Activities

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

•: We had a net loss from continuing operations of $430.5 million before income tax benefits, including $117.2 million in losses relating to the termination of three long-term gas supply contracts.
•: 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 $38.0 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 nine-month 2003 operating cash flows were driven by the following events and factors:

•: We had a net loss from continuing operations of $439.6 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 $57.6 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 $217.8 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 in Note 10 of the Consolidated Financial Statements, we have terminated 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 nominal cash obligations of approximately $463.7 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 will continue to reduce our interest expense through retirement of debt upon maturity with cash flow from operations after capital expenditures.

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 nine months ended September 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. Cash flow from investing activities in 2004 increased by $331.3 million compared to 2003, primarily due to the increase in net proceeds received from the 2004 sales of our Canadian utility businesses, independent power plants, and Midlands Electricity. In 2003 we received proceeds from the sales of our merchant loan portfolio, investments in Australia, Quanta Services, and our gas gathering and pipeline assets. In addition, we had lower merchant capital expenditures in 2004, since we completed the construction of a merchant plant in June 2003, and lower investments in unconsolidated Merchant subsidiaries compared to 2003. The increases in cash flow were partially offset by our $136.5 million deposit with St. Paul/Travelers related to the APEA II surety bond in 2004.

Cash Flows used for Financing Activities

Cash flows used for financing activities in the nine months ended September 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 $699.6 million increase in cash used for financing activities stems from the retirement of the senior notes due July 15, 2004, the Midlands Electricity acquisition note, our secured term loan and debt related to our Canadian operations. In 2003, we retired the debt associated with our investment in Australia and the construction of our merchant power plants. Additionally, we have paid $463.6 million for the settlement and termination of our obligations under three long-term gas contracts. The funds used to retire debt and terminate long-term gas contracts in 2004 were provided by the issuance of 46.0 million shares of common stock, $334.3 million of mandatorily convertible PIES and our $220 million unsecured term loan.

Collateral Positions

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

In millions

Trading positions	$	126.8
St. Paul/Travelers deposit for APEA II		136.5
Utility cash collateral requirements		76.4
Elwood tolling contract		37.8
Insurance and other		28.2

Total Funds on Deposit	$	405.7

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

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 August 18, 2004, Standard & Poor's upgraded our senior unsecured debt rating from CCC+ to B-. On September 13, 2004, Moody's Investors Service upgraded our senior unsecured debt rating from Caa1 to B2. 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 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 September 30,						Nine Months Ended September 30,
In millions			2004			2003			2004			2003

Earnings (Loss) Before Interest and Taxes
	Domestic Utilities	$	50.7		$	45.5		$	123.7		$	131.4
	Merchant Services		(178.8	)		(156.4	)		(344.7	)		(391.0	)
	Corporate and Other		3.6			(8.8	)		(10.1	)		26.9

Total EBIT			(124.5	)		(119.7	)		(231.1	)		(232.7	)
Interest expense			71.6			75.1			199.4			206.9
Income tax benefit			(79.6	)		(50.6	)		(162.3	)		(125.7	)

Loss from continuing operations			(116.5	)		(144.2	)		(268.2	)		(313.9	)
Earnings (loss) from discontinued operations, net of tax			.1			(25.7	)		56.7			11.5

Net Loss		$	(116.4	)	$	(169.9	)	$	(211.5	)	$	(302.4	)

Key Factors Impacting Continuing Operating Results

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

•: Domestic Utilities EBIT decreased $7.7 million primarily due to increased cost of natural gas used for fuel and higher purchased power cost and unfavorable weather for both the electric utility and the gas utility offset partially by rate increases in Colorado and Missouri.
•: The continued wind-down of our energy trading businesses resulted in a $46.3 million decrease in losses before interest and taxes from Merchant Services.
•: In Corporate and Other, we recorded $41.2 million of foreign currency gains in the first nine months of 2003 related to favorable movements in the Australian and New Zealand dollar against the U.S. dollar. In the 2004 period we recorded $11.9 million of foreign currency gains related to the wind-down of our Canadian merchant subsidiaries.

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 September 30,						Nine Months Ended September 30,

In millions			2004			2003			2004			2003

Sales		$	(.1	)	$	75.1		$	130.9		$	235.4
Cost of sales			—			14.9			25.1			47.0

Gross profit (loss)			(.1	)		60.2			105.8			188.4

Operating expenses:
	Operating expense		.3			33.6			56.7			95.4
	Net loss (gain) on sale of assets and other charges		.1			47.5			(74.0	)		47.5
	Depreciation and amortization expense		—			.2			—			8.6

Total operating expenses			.4			81.3			(17.3	)		151.5

Other income (expense)			.7			(9.2	)		2.7			(5.3	)

Earnings (loss) before interest and taxes			.2			(30.3	)		125.8			31.6
Interest expense			.1			3.5			14.7			15.0

Earnings (loss) before income taxes			.1			(33.8	)		111.1			16.6
Income tax expense (benefit)			—			(8.1	)		54.4			5.1

Earnings (loss) from discontinued operations		$	.1		$	(25.7	)	$	56.7		$	11.5

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit decreased $75.2 million, $14.9 million and $60.3 million, respectively, in 2004 compared to 2003. Sales, cost of sales, and gross profit for our consolidated independent power plants decreased $9.5 million, $6.0 million and $3.5 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 $65.7 million, $8.9 million and $56.8 million, respectively, primarily due to the sale of these businesses in May 2004.

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

Loss on sale of assets in 2003 consisted of a $47.5 million impairment charge related to our consolidated independent power plants, Lake Cogen and Onondaga. In the third quarter of 2003, we decided to proceed with the sale of these assets and therefore wrote the assets down to estimated fair value less costs to sell, which was less than their carrying value.

Operating Expense

Operating expense decreased $33.3 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.

Other Income (Expense)

Other income (expense) increased $9.9 million in 2004 compared to 2003, primarily due to a $6.8 million charge related to a currency put option intended to protect us from unfavorable currency movements on the Canada sales proceeds in 2003 and $2.2 million of foreign currency losses related to U.S. dollar denominated debt issued by our Canadian subsidiaries in 2003.

Income Tax Expense (Benefit)

The income tax expense (benefit) for 2004 decreased $8.1 million from 2003, primarily due to the sale of our consolidated independent power plants in March 2004 and our Canadian utility businesses in May 2004. In addition, approximately $28.0 million of the 2003 impairment charge on our consolidated independent power plants was expected to be a capital loss for which we provided valuation allowances.

Year-to-Date

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit decreased $104.5 million, $21.9 million and $82.6 million, respectively, in 2004 compared to 2003. Sales and gross profit for our Canadian network business decreased $47.5 million and $38.1 million, respectively, primarily due to the sale of these businesses in May 2004. Canadian utility sales, cost of sales and gross profit in June 2003 through September 2003 were $91.9 million, $11.6 million and $80.3 million, respectively. These decreases were partially offset by the Alberta Energy Utilities Board's (AEUB) decision in March 2003 to reduce our 2002 and 2003 customer billing rates. The AEUB decision resulted in an adjustment that reduced our first quarter 2003 sales and gross profit by approximately $33.7 million. Sales, cost of sales and gross profit for Lake Cogen and Onondaga were lower in 2004 by $56.8 million, $12.5 million and $44.3 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.

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

Gain on sale of assets in 2004 consisted primarily of a $8.4 million gain related to the sale of our consolidated independent power plants, Lake Cogen and Onondaga in March 2004 and a $65.6 million gain related to the sale of our Canadian utility businesses in May 2004. The 2003 loss consisted of the $47.5 million impairment charge related to our consolidated independent power plants.

Operating Expense

Operating expense decreased $38.7 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 $8.6 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 (Benefit)

The income tax expense (benefit) for 2004 increased $49.3 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. 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 approximately $28.0 million of the losses on the sale of the independent power plants would be treated as a capital loss, the benefit from which more likely than not would not be realized. However, the form of the final sale resulted in a portion of these losses being realized as ordinary losses. The related valuation allowance was therefore reversed in the first quarter of 2004. The remaining valuation allowance for the capital losses on the sale of the independent power plants may be adjusted again after detailed allocation of the purchase price for tax purposes is completed based on an independent appraisal and the final tax returns related to the sale are filed. 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 September 30,			Nine Months Ended September 30,

Dollars in millions		2004	2003		2004	2003

Sales:
	Electricity—regulated	$239.6	$235.3		$ 581.5	$ 544.5
	Natural gas—regulated	103.3	98.4		697.5	675.9
	Natural gas—non-regulated	2.7	2.6		6.0	13.7
	Other—non-regulated	7.0	7.5		20.5	22.2

Total sales		352.6	343.8		1,305.5	1,256.3

Cost of sales:
	Electricity—regulated	110.2	112.6		290.3	264.6
	Natural gas—regulated	59.5	54.1		488.4	462.0
	Natural gas—non-regulated	1.7	2.2		4.2	10.9
	Other—non-regulated	3.5	3.1		9.7	8.9

Total cost of sales		174.9	172.0		792.6	746.4

Gross profit		177.7	171.8		512.9	509.9

Operating expenses:
	Operating expense	96.3	95.5		295.1	287.0
	Gain on sale of assets	—	—		—	(2.2	)
	Depreciation and amortization expense	31.0	30.6		94.7	93.5

Total operating expenses		127.3	126.1		389.8	378.3

Other income (expense)		.3	(.2	)	.6	(.2	)

Earnings before interest and taxes		$ 50.7	$ 45.5		$ 123.7	$ 131.4

Electric sales and transportation volumes (GWh)		3,869.8	3,426.7		10,223.3	8,933.8
Gas sales and transportation volumes (Bcf)		31.1	34.4		154.4	165.9
Electric customers at end of period					452,000	445,000
Gas customers at end of period					889,000	879,000

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit for the Domestic Utilities business increased $8.8 million, $2.9 million, and $5.9 million, respectively, in 2004 compared to 2003. These changes were primarily due to the following factors:

•: Regulated electric utility sales and gross profit increased $4.3 million and $6.7 million, respectively, while cost of sales decreased $2.4 million in 2004 compared to 2003. Sales and gross profit increased by $11.3 million due to rate increases in Colorado effective in July 2003 and in Missouri effective in April 2004, plus $1.8 million of additional margin from an increase in customers. In addition, $1.6 million of lower costs of fuel and purchased power, net of offsetting derivative positions, also contributed to the increased margin. The decrease in purchased power and fuel costs was the result of mild weather in

2004 which allowed us to meet a greater portion of our customer demand with electricity generated at our lower-cost, coal-fired power plants rather than utilizing our higher-cost, gas-fired generation capacity or purchasing power as we did in 2003. These were offset by $8.1 million of unfavorable weather-related volume and other variances.

•: Sales and cost of sales for our regulated gas utilities increased $4.9 million and $5.4 million, respectively, in 2004 compared to 2003, for a net decrease in gross profit of $.5 million. Regulated gas margins decreased $1.7 million in 2004 compared to 2003 due to favorable resolution of gas cost proceedings in 2003. The overall decline in gas margins was partially offset by $1.9 million in rate increases in Nebraska and Missouri.

Year-to-Date

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for the Domestic Utilities business increased $49.2 million and $46.2 million, respectively, and gross profit increased $3.0 million in 2004 compared to 2003. These changes were primarily due to the following factors:

•: Regulated electric utility sales and cost of sales increased $37.0 million and $25.7 million, respectively, in 2004 compared to 2003, for a net increase in gross profit of $11.3 million. Sales and gross profit increased by $26.8 million due to rate increases in Colorado effective in July 2003 and in Missouri effective in April 2004, plus $4.4 million of additional margin from an increase in customers. These were partially offset by a $14.1 million increase in cost of sales due to the higher cost of fuel and purchased power, net of offsetting derivative hedge positions in 2003. Unfavorable weather and other items also decreased gross profit by $5.7 million.
•: Sales and cost of sales for our regulated gas utilities increased $21.6 million and $26.4 million, respectively, in 2004 compared to 2003, for a net decrease in gross profit of $4.8 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 $5.3 million in rate increases in Nebraska and Missouri.
•: Non-regulated gas sales, cost of sales and gross profit decreased $7.7 million, $6.7 million and $1.0 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 expense increased $8.1 million in 2004 compared to 2003 as a result of a number of cost increases. The most significant of these was materials costs, which increased $2.4 million, and labor and other compensation costs, which increased $3.4 million due to additional customer service representatives, apprentice linemen and compliance costs in 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

Nebraska	Gas	6/2003	1/2004	$	9.9	$ 6.2
Missouri	Electric	7/2003	4/2004		80.9	37.5
Missouri	Gas	8/2003	4/2004		6.4	3.4
Colorado	Electric	12/2003	8/2004		11.4	8.2
Kansas	Electric	6/2004	Pending		19.2	Pending
Kansas	Gas	11/2004	Pending		6.2	Pending

In June 2003, we filed for gas rate increases totaling $9.9 million in three rate areas of Nebraska. We received approval to place an interim rate increase of $9.9 million into effect beginning in October 2003, subject to refund. In December 2003, we reached a settlement with Nebraska's Public Advocate and other intervening parties for an increase of $6.2 million. The settlement was approved by the Nebraska Commission in January 2004.

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 for St. Joseph Light & Power and $19.71/Mwh for Missouri Public Service. If the amounts collected under the IEC exceed our average cost incurred for the two-year period, we will refund the excess to the customers, with interest. This fuel and purchased power cost recovery mechanism represents $18.5 million of the $37.5 million rate increase. Also, as part of the settlement we agreed not to seek a general increase in our Missouri electric rates that would be effective in less than two years from the current rate increase, unless certain significant events occur that impact our operations.

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

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 denied this request in October 2004.

In November 2004, we filed for a rate increase totaling $6.2 million for our gas territories in Kansas. This application is primarily to recover infrastructure improvements and increased operating and maintenance costs. We expect hearings to be held by May 2005 with rates effective in August 2005.

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. In October 2004, the Missouri Commission declined to schedule hearings on this request.

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. If these costs remain above the IEC base cost for the two-year period, we will not recover the excess. A portion of the rate increase is to cover increased costs in the 12-month test period such as additional staffing to improve customer service. To the extent that operating costs increase or decrease subsequent to the test period, the impact of the change will affect our operating results.

Our power supply agreement with Aries, which provides up to 500 MW of power, expires in June 2005. We currently plan to replace this power with the construction of a 315 megawatt peaking generation plant and by entering into long-term power purchase contracts. The construction of this peaking facility is expected to require additional capital expenditures of approximately $56 million. In addition, transmission system upgrades of $22 million will be required. To the extent the cost of this replacement power exceeds the cost of power recovered in rates under the Aries agreement, and until such cost is recovered in a subsequent rate case, our earnings could be adversely affected.

On December 22, 2003, one of our coal suppliers declared a partial Force Majeure event due to a labor strike at the mine. They gave us formal notice they would be unable to fully perform their contract obligations for the following 60 to 90 days. This Force Majeure condition has continued throughout 2004, with Aquila receiving approximately 30% of its contracted low sulfur, high Btu volumes. To date we have been able to meet our coal needs with comparable cost coal through existing contracts and spot purchases. However, in response to a recent decrease in availability of comparable spot market coal, we have entered into an option contract with another supplier to ensure an adequate supply of fuel for our coal-fired generation plants. This substitute supply of coal is higher in sulfur content, therefore requiring the purchase of additional sulfur dioxide (SO2) emission allowances at a time when the cost of such allowances is substantially higher than historical levels. In the event we continue to replace our original contracted coal supply with the substitute coal during 2005, our operating results could be adversely affected.

Merchant Services

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

			Three Months Ended September 30,						Nine Months Ended September 30,

In millions			2004			2003			2004			2003

Sales		$	(39.9	)	$	(30.2	)	$	(122.7	)	$	(69.3	)
Cost of sales			12.8			18.8			43.5			71.9

Gross loss			(52.7	)		(49.0	)		(166.2	)		(141.2	)

Operating expenses:
	Operating expense		7.0			14.8			26.0			61.5
	Restructuring charges		.1			.7			.7			24.7
	Net loss on sale of assets and other charges		116.8			87.9			143.6			188.3
	Depreciation and amortization expense		4.2			6.9			13.0			27.6

Total operating expenses			128.1			110.3			183.3			302.1

Other income (expense):
	Equity in earnings (losses) of investments		—			(2.0	)		1.9			44.9
	Other income		2.0			4.9			2.9			7.4

Loss before interest and taxes		$	(178.8	)	$	(156.4	)	$	(344.7	)	$	(391.0	)

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

Quarter-to-Quarter

Sales, Cost of Sales and Gross Loss

Gross loss for our Merchant Services operations for the three months ended September 30, 2004 was $52.7 million, primarily due to the following factors:

•: The settlement of our price risk management assets and liabilities associated with three of our long-term gas contracts resulted in non-cash, mark-to-market losses of approximately $29.2 million 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. This resulted in the recording of a net asset related to these three long-term contracts and their corresponding commodity hedges of approximately $29.2 million prior to our settlement. Additionally, we recorded a margin loss of approximately $11.7 million for margin recorded on these long-term contracts and approximately $6.0 million related to replacement gas payments we made under the termination provisions of these contracts.
•: In the third quarter of 2004, we incurred margin losses of $3.9 million resulting from the difference between revenue recognized on our remaining 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 third quarter of 2004, we recorded net margin losses associated with these agreements of $9.0 million. The cost to

purchase natural gas to fuel these power plants generally exceeded the value of the power that could be generated. Accordingly, we did not generate material revenues.

•: Offsetting the above losses, we recorded gross profit related to movements in our non-cash credit reserves of approximately $2.6 million and on natural gas call options used for hedging our winter 2004-2005 working capital requirements of approximately $3.2 million. These call options provide cash flow protection against a potential escalation or spike in natural gas prices for the portion of our total company gas supply portfolio that is purchased at index.

Gross loss for our Merchant Services operations for the three months ended September 30, 2003 was $49.0 million, primarily due to the following factors:

•: Approximately $21.4 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.
•: In the third quarter of 2003, we incurred margin losses of $10.4 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 third quarter of 2003, we recorded net margin loss associated with these agreements of $9.0 million. The cost to purchase natural gas to fuel these power plants generally exceeded the value of the power that could be generated. Accordingly, we did not generate any material revenues.
•: The remaining losses primarily relate to mark-to-market losses on open commodity positions and alternative risk contracts.

Operating Expense

Operating expense decreased $7.8 million primarily due to the reduction in legal and other investigation fees, reduced surety payments due to the settlement of three long-term gas contracts and reduced staffing needed to manage our remaining trading positions and non-regulated power generation assets.

Net Loss on Sale of Assets and Other Charges

In the third quarter of 2004, we recorded pretax losses of $117.2 million on the termination of three long-term gas supply contracts. See Note 10 to the Consolidated Financial Statements for further discussion. In September 2003, we recorded an impairment loss of $87.9 million to write our equity investments in independent power plants down to their estimated fair value, which was less than their carrying value.

Year-to-Date

Sales, Cost of Sales and Gross Profit

Gross loss for our Merchant Services operations for the nine months ended September 30, 2004 was $166.2 million, primarily due to the following factors:

•: Approximately $24.6 million was a non-cash loss related to the discounting of our trading portfolio, primarily driven by our long-term gas contracts. 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 resulting in the partial reversal of the previous earnings and asset recorded. After the settlement of three of our long-term gas contracts and the anticipated settlement of a fourth, the future impact of non-cash mark-to-market movements described above will be significantly reduced.

•: In the nine months of 2004, we incurred margin losses of $28.3 million resulting from the difference between revenue recognized on our long-term gas contracts and the net cost of gas delivered under these contracts.
•: We make fixed capacity payments evenly throughout the year that entitle us to generate power at merchant power plants owned by others. For the nine months of 2004, we recorded net margin loss associated with these agreements of $28.0 million. The cost to purchase natural gas to fuel these power plants generally exceeded the value of the power that could be generated. Accordingly, we did not generate material revenues. Capacity payments were lower in the nine 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.
•: The settlement of our price risk management assets and liabilities associated with three of our long-term gas contracts, resulted in margin losses of approximately $46.9 million. See quarter-to-quarter discussion above.
•: We incurred approximately $5.9 million of costs to manage our remaining 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 nine 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 nine months ended September 30, 2003 was $141.2 million, primarily due to the following factors:

•: Partially offsetting the losses discussed below were approximately $52.7 million of non-cash earnings related to the discounting of our trading portfolios, primarily driven by long-term gas contracts. During the first nine months of 2003, average gas prices rose over the life of our price risk management assets and liabilities by $.57 per MMBtu.
•: In the first nine months of 2003, we incurred margin losses of $33.2 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 nine months of 2003, we recorded net margin loss associated with these agreements of $46.2 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 material revenues.

•: In the first nine months of 2003, we incurred approximately $40.3 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 $37.8 million of net mark-to-market losses on natural gas hedge positions related to the Onondaga swap derivative and other hedges related to previous contracts.
•: The remaining gross loss primarily relates to mark-to-market losses on alternative risk contracts and other open commodity positions.

Operating Expense

Operating expense decreased $35.5 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.

Restructuring Charges

Restructuring charges decreased $24.0 million primarily due to a charge of $23.1 million taken in the first nine months 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 on Sale of Assets and Other Charges

Net loss on sale of assets and other charges in 2004 consists of a $117.2 million loss on the termination of three long-term gas contracts and a $46.6 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.

In May 2003, we terminated our 20-year tolling contract for the Acadia power plant and made a termination payment of $105.5 million. In September 2003, we recorded an impairment loss of $87.9 million to write our equity investments in independent power plants down to their estimated fair value, which was less than their carrying value. 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.

Depreciation and amortization expense

Depreciation and amortization expense decreased by $14.6 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 $43.0 million mainly due to the 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 from energy trading 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 $19.5 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 September 30,						Nine Months Ended September 30,

In millions			2004			2003			2004			2003

Sales		$	9.7		$	8.4		$	28.1		$	25.2
Cost of sales			3.2			2.5			9.0			7.8

Gross profit			6.5			5.9			19.1			17.4

Operating expenses:
	Operating expense		9.5			11.9			43.3			55.4
	Restructuring charges		(.1	)		(.1	)		.2			3.0
	Net loss (gain) on sale of assets and other charges		(2.3	)		3.0			(7.4	)		5.6
	Depreciation and amortization expense		2.3			1.1			4.6			2.7

Total operating expenses			9.4			15.9			40.7			66.7

Other income (expense):
	Equity in earnings of investments		—			1.9			.2			16.1
	Other income (expense)		6.5			(.7	)		11.3			60.1

Earnings (loss) before interest and taxes		$	3.6		$	(8.8	)	$	(10.1	)	$	26.9

Quarter-to-Quarter

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

The $2.3 million gain in 2004 related to the fair value adjustment of Everest Connections' target-based put rights liability. The $3.0 million loss on sale of assets in 2003 consisted of a $4.0 million impairment charge related to our investment in Midlands Electricity in the United Kingdom, offset in part by a $1.0 million gain on the sale of our interests in United Energy and Multinet Gas in Australia in July 2003.

Equity in Earnings of Investments

Equity in earnings of investments decreased $1.9 million in 2004 compared to 2003 due to the sale of our investments in Australia in May and July 2003.

Other Income

Other income increased $7.2 million mainly due to $11.9 million of realized foreign currency gains related to the wind-down of our Canadian merchant subsidiaries, partially offset by $8.7 million of prepayment penalties and fees we paid in association with the retirement of the $430 million three-year secured term loan.

Year-to-Date

Operating Expense

Operating expense decreased $12.1 million due to a $15.7 million decrease in restructuring fees, investigation fees and insurance compared to 2003. In addition, the restructuring of Everest Connections decreased operating expenses $2.1 million and the sale of our international

investments in Australia and the United Kingdom decreased operating expenses $9.1 million. These decreases were partially offset by a $8.4 million increase in the reserve to settle the appraisal rights shareholder lawsuit and $4.4 million of additional costs in 2004 related to the exit from our international networks investments.

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 and Other Charges

The 2004 gain on sale of assets and other charges of $7.4 million is mainly due to the fair value adjustment of our Everest Connections target-based put rights liability of $4.1 million, and the gain we recorded in connection with the sale of our interest in Midlands Electricity in January 2004. The Midlands Electricity investment was written down to its 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 2003 loss on sale of assets of $5.6 million was related to the impairment charge taken on our investment in Midlands Electricity in September 2003 and the loss on the sale of our interests in AlintaGas, United Energy and Multinet Gas in Australia in May and July 2003.

Equity in Earnings of Investments

Equity in earnings of investments decreased $15.9 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 $48.8 million mainly due to $41.2 million of foreign currency gains recognized in 2003 related to favorable movements in the Australian and New Zealand dollar against the U.S. dollar, and $12.1 million of foreign currency gains recognized in the second quarter of 2003 due to the strengthening of the Canadian dollar on U.S. dollar obligations at a former Canadian finance subsidiary not included in discontinued operations. We had an $11.9 million gain on foreign currency related to the wind-down of our Canadian merchant subsidiaries in 2004. Additionally 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 by $1.8 million in fees paid to lenders in connection with the waiver and amendment of financial covenants under our retired secured term loan. These gains in 2004 were partially offset by $8.7 million of prepayment penalties and fees we paid in association with the retirement of the secured term loan.

Interest Expense and Income Tax Benefit

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

		Three Months Ended September 30,						Nine Months Ended September 30,

In millions		2004			2003			2004			2003

Interest expense	$	71.6		$	75.1		$	199.4		$	206.9

Income tax benefit	$	(79.6	)	$	(50.6	)	$	(162.3	)	$	(125.7	)

Quarter-to-Quarter

Interest Expense

Interest expense decreased $3.5 million in 2004 compared to 2003. The decrease was primarily the result of 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. These reductions were offset in part by increases in interest expense related to the PIES issued in August 2004 and the write-off of $10.3 million of unamortized debt issue costs related to the early retirement of the secured term loan in September 2004.

Income Tax Benefit

The income tax benefit increased $29.0 million in 2004 compared to 2003, primarily as a result of tax benefits not being recognized on certain 2003 losses as a result of valuation allowances provided.

Year-to-Date

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 Australia, Midlands Electricity, our Merchant power plants, our prior revolving credit facility, our former 364-day secured credit facility and $250 million of senior notes due July 15, 2004. These decreases were partially offset by the borrowing in April 2003 of $430.0 million under our retired secured term loan, resulting in $7.6 million of additional interest expense and amortization of debt issue costs of $1.2 million. In addition, the reductions were offset in part by increases in interest expense related to the PIES issued in August 2004 and the write-off of $10.3 million of unamortized debt issue costs related to the early retirement of the secured term loan in September 2004.

Income Tax Benefit

The income tax benefit increased $36.6 million in 2004 compared to 2003, primarily as a result of tax benefits not being recognized on certain 2003 losses as a result of valuation allowances provided.

Significant Balance Sheet Movements

Total assets decreased by $2,414.0 million since December 31, 2003. This decrease is primarily due to the following:

•: Cash decreased $63.7 million. See our Consolidated Statement of Cash Flows for analysis of this decrease.
•: Restricted cash decreased $224.5 million primarily due to the return of cash that had been previously restricted for a large counterparty's customer funds on deposit of $248.7 million, partially offset by $22.8 million of additional cash we restricted for the resolution of the dispute over the early retirement of the three-year secured term loan.
•: Funds on deposit increased $23.2 million primarily due to the $136.5 million deposit we made with St. Paul related to the APEA II surety bond. This increase was partially offset by the return of $29.5 million of margin deposits paid to counterparties related to the seasonal decrease in gas purchases by our regulated utilities, and the return of $85.0 million of merchant funds on deposit related to the wind-down of our trading business.
•: Accounts receivable decreased $285.6 million, primarily reflecting lower volumes of gas and electricity delivered due to our exit from wholesale energy trading, and seasonal declines in regulated gas customer deliveries.
•: Inventories and supplies increased $34.6 million primarily due to the seasonal injection of natural gas into underground storage by our Domestic Utilities businesses for winter month deliveries to customers.
•: Price risk management assets decreased $231.6 million primarily due to the termination of three long-term gas contracts and related hedges in the third quarter of 2004, offset in part by an increase in natural gas prices since December 31, 2003.
•: Investments in unconsolidated subsidiaries decreased by $310.8 million primarily due to the sale of our investments in Midlands Electricity and our independent power plants.
•: Deferred charges and other assets decreased $66.1 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 $1,282.5 million primarily due to the sale of our Canadian utility businesses and our consolidated independent power plants.

Total liabilities decreased by $2,273.1 million and common shareholders' equity decreased by $140.9 million since December 31, 2003. These changes are primarily attributable to the following:

•: Short-term debt increased $220.0 million as a result of the execution of our 364-day unsecured term loan in September 2004.
•: Accounts payable decreased by $250.9 million primarily reflecting lower volumes of gas and electricity delivered due to our exit from wholesale energy trading.
•: Accrued liabilities decreased $46.1 million primarily due to the settlement with the CFTC regarding the reporting of our natural gas trading information to publications that compile and report index prices, the settlement of our appraisal rights litigation, and additional interest incurred on our outstanding debt obligations, partially offset by our increased tax obligation related to the sale of our Canadian utility businesses.

•: Price risk management liabilities decreased $179.7 million primarily due to the termination of three long-term gas contracts in the third quarter of 2004, offset in part by an increase in natural gas prices since December 31, 2003.
•: Customer funds on deposit decreased $253.9 million primarily due to the return of a large counterparty's deposit when the underlying contracts were settled in the third quarter of 2004.
•: Long-term debt, including current maturities of long-term debt, decreased by $407.1 million primarily due to the retirement of the three-year secured term loan, the $250.0 million retirement of 7.00% series of senior notes, and the $75.6 million early retirement of the Midlands acquisition note payable. These retirements were partially offset by the issuance of $345.0 million of PIES.
•: Deferred income taxes decreased $187.0 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.
•: Long-term gas contracts, including the current portion of long-term gas contracts, decreased $522.3 million primarily due to the termination of our obligations under three long-term gas contracts in the third quarter of 2004.
•: Deferred credits decreased $90.2 million primarily related to the elimination of deferred income tax regulatory liabilities in connection with the sale of our Canadian utility businesses.
•: Current and non-current liabilities of discontinued operations decreased $555.9 million primarily due to the sale of our Canadian utility businesses and our consolidated independent power plants.
•: Common shareholders' equity decreased $140.9 million primarily as a result of the year-to-date net loss of $211.5 million for 2004 and other comprehensive losses due to the sale of our investment in Midlands Electricity and our Canadian utility businesses, offset in part by the issuance of 46.0 million shares of common stock for $112.4 million.

Forward-Looking Information and Risk Factors

This report contains forward-looking statements that (i) we believe we have strong defenses to litigation pending against us, that it will be difficult for plaintiffs to establish that alleged misreporting of natural gas trade data affected the price of gas futures, and that we will prevail in certain litigation, (ii) we do not expect that the annual limitation on net operating losses would cause of any of our net operating losses to expire unutilized for purposes of reducing our taxes, (iii) we anticipate that our current revolving credit capacity and available cash will be sufficient for our winter needs, (iv) we expect to settle one of our remaining long-term gas contracts and retain the other two and (v) we expect that collateral posted in support of energy trading contracts will be returned to us as those positions are settled. 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:

•: Judges and juries can be difficult to predict and may in fact rule against us.
•: Our positions in litigation may be weakened by adverse developments in the law or the discovery of facts that hurt our cases.

•: Changes in the tax law or the failure to generate income could result in our tax net operating losses going unutilized.
•: Our access to revolving credit capacity depends on maintaining compliance with loan covenants. If we violate those covenants, we may lose revolving credit capacity and not have sufficient cash available for our winter needs.
•: Unanticipated increases in fuel prices and in the price of natural gas that we purchase for our utility customers could exhaust our liquidity in the winter months.
•: 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.
•: We may later decide to terminate long-term gas contracts that we do not presently intend to terminate.
•: Counterparties may default on their obligation to return collateral to 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		(102.3	)
Contracts realized or cash settled		50.4

Fair value at September 30, 2004	$	78.1

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	$	4.2
2005		19.0
2006		18.6
2007		22.1
Thereafter		14.2

Total fair value	$	78.1

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

Price Reporting Litigation

On July 8, 2004, the County of Santa Clara and the City and County of San Francisco each filed suit against seven energy trading companies, including Aquila, in the Superior Court of San Diego alleging manipulation of the California natural gas market in 2000 through 2002. On July 28, 2004, and September 8, 2004, the County of San Diego and a retail natural gas consumer, respectively, filed similar complaints making nearly identical allegations. All of these lawsuits allege violations of the Cartwright Act and unjust enrichment. In addition, the City and County of San Francisco and the lawsuit brought by a retail natural gas customer allege violations of the California Unfair Competition Law. The defendants have filed motions seeking to remove and transfer these cases as part of MDL proceeding MDL-1566, In re Western States Wholesale Natural Gas Antitrust Litigation. We believe we have strong defenses and will defend these cases vigorously.

Enron Canada Litigation

Lender Litigation

ERISA Litigation

Item 6. Exhibits

(a) List of Exhibits

Exhibit No.		Description

31.1		Certification of Chief Executive Officer under Section 302
31.2		Certification of Chief Financial Officer under Section 302
32.1		Certification of Chief Executive Officer under Section 906
32.2		Certification of Chief Financial Officer under Section 906

SIGNATURES

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

Aquila, Inc.

By:		/s/ Rick J. Dobson Rick J. Dobson Senior Vice President and Chief Financial Officer Signing on behalf of the registrant and as principal financial and accounting officer
Date:		November 3, 2004