AQUILA INC - 10-Q Quarterly Report

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

FORM 10-Q

(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2003
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 August 4, 2003
Common Stock, $1 par value		195,130,943

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Information regarding the consolidated financial statements is set forth on pages 3 through 21.

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

Management's discussion and analysis of financial condition and results of operations can be found on pages 22 through 41.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are subject to market risk as described on pages 65 through 68 of our 2002 Annual Report on Form 10-K. See discussion on pages 41 through 42 for changes in market risk since December 31, 2002.

ITEM 4. CONTROLS AND PROCEDURES

Information regarding disclosure controls and procedures can be found on page 42.

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information regarding legal proceedings can be found on page 43.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

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

Information regarding the submission of matters for a vote of securities holders can be found on page 43.

ITEM 5. OTHER INFORMATION

Not applicable.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

Exhibits and Reports on Form 8-K can be found on page 43.

Part I. Financial Information

Item 1. Financial Statements

Aquila, Inc.

Consolidated Statements of Income—Unaudited

		Three Months Ended June 30,
In millions, except per share amounts		2003			2002

Sales:
	Electricity—regulated	$	158.7		$	169.7
	Natural gas—regulated		156.9			128.6
	Electricity—non-regulated		25.8			134.8
	Natural gas—non-regulated		61.4			155.8
	Other—non-regulated		.4			.8

Total sales			403.2			589.7

Cost of sales:
	Electricity—regulated		80.3			78.2
	Natural gas—regulated		102.0			75.7
	Electricity—non-regulated		26.2			70.8
	Natural gas—non-regulated		11.0			98.2
	Other—non-regulated		5.2			5.7

Total cost of sales			224.7			328.6

Gross profit			178.5			261.1

Operating expenses:
	Operating expense		152.6			156.8
	Restructuring charges		20.8			71.4
	Impairment charges and net loss on sale of assets		103.0			894.6
	Depreciation and amortization expense		37.6			38.9

Total operating expenses			314.0			1,161.7

Other income (expense):
	Equity in earnings of investments		36.6			36.0
	Minority interest in income of subsidiaries		—			1.7
	Other income		42.7			3.8

Total other income (expense)			79.3			41.5

Interest expense:
	Interest expense		76.9			47.2
	Minority interest in income of partnership and trust		—			5.4

Total interest expense			76.9			52.6

Loss from continuing operations before income taxes			(133.1	)		(911.7	)
Income tax benefit			(38.0	)		(86.2	)

Loss from continuing operations			(95.1	)		(825.5	)
Earnings from discontinued operations, net of tax			14.5			15.5

Net loss		$	(80.6	)	$	(810.0	)

Basic and diluted earnings (loss) per common share:
	Continuing operations	$	(.49	)	$	(5.80	)
	Discontinued operations		.08			.11

	Net loss	$	(.41	)	$	(5.69	)

Dividends per common share		$	—		$	..30

See accompanying notes to consolidated financial statements.

Aquila, Inc.

Consolidated Statements of Income—Unaudited

		Six Months Ended June 30,
In millions, except per share amounts		2003			2002

Sales:
	Electricity—regulated	$	309.3		$	307.7
	Natural gas—regulated		577.5			425.9
	Electricity—non-regulated		24.6			234.2
	Natural gas—non-regulated		30.9			289.3
	Other—non-regulated		3.1			31.7

Total sales			945.4			1,288.8

Cost of sales:
	Electricity—regulated		152.0			141.5
	Natural gas—regulated		407.8			275.6
	Electricity—non-regulated		58.1			116.7
	Natural gas—non-regulated		14.8			210.0
	Other—non-regulated		11.1			11.5

Total cost of sales			643.8			755.3

Gross profit			301.6			533.5

Operating expenses:
	Operating expense		295.5			358.1
	Restructuring charges		27.1			71.4
	Impairment charges and net loss on sale of assets		100.8			894.6
	Depreciation and amortization expense		85.5			78.4

Total operating expenses			508.9			1,402.5

Other income (expense):
	Equity in earnings of investments		61.1			68.3
	Minority interest in income of subsidiaries		—			4.2
	Other income		62.4			1.3

Total other income (expense)			123.5			73.8

Interest expense:
	Interest expense		144.2			86.4
	Minority interest in income of partnership and trust		—			11.1

Total interest expense			144.2			97.5

Loss from continuing operations before income taxes			(228.0	)		(892.7	)
Income tax benefit			(68.7	)		(95.7	)

Loss from continuing operations			(159.3	)		(797.0	)
Earnings from discontinued operations, net of tax			26.8			31.4

Net loss		$	(132.5	)	$	(765.6	)

Basic and diluted earnings (loss) per common share:
	Continuing operations	$	(.82	)	$	(5.71	)
	Discontinued operations		.14			.22

	Net loss	$	(.68	)	$	(5.49	)

Dividends per common share		$	—		$	..60

See accompanying notes to consolidated financial statements.

Aquila, Inc.

Consolidated Balance Sheets

In millions		June 30, 2003		December 31, 2002
		(Unaudited)

ASSETS
Current assets:
	Cash and cash equivalents	$	236.8	$	411.6
	Restricted cash		332.1		493.9
	Funds on deposit		480.3		310.3
	Accounts receivable, net		718.9		1,633.0
	Inventories and supplies		101.5		137.2
	Price risk management assets		472.6		545.2
	Prepayments and other		197.7		391.5
	Current assets of discontinued operations		151.6		151.5

Total current assets			2,691.5		4,074.2

	Property, plant and equipment, net		2,686.2		2,661.7
	Investments in unconsolidated subsidiaries		941.7		914.9
	Price risk management assets		744.8		491.6
	Goodwill, net		111.0		111.0
	Deferred charges and other assets		283.1		260.1
	Non-current assets of discontinued operations		907.2		745.7

Total Assets		$	8,365.5	$	9,259.2

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Current maturities of long-term debt	$	15.7	$	355.9
	Short-term debt		109.3		287.8
	Accounts payable		606.8		1,586.1
	Accrued liabilities		362.1		332.5
	Price risk management liabilities		410.4		469.5
	Current portion of long-term gas contracts		84.0		81.5
	Customer funds on deposit		348.7		242.8
	Current liabilities of discontinued operations		264.9		240.8

Total current liabilities			2,201.9		3,596.9

Long-term liabilities:
	Long-term debt, net		2,697.3		2,270.6
	Deferred income taxes and credits		409.2		423.0
	Price risk management liabilities		506.8		282.8
	Long-term gas contracts, net		627.7		671.2
	Minority interest		—		13.4
	Deferred credits		231.7		266.0
	Non-current liabilities of discontinued operations		130.2		127.4

Total long-term liabilities			4,602.9		4,054.4

Common shareholders' equity			1,560.7		1,607.9

Total Liabilities and Shareholders' Equity		$	8,365.5	$	9,259.2

See accompanying notes to consolidated financial statements.

Aquila, Inc.

Consolidated Statements of Comprehensive Income—Unaudited

	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2003			2002			2003			2002

Net loss	$	(80.6	)	$	(810.0	)	$	(132.5	)	$	(765.6	)
Unrealized translation adjustments, net of tax		26.2			24.5			87.2			21.6
Unrealized cash flow hedges, net of tax		1.4			(1.1	)		1.7			(10.6	)
Unrealized loss from available-for-sale securities		—			—			(7.3	)		—

Comprehensive loss	$	(53.0	)	$	(786.6	)	$	(50.9	)	$	(754.6	)

Aquila, Inc.

Consolidated Statements of Common Shareholders' Equity

In millions	June 30, 2003			December 31, 2002
	(Unaudited)

Common stock: authorized 400 million shares at June 30, 2003 and December 31, 2002, par value $1 per share; 195,074,441 shares issued at June 30, 2003 and 193,782,782 shares issued at December 31, 2002; authorized 20 million shares of Class A common stock, par value $1 per share, none issued	$	195.1		$	193.8
Premium on capital stock		3,161.0			3,158.6
Retained deficit		(1,844.0	)		(1,711.5	)
Treasury stock, at cost (4,532 and 7,443 shares at June 30, 2003 and December 31, 2002, respectively)		—			—
Accumulated other comprehensive income (losses)		48.6			(33.0	)

Total common shareholders' equity	$	1,560.7		$	1,607.9

See accompanying notes to consolidated financial statements.

Aquila, Inc.

Consolidated Statements of Cash Flows—Unaudited

				Six Months Ended June 30,
In millions				2003			2002
							(Restated— See Note 9)

Cash Flows From Operating Activities:
	Net loss			$	(132.5	)	$	(765.6	)
	Adjustments to reconcile net loss to net cash provided from (used for) operating activities:
		Depreciation and amortization expense			93.6			122.8
		Restructuring charges			27.1			71.8
		Cash paid for restructuring and impairment charges			(153.2	)		(1.4	)
		Impairment charges and net loss on sale of assets			100.8			894.6
		Net changes in price risk management assets and liabilities			4.1			200.3
		Deferred income taxes and investment tax credits			(63.3	)		(47.1	)
		Equity in earnings of investments			(61.1	)		(71.2	)
		Dividends and fees from investments			33.2			30.8
		Minority interests in income of subsidiaries			—			(4.2	)
		Changes in certain assets and liabilities, net of effects of acquisitions and divestitures:
			Restricted cash		(160.5	)		—
			Funds on deposit		(166.7	)		(20.4	)
			Accounts receivable/payable, net		(111.5	)		(29.4	)
			Accounts receivable sales programs		—			(195.5	)
			Inventories and supplies		34.3			22.6
			Prepayments and other		163.2			31.2
			Deferred charges and other assets		22.9			(12.2	)
			Accrued liabilities		135.3			(258.1	)
			Customer funds on deposit		104.6			65.2
			Deferred credits		(31.5	)		37.3
			Other		(68.1	)		(21.2	)

Cash provided from (used for) operating activities					(229.3	)		50.3

Cash Flows From Investing Activities:
	Network capital expenditures				(99.3	)		(131.0	)
	Merchant capital expenditures				(32.7	)		(127.7	)
	Net increase in merchant notes receivable				—			(51.4	)
	Investments in international businesses				—			(136.8	)
	Investments in communication services				(7.0	)		(20.5	)
	Cash proceeds received on sale of assets				402.5			60.9
	Merchant investment in unconsolidated subsidiaries				(44.5	)		(10.5	)
	Other				(27.5	)		44.1

Cash provided from (used for) investing activities					191.5			(372.9	)

Cash Flows From Financing Activities:
	Issuance of common stock				—			277.7
	Issuance of long-term debt				412.0			319.3
	Retirement of long-term debt				(433.8	)		(331.4	)
	Short-term borrowings (repayments), net				(79.4	)		170.3
	Cash paid on long-term gas contracts				(41.0	)		(40.8	)
	Cash dividends paid				—			(84.4	)
	Other				2.8			5.1

Cash provided from (used for) financing activities					(139.4	)		315.8

Decrease in cash and cash equivalents					(177.2	)		(6.8	)
Cash and cash equivalents at beginning of period (includes $30.1 million and $12.8 million, respectively, of cash included in current assets of discontinued operations)					441.7			262.9

Cash and cash equivalents at end of period (includes $27.7 million and $11.4 million, respectively, of cash included in current assets of discontinued operations)				$	264.5		$	256.1

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

Certain prior year amounts in the consolidated financial statements have been reclassified where necessary to conform to the 2003 presentation. In particular, sales and cost of sales have been reclassified to report energy trading gains and losses on a net basis pursuant to Emerging Issues Task Force Issue No. 02-3 (EITF No. 02-3), as discussed below under the caption "Energy Trading Activities." Also, as discussed in Note 4, the results of operations from certain assets that were sold in 2002 and early 2003 and those assets that are currently held for sale have been reclassified as discontinued operations in the accompanying balance sheets and statements of income for all periods presented.

Stock Based Compensation

We issue stock options to employees from time to time and account for these options under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25). All stock options issued are granted at the common stock's market price at date of issuance. This means we record no compensation expense related to stock options. We historically offered employees a stock purchase plan that enabled them to purchase our common stock at a 15% discount from the market price. This program was suspended during the second quarter of 2003.

Because we account for options and discounts under APB 25, we disclose a pro forma net loss and a basic and diluted loss per share as if we reflected the estimated fair value of options and discounts as compensation expense. Our pro forma net loss, basic and diluted loss per share are as follows:

		Three Months Ended June 30,						Six Months Ended June 30,
In millions, except per share amounts		2003			2002			2003			2002

Net loss:
	As reported	$	(80.6	)	$	(810.0	)	$	(132.5	)	$	(765.6	)
	Total stock-based employee compensation expense determined under fair value method, net of related tax		(1.3	)		(1.3	)		(2.8	)		(2.5	)

Pro forma net loss		$	(81.9	)	$	(811.3	)	$	(135.3	)	$	(768.1	)

Basic and diluted loss per share:
	As reported	$	(.41	)	$	(5.69	)	$	(.68	)	$	(5.49	)
	Pro forma		(.42	)		(5.70	)		(.70	)		(5.51	)

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

New Accounting Pronouncements

Energy Trading Activities

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

The following table reconciles gross sales and cost of sales previously reported to sales and cost of sales reported after the effects of EITF No. 02-3 and the reclassification of discontinued operations (discussed in Note 4):

In millions		Three Months Ended June 30, 2002			Six Months Ended June 30, 2002

Sales:
	Gross sales previously reported	$	9,654.3		$	18,515.6
	Sales netted per EITF No. 02-3		(8,914.9	)		(16,944.7	)
	Sales reclassified to discontinued operations		(149.7	)		(282.1	)

Reported sales		$	589.7		$	1,288.8

Cost of Sales:
	Gross cost of sales previously reported	$	9,318.2		$	17,831.6
	Cost of sales netted per EITF No. 02-3		(8,914.9	)		(16,944.7	)
	Cost of sales reclassified to discontinued operations		(74.7	)		(131.6	)

Reported cost of sales		$	328.6		$	755.3

Variable Interest Entities

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities, an interpretation of ARB No. 51." This interpretation addresses the consolidation by business enterprises of variable interest entities as defined in the interpretation. The interpretation applies immediately for variable interest entities created or obtained after January 31, 2003 and on July 1, 2003 for variable interest entities created prior to January 31, 2003. This interpretation is not expected to have a material impact on our financial position or results of operations.

Derivative Instruments

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

Financial Instruments

In May 2003, the FASB issued SFAS No. 150, "Accounting for Financial Instruments with Characteristics of both Liabilities and Equity" (SFAS 150). This statement establishes standards for the classification and measurement of certain financial instruments that have the characteristics of both liabilities and equities. It requires that an issuer classify a financial instrument that is within the scope of the standard as a liability. This standard is effective for all financial instruments entered into or modified after May 31, 2003 and for the first interim reporting period beginning after June 15, 2003. We believe the adoption of this standard will have no impact on our financial position or results of operations.

2. Restructuring Charges

We recorded the following restructuring charges:

		Three Months Ended June 30,					Six Months Ended June 30,
In millions		2003			2002		2003			2002

Domestic Networks:
	Severance costs	$	1.1		$	15.3	$	2.1		$	15.3
	Disposal of corporate aircraft		—			4.6		—			4.6

	Total Domestic Networks		1.1			19.9		2.1			19.9

Capacity Services:
	Interest rate swap reductions		17.8			—		23.1			—
	Severance costs		—			.6		—			.6

	Total Capacity Services		17.8			.6		23.1			.6

Wholesale Services:
	Severance costs		1.5			24.4		1.5			24.4
	Leasehold improvements and equipment		—			22.8		—			22.8
	Disposal of corporate aircraft		—			2.2		—			2.2
	Other		(.6	)		1.5		(.6	)		1.5

	Total Wholesale Services		.9			50.9		.9			50.9
Corporate and Other severance costs			1.0			—		1.0			—

Total restructuring charges		$	20.8		$	71.4	$	27.1		$	71.4

Severance Costs

We incurred severance costs of $1.1 million and $2.1 million, respectively, for the three and six months ended June 30, 2003, in connection with the restructuring of Everest Connections, our communications business within Domestic Networks. This resulted from a reduction of approximately 160 employees. We incurred an additional $1.5 million of severance costs in the second quarter of 2003 related to the continued wind down of our domestic and international energy trading operations in Wholesale Services.

In connection with the continuing alignment of our management team with our new strategic direction, we incurred approximately $1.0 million of severance costs in Corporate and Other in the second quarter of 2003.

During the second quarter of 2002, we incurred $40.3 million of total severance costs related to the restructuring of our Domestic Networks in order to more closely align it with its regulatory service areas and from the decision to exit our energy trading business. These actions resulted in the termination of approximately 840 energy trading employees, 500 Domestic Networks employees and 50 Corporate employees. These charges were expensed and accrued during the second quarter of 2002 and are being paid out bi-weekly over the term of the severance benefit.

Disposal of Corporate Aircraft

The $6.8 million charge for disposal of corporate aircraft in 2002 primarily included the termination of applicable lease agreements and losses associated with the sale of our corporate aircraft.

Interest Rate Swap Reductions

We incurred $17.8 million and $23.1 million of restructuring charges for the three and six months ended June 30, 2003, respectively, to exit portions of interest rate swaps related to our Clay County and

Piatt County construction financing arrangements. As debt related to these facilities was paid down, our interest rate swaps exceeded the outstanding debt. Thus we reduced our position and realized the loss associated with the cancelled portion of the swaps.

Leasehold Improvements and Equipment

During the second quarter of 2002, we also wrote down $22.8 million of leasehold improvements and equipment in our wholesale energy trading business that were no longer realizable based on management's best estimate of their fair value.

Restructuring Reserve Activity

The following is a summary of the activity for accrued restructuring charges for the six months ended June 30, 2003:

In millions

Severance Costs:
Accrued severance costs as of December 31, 2002		$	16.6
	Additional expense during the period		4.6
	Cash payments during the period		(16.3	)

Accrued severance costs as of June 30, 2003		$	4.9

Other Restructuring Costs (a):
Accrued other restructuring costs as of December 31, 2002		$	32.6
	Additional expense during the period		22.5
	Cash payments during the period		(31.4	)

Accrued other restructuring costs as of June 30, 2003		$	23.7

(a): The majority of this liability represents costs accrued for future unused leased office space which relate to leases with various terms through 2015.

3. Impairment Charges and Net Loss on Sale of Assets

We recorded the following impairment charges and net (gain) loss on sale of assets:

		Three Months Ended June 30,					Six Months Ended June 30,
In millions		2003			2002		2003			2002

Domestic Networks:
	Quanta Services	$	—		$	692.9	$	—		$	692.9
	Communications investments		—			23.1		—			23.1
	Other		—			—		(2.2	)		—

	Total Domestic Networks		—			716.0		(2.2	)		716.0

International Networks:
	Australia		2.6			—		2.6			—

	Total International Networks		2.6			—		2.6			—

Capacity Services:
	Acadia tolling agreement		105.5			—		105.5			—
	Turbines		(5.1	)		—		(5.1	)		—

	Total Capacity Services		100.4			—		100.4			—

Wholesale Services:
	Wholesale Services goodwill		—			178.6		—			178.6

	Total Wholesale Services		—			178.6		—			178.6

Total impairment charges and net loss on sale of assets		$	103.0		$	894.6	$	100.8		$	894.6

Quanta Services

At June 30, 2002, the cost basis in our 38% equity investment in Quanta Services was $26.69 per share and was significantly above the trading price of Quanta Services' stock. On July 1, 2002, Quanta Services announced that it had reduced its earnings forecast due to a continued decline in the telecommunications industry, reduced utility construction spending, and financial difficulties surrounding Quanta Services' two largest customers. Quanta Services' share price dropped to approximately $3.00 per share after this announcement. Because of these factors, and the termination of our proxy contest for control of Quanta Services in May 2002, we concluded that there was an other-than-temporary decline in the fair value of this investment. Accordingly, we wrote the investment down by $692.9 million before tax, or $627.3 million after tax, to its estimated fair value of $3.00 a share or $87.7 million in total.

Communications Investments

During the quarter ended June 30, 2002, we determined that certain cost and equity method investments in communications technology-related businesses were impaired based on continued losses in these businesses, their failure to achieve certain operational goals, the inability of these businesses to obtain additional capital, and our assessment of the long-term prospects of these businesses. Accordingly, we recorded a $23.1 million pretax, or $13.9 million after tax, impairment charge related to these investments.

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. In June, we retired $90.7 million of our $200.0 million 364-day secured credit facility with these proceeds. 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 $513.0 million. Approximately $109.3 million of these proceeds were used in July to retire the remaining balance outstanding under the 364-day secured credit facility. We expect to record a gain in the third quarter of 2003 in connection with this sale.

After fees, expenses and taxes, the sale of all of our Australian investments are expected to yield combined net cash proceeds of approximately $477.0 million.

Acadia Tolling Agreement

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

Turbines

During the second quarter of 2003, we completed the contract termination and sale of our remaining 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.

Wholesale Services Goodwill

In connection with our decision to exit our energy trading operations, we assessed our ability to realize the goodwill associated with our Wholesale Services business. This assessment was based on our best estimate of the value of this business in a liquidation, which we determined was less than the carrying value of its net assets. Because future earnings or sufficient sales proceeds could no longer support this asset, we wrote off the entire unamortized goodwill balance of $178.6 million in the second quarter of 2002.

4. Discontinued Operations

In 2002 and early 2003, we sold our Texas natural gas storage facility, our Texas and Mid-Continent natural gas pipeline systems, including our natural gas and natural gas liquids processing assets, our ownership interest in the Oasis Pipe Line Company, our coal terminal and handling facility (which are all included in our Capacity Services segment) and our Merchant loan portfolio (which is included in our Wholesale Services segment). In the second quarter of 2003, we sent out an information memorandum for the sale of our Canadian utility businesses (which are included in our International Networks segment) and began a process to solicit interested buyers. We received indications of interest in July 2003 and subject to an adequate sales price, expect to negotiate a definitive agreement in the third quarter of 2003 and close the sale in the first quarter of 2004, following the receipt of regulatory approvals and satisfaction of other closing conditions.

We have reported the results of operations from the above assets in discontinued operations in the Consolidated Statements of Income. The related assets and liabilities included in the sale of these

businesses, as detailed below, have been reclassified as current and non-current assets and liabilities of discontinued operations on the Consolidated Balance Sheets.

In millions		June 30, 2003		December 31, 2002

Current assets of discontinued operations:
	Cash and cash equivalents	$	27.7	$	30.1
	Other current assets		123.9		121.4

Total current assets of discontinued operations		$	151.6	$	151.5

Non-current assets of discontinued operations:
	Property, plant and equipment, net	$	652.8	$	519.1
	Goodwill, net		220.8		188.6
	Other non-current assets		33.6		38.0

Total non-current assets of discontinued operations		$	907.2	$	745.7

Current liabilities of discontinued operations:
	Current maturities of long-term debt	$	74.0	$	174.8
	Short-term debt		84.2		13.2
	Other current liabilities		106.7		52.8

Total current liabilities of discontinued operations		$	264.9	$	240.8

Non-current liabilities of discontinued operations:
	Long-term debt, net	$	130.2	$	127.4

Total non-current liabilities of discontinued operations		$	130.2	$	127.4

Operating results from our discontinued operations are as follows:

		Three Months Ended June 30,				Six Months Ended June 30,
In millions		2003		2002		2003			2002

Sales		$	67.8	$	149.7	$	105.1		$	282.1
Cost of sales			8.9		74.7		21.0			131.6

Gross profit			58.9		75.0		84.1			150.5

Operating expenses:
	Operating expense		23.2		37.0		48.0			72.3
	Restructuring charges		—		.4		—			.4
	Depreciation and amortization expense		11.0		22.7		8.1			44.4

Total operating expenses			34.2		60.1		56.1			117.1

Other income (expense):
	Equity in earnings of investments		—		1.8		—			2.9
	Other income		1.5		15.3		4.7			26.4

Earnings before interest and taxes			26.2		32.0		32.7			62.7
Interest expense (income)			1.3		5.6		(1.0	)		10.7

Earnings before income taxes			24.9		26.4		33.7			52.0
Income tax expense			10.4		10.9		6.9			20.6

Earnings from discontinued operations		$	14.5	$	15.5	$	26.8		$	31.4

5. Earnings (Loss) per Common Share

The table below shows how we calculated basic and diluted earnings (loss) per share. Basic earnings (loss) per share and basic weighted average shares are the starting point in calculating the dilutive measures. To calculate basic earnings (loss) per share, divide our net loss for the period by our weighted average shares outstanding, without adjusting for dilutive items. Diluted earnings (loss) per share is calculated by dividing our net loss, after assumed conversion of dilutive securities, by our weighted average shares outstanding, adjusted for the effect of dilutive securities. As a result of the net losses in the three and six months ended June 30, 2003 and 2002, the potential issuances of common stock for dilutive securities were considered anti-dilutive and therefore not included in the calculation of diluted earnings (loss) per share.

		Three Months Ended June 30,						Six Months Ended June 30,
In millions, except per share amounts		2003			2002			2003			2002

Loss from continuing operations		$	(95.1	)	$	(825.5	)	$	(159.3	)	$	(797.0	)
Earnings from discontinued operations			14.5			15.5			26.8			31.4

Net loss		$	(80.6	)	$	(810.0	)	$	(132.5	)	$	(765.6	)

Basic and diluted earnings (loss) per share:
	Loss from continuing operations	$	(.49	)	$	(5.80	)	$	(.82	)	$	(5.71	)
	Earnings from discontinued operations		.08			.11			.14			.22

	Net loss	$	(.41	)	$	(5.69	)	$	(.68	)	$	(5.49	)

Weighted average number of common shares used in basic and diluted earnings (loss) per share			194.6			142.3			194.3			139.5

6. Divestitures

Midlands

In May 2003, we signed an agreement to sell our 79.9% interest in Aquila Sterling Limited, the owner of Midlands Electricity plc, for approximately $56.0 million. Completion of the sale is subject to various conditions, including the successful redemption of the outstanding bonds issued by Avon Energy Partners Holdings, an Aquila Sterling subsidiary, at 86% of their par value plus accrued interest. If we do not close the sale of our investment by November 2003, the agreement to sell will terminate unless agreed otherwise by the parties.

7. Reportable Segment Reconciliation

Our reportable segment reconciliations are listed below.

		Three Months Ended June 30,						Six Months Ended June 30,
In millions		2003			2002			2003			2002

Sales:
	Domestic Networks	$	338.6		$	416.4		$	929.3		$	990.2
	International Networks		—			—			—			—

	Total Global Networks Group		338.6			416.4			929.3			990.2

	Capacity Services		25.4			110.0			20.1			166.6
	Wholesale Services		39.2			63.3			(4.0	)		132.0

	Total Merchant Services		64.6			173.3			16.1			298.6

Total Sales		$	403.2		$	589.7		$	945.4		$	1,288.8

EBIT:
	Domestic Networks	$	10.0		$	(718.3	)	$	80.6		$	(672.2	)
	International Networks		9.1			26.8			13.3			37.5

	Total Global Networks Group		19.1			(691.5	)		93.9			(634.7	)

	Capacity Services		(115.6	)		20.4			(164.3	)		22.6
	Wholesale Services		11.5			(191.2	)		(41.1	)		(169.6	)

	Total Merchant Services		(104.1	)		(170.8	)		(205.4	)		(147.0	)
	Corporate and Other		28.8			3.2			27.7			(13.5	)

Total EBIT			(56.2	)		(859.1	)		(83.8	)		(795.2	)
Interest expense			76.9			52.6			144.2			97.5

Loss from continuing operations before income taxes		$	(133.1	)	$	(911.7	)	$	(228.0	)	$	(892.7	)

In millions		June 30, 2003		December 31, 2002

Assets:
	Domestic Networks	$	2,800.3	$	2,666.5
	International Networks		1,715.3		1,607.1

	Total Global Networks Group		4,515.6		4,273.6

	Capacity Services		1,198.9		1,203.2
	Wholesale Services		2,332.4		3,092.1

	Total Merchant Services		3,531.3		4,295.3
	Corporate and Other		318.6		690.3

Total Assets		$	8,365.5	$	9,259.2

8. Financings

Revolving Credit Facility

In April 2002, we entered into a revolving credit facility totaling $650.0 million. The credit facility consisted of two $325.0 million credit agreements, one with a maturity of 364 days, and the other with a maturity of three years. In April 2003, the 364-day credit facility was repaid in full and the unused portion of the three-year credit facility was terminated. During the second quarter of 2003, we terminated the remainder of the three-year facility and replaced the letters of credit issued under it with new letters of credit issued under our letter of credit facility discussed below.

364-Day Secured Credit Facility

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

On May 12, 2003, we exercised our option under the 364-day financing to borrow the remaining $100.0 million available under the facility. The proceeds were used to terminate our Acadia tolling agreement as discussed in Note 3. We paid additional arrangement fees of $4.1 million for this borrowing.

As stated in Note 3, we retired $90.7 million of this borrowing in June 2003 with proceeds from the sale of our interest in AlintaGas. The remaining balance of $109.3 million was retired in July 2003 with proceeds from the sale of our interests in United Energy and Multinet Gas.

Three-Year Secured Credit Facility

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

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

We have also committed to use reasonable efforts to obtain approvals that would provide these lenders additional domestic utility assets as collateral for their loans. If, as a result of the addition of any such collateral, the value of the domestic regulated utility asset collateral securing the indenture exceeds 167% of the loan secured by the indenture, the pledge of the Canadian and independent power projects equity interest may be released and the interest rate would be reduced to LIBOR (which has a 3% floor) plus 5.00%. In April 2003, we filed applications with the state regulatory bodies in Colorado, Iowa, Kansas, Minnesota and Missouri requesting authority to pledge our utility assets located in their respective states. On July 11, 2003, the Colorado regulatory body authorized the use of our Colorado utility assets as additional collateral under the facility. We continue to work with the remaining states to obtain their approvals for the additional collateral.

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

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

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

In addition, the $430.0 million secured debt would become immediately due and payable if we do not complete an exchange offer, tender offer, refinancing or other retirement transaction with regard to 80% of our $250.0 million, 7% senior note series due July 15, 2004 and our $150.0 million, 6.875% senior note series due October 1, 2004, at least two weeks prior to their respective maturity dates. Among other restrictions, the three-year secured facility contains the following financial covenants:

(1): We must maintain a ratio of total debt to total capital of not more than .75 to 1.00 as of September 30, 2003 and December 31, 2003, decreasing to .70 to 1.00 for quarters ending after December 31, 2003.
(2): Beginning July 1, 2003, we must maintain a trailing 12-month ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) from pledged assets to interest expense related to these assets of no less than 1.05 to 1.00, increasing to 2.0 to 1.0 for quarters ending after December 31, 2004.
(3): Beginning July 1, 2003, we must maintain a trailing 12-month ratio of debt outstanding on our pledged assets to EBITDA from our pledged assets of no more than 10.5 to 1.0, decreasing to 5.5 to 1.0 for quarters ending after June 30, 2004.

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

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

We have presently allocated approximately $250 million of the loan balance as being necessary to support the working capital requirements of our domestic utility operations. In connection with our request to obtain approvals from state regulatory bodies to include additional utility assets as part of the collateral pool, we have made a commitment to ensure that portions of the loan that are not necessary for these utility operations be collateralized by non-utility assets. In some circumstances, this would necessitate a repayment of borrowings under the loan agreement that would result in the payment of a make-whole amount.

Letter of Credit Facility

In April 2003, we executed a 364-day Letter of Credit Agreement with a commercial bank. Under terms of the Agreement, the bank committed to initially issue letters of credit under the facility subject to a limit of $200.0 million outstanding at any one time. All letters of credit issued are fully secured by cash deposits with the bank. The committed amount automatically decreased to $175.0 million at June 30, 2003 and will decrease further to $150.0 million at December 31, 2003. At June 30, 2003, $80.2 million of letters of credit were outstanding under this facility.

Canadian Subsidiaries

On July 31, 2003, we closed on a $215.0 million, 364-day unsecured loan. The borrowers are Aquila Networks Canada Corp. (ANCC) and Aquila Networks Canada (Alberta) Ltd. (ANCA), each of which is an indirect wholly-owned subsidiary. At closing, ANCC borrowed $115.0 million and ANCA

borrowed $100.0 million. The interest rate on this financing is LIBOR (with 2.50% floor) plus 4.25%. Proceeds were used by ANCA to repay and terminate its existing 364-day credit agreement that matured on July 31, 2003 and a letter of credit facility. ANCC will use its proceeds to finance the capital expenditure and working capital requirements of its regulated utility subsidiaries, as well as repay certain bank debt of Aquila Networks Canada (British Columbia) Ltd. (ANCBC). The facilities will be repaid with the proceeds received in connection with the sale of its Canadian utility investments. We paid up-front arrangement fees of $4.3 million.

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

9. Restatement of Consolidated Statement of Cash Flow

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

In 2002, the EITF, in its deliberations regarding EITF No. 02-3, discussed a number of items related to energy trading and risk management activities. In order to more fully address certain of the items discussed, the EITF formed a working group. One of the items discussed by the working group was "prepaid gas contracts." These discussions included the cash flow presentation of contracts similar to our long-term gas contracts. Based on this discussion, and other accounting and industry discussions and guidance occurring in 2002, we believe that the current industry and accounting consensus is to report these contracts as financing activities in the statement of cash flows. As a result, we have reported these cash flows in accordance with the current accounting interpretations and guidance for all periods presented in our Consolidated Statements of Cash Flows. This resulted in a $40.8 million increase in Cash Flows From Operating Activities for the six months ended June 30, 2002, as compared to the amount previously reported. Cash Flows From Financing Activities changed by the corresponding amount, resulting in no change in total cash flow. This change had no impact on earnings or losses.

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

	Six Months Ended June 30, 2002
In millions	As Previously Reported			As Restated

Cash provided from operating activities	$	9.5		$	50.3
Cash used for investing activities		(372.9	)		(372.9	)
Cash provided from financing activities		356.6			315.8

Net decrease in cash and cash equivalents	$	(6.8	)	$	(6.8	)

10. Aries Power Project

MEP Pleasant Hill, LLC, our 50 percent-owned joint venture that owns and operates the Aries Power Project in Pleasant Hill, Missouri, was unable to refinance or repay $270.0 million of

construction loans prior to their June 26, 2003 maturity. In response to the default, the lenders have drawn on $75.0 million of letters of credit that we and our partner equally pledged to support the loans, reducing the loan balances to $195.0 million. Although the project is current on its interest payments and other operating expenses, the loans remain in default. The loans are non-recourse to Aquila and the default has no direct impact on our other credit arrangements or utility operations. We are currently working with our partner and lenders to cure the default. As of June 30, 2003, our investment balance in the Aries Power Project was $31.4 million.

11. Legal and Environmental Matters

On February 19, 2002, we filed a suit against Chubb Insurance Group, the issuer of surety bonds in support of certain of our long-term gas supply contracts. Previously, Chubb had demanded that it be released from its surety obligation of up to $531 million or, alternatively, that we post collateral to secure its obligation. We do not believe that Chubb is entitled to be released from its surety obligations or that we are obligated to post collateral to secure its obligations unless it is likely we will default on the contracts. Chubb has not alleged that we are likely to default on the contracts. If Chubb were to prevail, it would have a material adverse impact on our liquidity and financial position. We rely on other sureties in support of long-term gas supply contracts similar to those described above. There can be no assurance that these sureties will not make claims similar to those raised by Chubb. We have performed under these contracts since their inception and intend to continue to fully perform under these contracts.

A consolidated lawsuit was filed against us in federal court in Missouri in connection with our recombination with our Aquila Merchant subsidiary that occurred pursuant to an exchange offer completed in January 2002. The suit raised allegations concerning the lack of independent members on the board of directors of Aquila Merchant to negotiate the terms of the exchange offer on behalf of the public shareholders of Aquila Merchant. Persons holding certificates formerly representing approximately 1.8 million shares of Aquila Merchant common stock are also pursuing their appraisal rights in connection with the recombination. We do not believe that either of these actions will have an outcome materially adverse to us.

A number of companies that have engaged in energy trading activities, including us, have received requests from various regulatory agencies to furnish data and answer questions relating to the possible inaccurate reporting of gas trade information to various industry publications in 2000 and 2001. In response to such inquiries, we initiated a review of our reported information relative to recorded data and are fully cooperating with these investigations. Additionally, we have reported to the Federal Energy Regulatory Commission and the Commodity Futures Trading Commission (CFTC) that we have been unable to reconcile all of the gas trade data reported to various trade publications with the gas trade data in our internal records and that our former traders may have reported inaccurate information. We are continuing to work with the CFTC on this matter.

A lawsuit was filed against us and numerous other energy trading companies in November 2002 by the Lieutenant Governor of the State of California alleging that we misreported gas trade data that, in turn, affected the market price of electricity in California. Our motion to be dismissed from the lawsuit was granted by the court in the second quarter of 2003.

The Environmental Protection Agency (EPA) has been conducting enforcement initiatives nationwide, and recently has inquired at several coal-fired power plants operated by other companies in our region. These investigations are being made to determine whether modifications at those facilities were subject to New Source Review requirements (NSR) under the Clean Air Act. The EPA contends that power plants are required to update emission controls at the time of major maintenance or capital activity, and it has initiated civil enforcement actions in some cases. The EPA has not requested any information from our company in that regard, nor has it indicated that it intends to do so. We believe that the maintenance and capital activities performed at our power plants are routine and not subject to NSR. It is possible, if the EPA does pursue such action with our company, that our additional investment to comply could be material. We would expect to obtain recovery of such costs through rates.

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

AQUILA, INC.

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

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

FORWARD-LOOKING INFORMATION AND RISK FACTORS

This report contains forward-looking information, including statements that (i) we expect our utility rates to be increased in certain states where we have utility operations, and (ii) our long-term liquidity depends upon the sale of non-strategic assets, restructuring of generation capacity obligations, and the ability to raise additional capital through debt or equity markets and the ability to use regulated assets as collateral for debt. The words "may," "will," "should," "expect," "anticipate," "intend," "plan," "believe," "seek," "estimate," or the negative of these terms or similar expressions identify further forward-looking statements. Similar statements that identify our objectives, plans and goals are forward-looking statements.

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

•: Regulatory commissions may refuse to approve some or all of the increases we have requested to our utility rates.
•: Counterparties may default on their obligations to pay, supply commodities, return collateral to us or to meet their obligations under commercial contracts, including those designed to hedge against movements in commodity prices.
•: Our credit ratings and financial condition will limit our ability to access the capital markets we historically used to refinance our debt. Because we recently pledged a significant portion of our assets as collateral for loans, it will be difficult for us to obtain additional financing. We must obtain regulatory approvals to use the majority of our remaining unencumbered assets as collateral for additional loans.
•: If our financial condition improves, market prices for our long-term debt may increase and limit our ability to repurchase it. Our new credit agreements and commitments to state regulatory bodies require us to use a portion of the proceeds from the sale of our assets to reduce our obligations to those lenders before retiring other debt.

•: Our commitments under long-term gas delivery contracts and capacity generation contracts will generate significant losses and negative cash flows for an extended period of time. Because these obligations represent favorable contracts to the counterparties, absent a risk of our default, they may be unwilling to restructure or sell the contracts.
•: There are numerous ongoing state and federal investigations of the trading activities of companies that participated in the energy trading industry, including us. Companies that have violated laws or rules of the investigating agencies have been required to pay significant amounts to settle these investigations. Even if no wrongdoing is found, we will incur legal and forensic accounting costs associated with complying with the discovery requests of the investigating bodies.
•: Proceeds from future asset sales could be lower than book value which would generate additional losses and may not adequately reduce our debt to levels where our operations are able to generate sufficient cash flows to service our remaining debt.

RESULTS OF OPERATIONS

Financial Review

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

The use of EBIT as a performance measure is not meant to be considered an alternative to net income or cash flows from operating activities, which are determined in accordance with generally accepted accounting principles (GAAP), as an indicator of operating performance or as a measure of

liquidity, or other performance measures used under GAAP. In addition, the term may not be comparable to similarly titled measures used by other companies.

		Three Months Ended June 30,						Six Months Ended June 30,
In millions		2003			2002			2003			2002

Earnings (Loss) Before Interest and Taxes:
	Domestic Networks	$	10.0		$	(718.3	)	$	80.6		$	(672.2	)
	International Networks		9.1			26.8			13.3			37.5

	Total Global Networks Group		19.1			(691.5	)		93.9			(634.7	)

	Capacity Services		(115.6	)		20.4			(164.3	)		22.6
	Wholesale Services		11.5			(191.2	)		(41.1	)		(169.6	)

	Total Merchant Services		(104.1	)		(170.8	)		(205.4	)		(147.0	)
	Corporate and Other		28.8			3.2			27.7			(13.5	)

Total EBIT			(56.2	)		(859.1	)		(83.8	)		(795.2	)
Interest expense			76.9			52.6			144.2			97.5
Income tax benefit			(38.0	)		(86.2	)		(68.7	)		(95.7	)

Loss from continuing operations			(95.1	)		(825.5	)		(159.3	)		(797.0	)
Earnings from discontinued operations, net of tax			14.5			15.5			26.8			31.4

Net loss		$	(80.6	)	$	(810.0	)	$	(132.5	)	$	(765.6	)

Discontinued Operations

As further discussed in Note 4 to the Consolidated Financial Statements, we have reported the results of operations of the following assets in discontinued operations in the Consolidated Statements of Income: (1) our Texas natural gas storage facility, our Texas and Mid-Continent natural gas pipeline systems, including our natural gas and natural gas liquids processing assets and our ownership interest in the Oasis Pipe Line Company, our coal terminal and handling facility and our Merchant loan portfolio that were all sold in 2002 and early 2003, and (2) our Canadian network businesses that we

are currently planning to sell. The unaudited operating results of our operations that are considered discontinued operations for accounting purposes are as follows:

		Three Months Ended June 30,				Six Months Ended June 30,
In millions		2003		2002		2003			2002

Sales		$	67.8	$	149.7	$	105.1		$	282.1
Cost of sales			8.9		74.7		21.0			131.6

Gross profit			58.9		75.0		84.1			150.5

Operating expenses:
	Operating expense		23.2		37.0		48.0			72.3
	Restructuring charges		—		.4		—			.4
	Depreciation and amortization expense		11.0		22.7		8.1			44.4

Total operating expenses			34.2		60.1		56.1			117.1

Other income (expense):
	Equity in earnings of investments		—		1.8		—			2.9
	Other income		1.5		15.3		4.7			26.4

Earnings before interest and taxes			26.2		32.0		32.7			62.7
Interest expense (income)			1.3		5.6		(1.0	)		10.7

Earnings before income taxes			24.9		26.4		33.7			52.0
Income tax expense			10.4		10.9		6.9			20.6

Earnings from discontinued operations		$	14.5	$	15.5	$	26.8		$	31.4

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit decreased $81.9 million, $65.8 million and $16.1 million, respectively, in 2003 compared to 2002. These decreases were primarily due to the sale of our gas gathering and pipeline assets and our coal handling facility in the fourth quarter of 2002.

Operating Expense

Operating expense decreased $13.8 million in 2003 compared to 2002 primarily due to the sale of our gas gathering and pipeline assets, our Merchant loan portfolio and our coal handling facility in the fourth quarter of 2002.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $11.7 million in 2003 compared to 2002. Approximately $7.8 million of the decrease was due to the sale of our gas gathering and pipeline assets and our coal handling facility in the fourth quarter of 2002. The remaining decrease was primarily due to the decision by the Alberta Energy and Utility Board (AEUB) to reduce the depreciation rates on most of our distribution assets in Alberta.

Other Income

Other income decreased $13.8 million in 2003 compared to 2002 primarily due to the sale of our Merchant loan portfolio in the fourth quarter of 2002.

Interest Expense (Income)

Interest expense (income) decreased $4.3 million in 2003 compared to 2002 primarily due to the retirement of $85.3 million of Canadian bank borrowings in April 2003.

Year-to-Date

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit decreased $177.0 million, $110.6 million and $66.4 million, respectively, in 2003 compared to 2002. These decreases were primarily due to the sale of our gas gathering and pipeline assets and our coal handling facility in the fourth quarter of 2002. In addition, sales and gross profit for our Canadian network operations decreased $30.0 million and $27.0 million primarily due to the decision by the AEUB to decrease our 2002 and 2003 customer billing rates.

Operating Expense

Operating expense decreased $24.3 million in 2003 compared to 2002 primarily due to the sale of our gas gathering and pipeline assets, our Merchant loan portfolio and our coal handling facility in 2002 and early 2003.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased $36.3 million in 2003 compared to 2002. Approximately $15.4 million of the decrease was due to the sale of our gas gathering and pipeline assets and our coal handling facility in the fourth quarter of 2002. The remaining decrease was primarily due to the decision by the AEUB to reduce the depreciation rates of most of our distribution assets in Alberta.

Other Income

Other income decreased $21.7 million in 2003 compared to 2002 primarily due to the sale of our Merchant loan portfolio in the fourth quarter of 2002.

Interest Expense (Income)

Interest expense (income) decreased $11.7 million due to the retirement of $85.3 million of Canadian bank borrowings in April 2003 and an increase in interest received on intercompany loans to continuing operations in 2003.

Income Tax Expense

Income tax expense decreased $13.7 million primarily due to reduced earnings in 2003 compared to 2002 and the effect of the AEUB decision that decreased sales and depreciation. However, only the sales impact is tax affected for Canadian regulatory purposes.

DOMESTIC NETWORKS

The table below summarizes the operations of our Domestic Networks.

		Three Months Ended June 30,					Six Months Ended June 30,
Dollars in millions		2003		2002			2003			2002

Sales		$	338.6	$	416.4		$	929.3		$	990.2
Cost of sales			192.5		257.8			579.7			638.6

Gross profit			146.1		158.6			349.6			351.6

Operating expenses:
	Operating expense		103.8		107.0			204.3			232.1
	Restructuring charges		1.1		19.9			2.1			19.9
	Impairment charges and net loss (gain) on sale of assets		—		716.0			(2.2	)		716.0
	Depreciation and amortization expense		31.7		34.4			65.1			69.6

Total operating expenses			136.6		877.3			269.3			1,037.6

Other income (expense):
	Equity in earnings (loss) of investments		—		(3.3	)		—			4.6
	Minority interest in income of subsidiaries		—		1.7			—			4.2
	Other income		.5		2.0			.3			5.0

Earnings (loss) before interest and taxes		$	10.0	$	(718.3	)	$	80.6		$	(672.2	)

Electric sales and transportation volumes (GWh)			2,679.7		3,048.6			5,507.2			5,970.6
Gas sales and transportation volumes (Bcf)			43.1		46.6			131.5			128.5
Electric customers at end of period								442,000			436,000
Gas customers at end of period								884,000			876,000

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit for the Domestic Networks businesses decreased $77.8 million, $65.3 million and $12.5 million, respectively, in 2003 compared to 2002. These decreases were primarily due to the following factors:

•: Sales and cost of sales for our regulated gas utilities increased approximately $28.3 million and $26.3 million, respectively, for a net increase in gross profit of $2.0 million. Regulated gas utility sales and cost of sales increased due to a 30% 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 does not have a corresponding impact on gross profit. The increase in gross profit for our regulated gas utilities was the result of $2.1 million of interim rate increases in Michigan and Iowa.
•: Regulated electric utility sales and gross profit decreased $11.0 million and $13.1 million, respectively, in 2003 compared to 2002, while cost of sales increased $2.1 million. Regulated electric sales and gross profit decreased due to milder weather and decreased off-system sales. Cost of sales increased due to the higher cost of natural gas used to fuel our power plants resulting in a further reduction in gross profit.
•: Non-regulated gas sales, cost of sales and gross profit decreased $100.5 million, $93.2 million and $7.3 million, respectively, in 2003 compared to 2002, primarily as the result of the sale of our non-regulated wholesale gas operations in 2002.

•: Other non-regulated sales, cost of sales and gross profit were higher by $7.3 million, $2.4 million and $4.9 million higher, respectively, in 2003 due to an increase in customers at Everest Connections.

Restructuring Charges

Restructuring charges decreased $18.8 million in 2003 compared to 2002. In the second quarter of 2003, we completed the restructuring of the operations of Everest Connections resulting in the termination of a total of approximately 160 employees and $1.1 million of severance costs.

We restructured our domestic utility business in the second quarter of 2002 to more closely align it with our state service areas. In connection with this restructuring, we incurred $19.9 million in costs, primarily in the form of severance for terminated employees and the disposition of our corporate aircraft operation.

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

As further discussed in Note 3 to the Consolidated Financial Statements, Domestic Networks incurred $716.0 million of losses resulting from impairments in 2002. The impairments consisted of $692.9 million and $23.l million related to our investments in Quanta Services and other communication technology investments, respectively.

Equity in Earnings (Losses) of Investments

Equity in earnings (losses) of investments increased $3.3 million in 2003 compared to 2002. Our share of Quanta Services' loss in the second quarter of 2002 was $3.1 million. Our remaining investment in Quanta Services was sold during the first quarter of 2003.

Year-to-Date

Sales, Cost of Sales and Gross Profit

Sales, cost of sales and gross profit for the Domestic Networks businesses decreased $60.9 million, $58.9 million and $2.0 million, respectively, in 2003 compared to 2002. These decreases were primarily due to the following factors:

•: Sales and cost of sales for our regulated gas utilities increased approximately $151.6 million and $132.2 million, respectively, for a net increase in gross profit of $19.4 million. Regulated gas utility sales and cost of sales increased due to a 31% increase in natural gas prices. However, because gas purchase costs for our gas utility operations are passed through to our customers, the change in gas prices did not have a corresponding impact on gross profit. Gross profit for our regulated gas utilities increased due to $8.6 million of interim rate increases in Michigan and Iowa and increased volumes delivered due to colder than normal weather in the first quarter of 2003.
•: Regulated electric utility sales and cost of sales increased $1.6 million and $10.5 million, respectively, in 2003 compared to 2002, while gross profit decreased $8.9 million. Increased sales, cost of sales and gross profit from customer growth were offset by reduced volumes resulting from milder weather in the second quarter of 2003 and decreased off-system sales. Cost of sales increased due to the higher cost of natural gas used to fuel our power plants resulting in a further reduction in gross profit.
•: Non-regulated gas sales, cost of sales and gross profit decreased $217.4 million, $201.2 million and $16.2 million, respectively, in 2003 compared to 2002, primarily as the result of the sale of our non-regulated wholesale gas operations in 2002.

•: Other non-regulated sales, cost of sales and gross profit were higher by $12.2 million, $4.0 million and $8.2 million, respectively, in 2003 due to an increase in customers at Everest Connections.

Operating Expense

Operating expense decreased $27.8 million in 2003 compared to 2002, primarily due to labor, benefit savings and lower administrative expenses resulting from our restructuring in 2002.

Restructuring Charges

Restructuring charges decreased $17.8 million in 2003 compared to 2002. In the first half of 2003, we completed the restructuring of the operations of Everest Connections resulting in the termination of a total of approximately 160 employees and $2.1 million of severance costs.

Equity in Earnings (Losses) of Investments

Equity in earnings (losses) of investments decreased $4.6 million in 2003 compared to 2002. The decrease was primarily due to the sale of our equity interest in Quanta Services during the latter half of 2002 that reduced our ownership to 10.2% at December 31, 2002. Due to our reduced ownership, we could no longer record equity earnings. Our remaining investment was sold during the first quarter of 2003.

Other Income

Other income decreased $4.7 million in 2003 compared to 2002, primarily due to lower interest income and gains on sales of other assets in 2002.

Regulatory Matters

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

In millions	Type of service	Date Requested	Amount Requested		Amount Approved

Minnesota	Gas	8/2000	$	9.8	$	5.7
Iowa	Gas	6/2002		9.3		4.3
Michigan	Gas	8/2002		14.3		8.4
Colorado	Electric	10/2002		23.4		16.0
Nebraska	Gas	6/2003		9.9		Pending
Missouri	Electric	7/2003		80.9		Pending
Missouri	Gas	8/2003		6.4		Pending

2003 Regulatory Activity

A settlement was reached with the intervenors in the Minnesota rate case for $5.7 million. The settlement was approved by the Commission in July 2003.

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

In August 2002, we filed for a $14.3 million general rate increase in Michigan. We received approval to place an interim increase of $8.2 million into effect as of December 2002. We reached a settlement with the Commission staff and other intervening parties for an increase of $9.1 million. This

settlement was approved by the Commission in March 2003 and the new rates were effective in second quarter 2003. This increase was partially offset by a separate depreciation case whereby our annual rates were reduced by $.7 million. This decrease relates to our depreciation rates, which reduced cash flow but had little impact on earnings.

In October 2002, we filed for a $23.4 million increase in our Colorado electric rates. In April 2003, we reached a settlement with the Commission staff and other intervening parties for an increase of $16.0 million. This settlement was approved by the Commission and new rates were effective beginning in June 2003.

In June 2003, we filed for a total of $9.9 million of gas rate increases in three rate areas of Nebraska. We expect interim rates to be effective in October 2003, with hearings to be held regarding each request and decisions rendered 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. We expect hearings to be held in February 2004.

In August 2003, we filed for a rate case 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. We expect hearings in March 2004.

INTERNATIONAL NETWORKS

The operating results for our Canadian Networks have been reclassified as discontinued operations for all periods presented. The table below summarizes our remaining operations in International Networks, including our equity method investments in Australia, New Zealand (sold in the fourth quarter of 2002) and the United Kingdom.

		Three Months Ended June 30,				Six Months Ended June 30,
In millions		2003		2002		2003		2002

Operating expenses:
	Operating expense	$	3.7	$	2.5	$	6.7	$	4.5
	Impairment charges and net loss on sale of assets		2.6		—		2.6		—

Total operating expenses			6.3		2.5		9.3		4.5

Other income (expense):
	Equity in earnings of investments		8.9		28.0		14.1		40.4
	Other income		6.5		1.3		8.5		1.6

Earnings before interest and taxes		$	9.1	$	26.8	$	13.3	$	37.5

Quarter-to-Quarter

Equity in Earnings of Investments

Equity in earnings of investments decreased $19.1 million in 2003 compared to 2002. This decrease was primarily due to the October 2002 sale of our interest in UnitedNetworks Limited in New Zealand, which contributed equity earnings of $9.3 million in the second quarter of 2002. We recorded no equity earnings from our investment in Midlands Electricity plc (our United Kingdom electric network) in the second quarter of 2003. Our share of undistributed net earnings from Midlands was $19.9 million in the second quarter of 2003. However, as we stated in our 2002 Form 10-K, we did not recognize the earnings from this investment due to regulatory limitations on cash payments by Midlands to its owners. We intend to record equity earnings and management fees from this investment only to the extent cash is received. In the second quarter of 2002, we recorded equity earnings of $8.4 million from Midlands.

Other Income

Other income increased $5.2 million in 2003 compared to 2002. This increase was primarily due to $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 payable by a Canadian subsidiary and $3.0 million of foreign currency gains in Australia. This increase was partially offset by $9.3 million of cost related to a put option intended to protect us from unfavorable currency movement on the Australian sale proceeds.

Year-to-Date

Equity in Earnings of Investments

Equity in earnings of investments decreased $26.3 million in 2003 compared to 2002. This decrease was primarily due to the October 2002 sale of our interest in UnitedNetworks Limited in New Zealand, which contributed equity earnings of $17.7 million in the first six months of 2002. We recorded no equity earnings from our investment in Midlands in 2003 for the reasons discussed above. Our share of undistributed net earnings from Midlands was $34.1 million in 2003. During 2002, we recorded equity earnings of $8.4 million related to Midlands.

Other Income

Other income increased $6.9 million in 2003 compared to 2002. This increase was primarily due to $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 payable by a Canadian subsidiary and $5.1 million of foreign currency gains in Australia. This increase was partially offset by $9.3 million of cost related to a put option intended to protect us from unfavorable currency movement on the Australian sale proceeds.

Current Operating Developments

Australia. In April 2003, we agreed 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 Limited and received approximately $97.0 million in cash proceeds in May and July. In June, we retired $90.7 million of our $200.0 million 364-day secured credit facility with these proceeds. We recorded a loss of $2.6 million in connection with this sale in the second quarter of 2003.

In July 2003, we completed the sale of our interests in United Energy and Multinet Gas and received additional cash proceeds of $513.0 million. Approximately $109.3 million of these proceeds were used to retire the remaining balance outstanding under our 364-day secured credit facility. We expect to record a gain in the third quarter of 2003 in connection with this sale.

After fees, expenses and taxes, the sale of all of our Australian investments are expected to yield combined net cash proceeds of approximately $477.0 million.

Midlands. In May 2003, we signed an agreement to sell our 79.9% ownership in Aquila Sterling Limited, the owner of Midlands Electricity plc, for approximately $56.0 million. Completion of the sale is subject to various conditions, including the successful redemption of outstanding bonds issued by Avon Energy Partners Holdings, an Aquila Sterling subsidiary, at 86% of their par value plus accrued interest. If we do not close the sale of our investment by November 2003, the agreement to sell will terminate unless agreed otherwise by the parties.

Canada. In the second quarter of 2003, we sent out an information memorandum for the sale of our Canadian utility businesses and began a process to solicit interested buyers. We received indications of interest in July 2003 and, subject to our receipt of an adequate offer, expect to negotiate a definitive agreement in the third quarter of 2003 and close the sale in the first quarter of 2004, following the receipt of regulatory approvals and satisfaction of other closing conditions.

CAPACITY SERVICES

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

		Three Months Ended June 30,					Six Months Ended June 30,
In millions		2003			2002		2003			2002

Sales		$	25.4		$	110.0	$	20.1		$	166.6
Cost of sales			32.2			70.8		64.1			116.7

Gross profit (loss)			(6.8	)		39.2		(44.0	)		49.9

Operating expenses:
	Operating expense		12.4			28.3		24.1			46.7
	Restructuring charges		17.8			.6		23.1			.6
	Impairment charges and net loss on sale of assets		100.4			—		100.4			—
	Depreciation and amortization expense		5.3			2.0		19.4			4.1

Total operating expenses			135.9			30.9		167.0			51.4

Other income (expense):
	Equity in earnings of investments		27.7			11.3		46.9			23.3
	Other income (expense)		(.6	)		.8		(.2	)		.8

Earnings (loss) before interest and taxes		$	(115.6	)	$	20.4	$	(164.3	)	$	22.6

Quarter-to-Quarter

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for our Capacity Services operations decreased approximately $84.6 million and $38.6 million, respectively, in 2003 compared to 2002, resulting in a decrease in gross profit of $46.0 million. These decreases were primarily due to the following factors:

•: Sales and cost of sales were approximately $61.7 and $42.6 million lower, respectively, as higher natural gas prices used for fuel in our merchant power plants made it uneconomical to operate the plants in the second quarter of 2003 compared to the second quarter of 2002.
•: In 2002 we generated approximately $28.6 million of favorable mark-to-market gains. As liquidity and electricity prices have since declined in the forward market, these gains did not recur in 2003.
•: In connection with our merchant power plants, we make fixed capacity payments evenly throughout the year. For the second quarter of 2003, capacity payments increased by $4.6 million compared to 2002 as new plants became operational late in 2002, resulting in an increase in cost of sales. This additional capacity was utilized on a limited basis at prices that were not sufficient to cover the fixed lease payments.

Operating Expense

Operating expense decreased $15.9 million primarily due to labor, benefit savings and lower corporate costs resulting from the restructuring of this business in 2002.

Restructuring Charges

In the second quarter of 2003, we recorded restructuring charges of $17.8 million relating to 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, our swaps were in excess of our outstanding debt. We therefore reduced our position and realized the loss associated with the cancelled portion of the swaps.

Impairment Charges and Net Loss on Sale of Assets

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

Equity in Earnings of Investments

Equity in earnings of investments increased $16.4 million mainly due to $15.1 million of increased earnings resulting from mark-to-market gains occurring at the operating level of one of our equity investments. These gains are non-cash mark-to-market gains that will reverse over time as power is delivered.

Year-to-Date

Sales, Cost of Sales and Gross Profit

Sales and cost of sales for our Capacity Services operations decreased approximately $146.5 million and $52.6 million, respectively, in 2003 compared to 2002, resulting in a decrease in gross profit of $93.9 million. These decreases were primarily due to the following factors:

•: Sales and cost of sales were approximately $93.7 million and $69.3 million lower, respectively, as higher natural gas prices used for fuel in our merchant power plants made it uneconomical to operate the plants in the first half of 2003 compared to the first half of 2002.
•: In 2002 we generated approximately $50.0 million of favorable mark-to-market gains. As liquidity and electricity prices have since declined in the forward market, these gains did not recur in 2003.
•: In connection with our merchant power plants, we make fixed capacity payments evenly throughout the year. For the first half of 2003, capacity payments increased by $16.1 million compared to 2002 as new plants became operational late in 2002, resulting in an increase in cost of sales. This additional capacity was utilized on a limited basis at prices that were not sufficient to cover the fixed lease payments.

Operating Expense

Operating expense decreased $22.6 million primarily due to labor, benefit savings and lower corporate costs resulting from the restructuring of this business in 2002.

Restructuring Charges

During the first six months of 2003, we recorded restructuring charges of $23.1 million relating to 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, our swaps were in excess of our outstanding debt. We therefore reduced our position and realized the loss associated with the cancelled portion of the swaps.

Impairment Charges and Net Loss on Sale of Assets

In May 2003, we terminated our 20-year tolling contract for the Acadia power plant and made a termination payment of $105.5 million. Partially offsetting the termination payment was a $5.1 million

gain related to the contract termination and sale of our remaining turbines that we had previously written down to estimated fair value in 2002.

Depreciation and Amortization Expense

Depreciation and amortization expense increased $15.3 million in 2003 compared to 2002. This increase was primarily due to a change in the estimated amortizable life of certain plant premiums relating to our acquisition of GPU International in 2000 that contributed $11.4 million of the increase. The start of commercial operations at two owned power plants contributed an additional $4.5 million of depreciation and amortization expense.

Equity in Earnings of Investments

Equity in earnings of investments increased $23.6 million mainly due to $29.0 million of increased earnings resulting from mark-to-market gains occurring at the operating level of one of our equity investments. These gains are non-cash mark-to-market gains that will reverse over time as power is delivered. These gains were offset in part by the sale of our Lockport investment that contributed $3.8 million of equity earnings in 2002.

Earnings Trend and Impact of Changing Business Environment

The merchant energy sector has been negatively impacted by the increase in generation capacity that became operational in 2002 and by the continued construction of additional power plants. This increase in supply has placed downward pressure on power prices and subsequently the value of unsold merchant generation capacity. As a result of the above factors, we do not expect our Capacity Services unit to be profitable in the next two to three years.

We attempt to optimize and hedge our power plants with forward contracts which qualify as derivative instruments. When we enter into these positions, 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 cash flow.

Current Operating Development

Independent Power Plants. We are exploring the possible sale of our interest in our contracted power plants. We received indications of interest from potential buyers in July 2003 and will begin a due diligence process with selected parties. If the binding bids from potential buyers are deemed adequate, we will proceed with the sale process and expect to close a sale by December 2003, subject to customary closing conditions.

WHOLESALE SERVICES

The table below summarizes the operations of our domestic and international Wholesale Services businesses.

		Three Months Ended June 30,					Six Months Ended June 30,
In millions		2003		2002			2003			2002

Sales		$	39.2	$	63.3		$	(4.0	)	$	132.0
Cost of sales			—		—			—			—

Gross profit (loss)			39.2		63.3			(4.0	)		132.0

Operating expenses:
	Operating expense		26.9		25.0			36.4			70.3
	Restructuring charges		.9		50.9			.9			50.9
	Impairment charges and net loss on sale of assets		—		178.6			—			178.6
	Depreciation and amortization expense		.9		2.5			1.6			4.7

Total operating expenses			28.7		257.0			38.9			304.5
Other income			1.0		2.5			1.8			2.9

Earnings (loss) before interest and taxes		$	11.5	$	(191.2	)	$	(41.1	)	$	(169.6	)

As a result of the implementation of EITF No. 02-3 (which requires that all gains and losses on energy trading contracts be reported net in sales), all Wholesale Services' sales are reported net for all periods presented. To the extent losses exceeded gains, sales are shown as a negative number.

Quarter-to-Quarter

Sales and Gross Profit

Sales and gross profit for our Wholesale Services operations decreased by $24.1 million, primarily due to the following factors:

•: Late in the second quarter of 2002, we announced that we were exiting the wholesale energy trading business. Thus, in 2003, we were not adding new or speculative positions to our trading portfolio and therefore had limited opportunities for earnings.
•: Included in the $39.2 million of 2003 gross profit was $47.7 million of non-cash earnings related to our portfolio. Substantially all of these earnings relate to our long-term gas contracts. During the quarter, average gas prices rose over the life of these contracts by $.63 per MMbtu, which caused both the price risk management asset and price risk management liability related to these contracts to increase in value. However, because our price risk management liabilities are discounted based on our credit standing, versus the receivable side of these transactions which are discounted at our counterparties' credit ratings (which on average are substantially higher than our credit rating), non-cash mark-to-market earnings were created. The discounting of these liabilities and receivables is in accordance with SFAS 133 and is more fully described in Statement of Financial Accounting Concepts No. 7, "Using Cash Flow Information and Present Value in Accounting Measurement" (SFAS Concept 7).
•: In 2002, we recorded $34.0 million of similar mark-to-market earnings. However, the increase in earnings was attributable to our credit rating downgrades versus higher gas prices.

Operating Expense

Operating expense increased $1.9 million primarily due to regulatory review costs in the second quarter of 2003, partially offset by labor, benefit savings and related operating cost reductions resulting from the exit from our wholesale energy trading operations in 2002.

Restructuring Charges

In connection with the exit from our wholesale energy trading business, we incurred $50.9 million of restructuring charges in the second quarter of 2002. These charges mainly included $24.4 million of severance and retention payments to terminated employees and $22.8 million of excess leasehold improvements and equipment that were expensed when we vacated the related leased properties.

Impairment Charges and Net Loss on Sale of Assets

Impairment charges and net loss on sale of assets in the second quarter of 2002 consisted of an impairment charge of $178.6 million related to goodwill associated with Wholesale Services that became unrealizable due to our exit from wholesale energy trading.

Year-to-Date

Sales and Gross Profit

Sales and gross profit for our Wholesale Services operations decreased by $136.0 million, primarily due to the following factors:

•: In the second quarter of 2002, we announced that we were exiting the wholesale energy trading business. Thus, in 2003, we were not adding new or speculative positions to our trading portfolio and therefore had limited opportunities for earnings.
•: Included in the $4.0 million loss in 2003 was approximately $27.0 million of non-cash losses related to the sale of all of our capacity under certain long-term gas transportation agreements at substantially less than our future commitments. The loss was recognized for accounting purposes; however, the cash associated with the loss will be paid out over the term of the contracts. In addition, we recorded a $5.5 million loss related to terminating additional trading contracts.
•: Also included in the $4.0 million loss in 2003 was approximately $67.0 million of non-cash earnings related to our portfolio. Substantially all of these earnings relate to our long-term gas contracts. During the first six months, average gas prices rose over the life of these contracts by $.90 per MMbtu, which caused both the price risk management asset and price risk management liability related to these contracts to increase in value. However, because our price risk management liabilities are discounted based on our credit standing, versus the receivable side of these transactions which are discounted at our counterparties' credit ratings (which on average are substantially higher than our credit rating), non-cash mark-to-market earnings were created. The discounting of these liabilities and receivables is in accordance with SFAS 133 and is more fully described in SFAS Concept 7.
•: In 2002, we recorded $34.0 million of similar mark-to-market earnings. However, the increase in earnings was attributable to our credit rating downgrades versus higher gas prices.
•: As of June 30, 2003, we have recorded $110.9 million of mark-to-market gains related to increasing gas prices and the widening of our credit spreads between us and our counterparties. Substantially all of these gains relate to our long-term gas contracts discussed above. These non-cash gains will be reversed in later periods as contracts settle, our credit rating improves and/or as gas prices decline.
•: Our remaining 2003 margin losses mainly stem from unfavorable mark-to-market losses on open positions and $23.7 million of unfavorable settlements related to our European merchant operation as we continue to wind down that business.

Operating Expense

Operating expense decreased $33.9 million primarily due to labor, benefit savings and related operating cost reductions resulting from the exit from our wholesale energy trading operations in 2002, partially offset by regulatory review costs in the second quarter of 2003.

Restructuring Charges

Impairment Charges and Net Loss on Sale of Assets

Impairment charges and net loss on sale of assets in 2002 consisted of an impairment charge of $178.6 million related to goodwill associated with Wholesale Services that became unrealizable due to our exit from wholesale energy trading.

CORPORATE AND OTHER

The table below summarizes our Corporate and Other expenses and other income.

		Three Months Ended June 30,						Six Months Ended June 30,
In millions		2003			2002			2003			2002

Operating expenses:
	Operating expense	$	5.8		$	(6.0	)	$	24.0		$	4.5
	Restructuring charges		1.0			—			1.0			—
	Depreciation and amortization expense		(.3	)		—			(.6	)		—

Total operating expenses			6.5			(6.0	)		24.4			4.5

Other income (expense):
	Equity in earnings of investments		—			—			.1			—
	Other income (expense)		35.3			(2.8	)		52.0			(9.0	)

Earnings (loss) before interest and taxes		$	28.8		$	3.2		$	27.7		$	(13.5	)

Quarter-to-Quarter

Operating Expense

Operating expense increased $11.8 million primarily due to $3.4 million of restructuring consulting fees and $7.8 million of increased costs associated with being non-investment grade. These amounts were partially offset by first quarter regulatory review expenses that were allocated to Wholesale Services in the second quarter of 2003.

In 2002, there was an additional allocation of first quarter Corporate expenses to Merchant Services. This resulted in negative Corporate expense for the quarter, but had no impact on the consolidated results.

Other Income (Expense)

Other income (expense) increased $38.1 million mainly due to $35.8 million of foreign currency gains in 2003 resulting from favorable movements in the Australian and New Zealand dollar against the U.S. dollar.

Interest Expense

Interest expense increased $24.3 million in the second quarter of 2003 compared to 2002. The increase was primarily the result of higher interest costs related to the $500.0 million of 14.875% senior notes issued in July 2002, the borrowing of $430.0 million under our three-year secured facility and a $200.0 million borrowing under our 364-day secured credit facility in the second quarter of 2003. These increases were offset in part by the retirement of debt outstanding in Australia, Canada, New Zealand and the United Kingdom in late 2002 and early 2003 and the conversion of the premium equity participating securities to common equity in November 2002.

Income Tax Benefit

The income tax benefit decreased $48.2 million in 2003 compared to 2002, primarily as a result of lower losses before income taxes in 2003 compared to 2002, partially offset due to tax benefits not being recognized on a significant amount of the 2002 losses as a result of valuation allowances provided and certain amounts not being deductible for income tax purposes.

Year-to-Date

Operating Expense

Operating expense increased $19.5 million primarily due to $9.3 million of restructuring consulting fees and $13.0 million of increased costs associated with being non-investment grade.

Other Income (Expense)

Other income (expense) increased $61.0 million mainly due to $49.6 million of foreign currency gains in 2003 resulting from favorable movements in the Australian and New Zealand dollar against the U.S. dollar. In addition, 2002 included $5.9 million of foreign exchange and interest rate hedge losses relating to our original planned financing structure that was not consummated in connection with our Midlands acquisition.

Interest Expense

Interest expense increased $46.7 million in the first half of 2003 compared to 2002. The increase was primarily the result of higher interest costs related to the $500.0 million of 14.875% senior notes issued in July 2002, $287.5 million of 7.875% senior notes issued in February 2002 and the borrowing in the 2003 second quarter of $430.0 million under our three-year secured facility and $200.0 million under our 364-day secured credit facility. These increases were offset in part by the retirement of debt outstanding in Australia, Canada, New Zealand and the United Kingdom in late 2002 and early 2003 and the conversion of the premium equity participating securities to common equity in November 2002.

Income Tax Benefit

The income tax benefit decreased $27.0 million in 2003 compared to 2002, primarily as a result of lower losses before income taxes in 2003 compared to 2002 and certain regulatory adjustments that were made in the first quarter of 2002, partially offset due to tax benefits not being recognized on a significant amount of the 2002 losses as a result of valuation allowances provided and certain amounts not being deductible for income tax purposes.

SIGNIFICANT BALANCE SHEET MOVEMENTS

Total assets decreased by $893.7 million since December 31, 2002. This decrease is primarily due to the following:

•: Cash decreased $174.8 million. See our Consolidated Statement of Cash Flows for analysis of this decrease.
•: Restricted cash decreased $161.8 million primarily due to the release of cash held in escrow on the sale of our Merchant loan portfolio, the use of restricted cash collateral to retire debt related to our Piatt County and turbine construction facilities, offset by increased customer deposits that were required to be restricted.
•: Funds on deposit increased $170.0 million primarily due to the cash collateralization requirement for our letters of credit and additional margin deposits paid to counterparties due to the significant increase in natural gas prices in 2003.
•: Accounts receivable, net decreased $914.1 million primarily due to lower volumes of natural gas and electricity delivered due to our exit from wholesale energy trading, offset in part by increased natural gas prices since December 31, 2002.
•: Price risk management assets increased $180.6 million primarily due to increased natural gas prices since December 31, 2002, partially offset by a reduction in the number of trading contracts.
•: Prepayments and other decreased $193.8 million primarily due to the collection of our $191.1 million income tax refund.
•: Non-current assets of discontinued operations increased $161.5 million primarily due to an increase in the exchange rate on our Canadian utility assets.

Total liabilities decreased by $846.5 million and common shareholders' equity decreased by $47.2 million since December 31, 2002. These changes are primarily attributable to the following:

•: Accounts payable decreased by $979.3 million primarily due to lower volumes of natural gas and electricity delivered due to our exit from wholesale energy trading, offset in part by increased natural gas prices since December 31, 2002.
•: Price risk management liabilities increased $164.9 million primarily due to increased natural gas prices since December 31, 2002, partially offset by a reduction in the number of trading contracts.
•: Customer funds on deposit increased by $105.9 million primarily due to increased natural gas prices resulting in additional margin deposits being received from our counterparties.
•: Short-term and long-term debt, including current maturities of long-term debt, together decreased by $92.0 million primarily due to the repayment of $88.3 million of Australian notes, $245.1 million of debt related to our Clay and Piatt County power plants, $244.4 million of revolving credit borrowings and $43.4 million related to our turbine facility. These decreases were offset by net borrowings of $109.3 million under the $200.0 million 364-day secured credit facility and $430.0 million under the three-year secured credit facility.
•: Common shareholders' equity decreased $47.2 million primarily as a result of improved exchange rates on our foreign investments that created $87.2 million of comprehensive income, partially offset by the $132.5 million net loss in the first six months of 2003.

LIQUIDITY AND CAPITAL RESOURCES

Short-term Liquidity

As of June 30 and July 31, 2003, we had the following cash and short-term debt (including Canadian cash and debt reported in discontinued operations):

In millions		June 30, 2003		July 31, 2003

Short-term debt:
	364-day secured facility (a)	$	109.3	$	—
	Bank borrowings and other—Canada		84.2		291.1

	Subtotal		193.5		291.1

Current maturities of long-term debt:
	Canadian asset securitization (b)		73.6		70.6
	Miscellaneous		16.1		16.1

	Subtotal		89.7		86.7

Total		$	283.2	$	377.8

(a): We repaid this facility in July 2003 with the proceeds from the sale of our Australian investments.
(b): This facility is secured by certain future rate collections and will be repaid monthly through February 2004.

On April 11, 2003, we closed on a three-year secured financing of $430.0 million and a 364-day secured financing of $200.0 million. At closing of the 364-day secured financing, we initially borrowed $100.0 million. On May 12, 2003, we exercised our option under the 364-day financing to borrow the additional $100.0 million available under this facility. See Note 8 to the Consolidated Financial Statements for additional information regarding the terms of the financings. Proceeds from the financings were used to retire debt, support letters of credit and terminate our Acadia tolling agreement. We retired the 364-day secured credit facility with payments in June and July 2003 out of the proceeds from the sale of our Australian investments.

On July 31, 2003, we closed on a $215.0 million, 364-day unsecured loan. The borrowers are ANCC and ANCA, each of which is an indirect wholly-owned subsidiary. At closing, ANCC borrowed $115.0 million and ANCA borrowed $100.0 million. The interest rate on this financing is LIBOR (with 2.50% floor) plus 4.25%. Proceeds were used by ANCA to repay and terminate its existing 364-day credit agreement that matured on July 31, 2003 and a letter of credit facility. ANCC will use its proceeds to finance the capital expenditure and working capital requirements of its regulated utility subsidiaries, as well as repay certain bank debt of ANCBC. The facilities will be repaid with the proceeds received in connection with the sale of its Canadian utility investments. We paid up-front arrangement fees of $4.3 million.

Due to our non-investment grade credit rating and lack of short-term lines of credit, we must maintain sufficient cash on hand to cover all of the working capital requirements of our business. The most significant activity impacting working capital is the purchase of natural gas for our gas utility customers. We could experience significant working capital requirements during peak winter heating months due to higher natural gas consumption, potential periods of high natural gas prices and the fact that we are currently required to prepay certain of our gas commodity suppliers and pipeline companies.

Long-term Liquidity

Our next significant need for outside capital relates to the retirement of our $250 million and $150 million of senior notes maturing in July and October 2004, respectively. We anticipate retiring this debt with proceeds from the sale of our Canadian operations and independent power projects.

As we continue to transition to a domestic utility business, our long-term liquidity is dependent upon the following actions:

•: the successful sale of non-strategic assets;
•: restructuring of our generation capacity obligations;
•: obtaining additional rate increases for our domestic networks;
•: ability to raise additional capital through equity and debt markets;
•: ability to use regulated assets as collateral for debt.

Cash Flows

Cash Flows from Operating Activities—Cash used for operating activities increased in the six months ended June 30, 2003, compared to the same period in 2002 primarily due to increases in restricted cash and funds on deposit resulting from downgrades of our credit, higher natural gas prices and cash paid for restructuring and impairment charges. These cash outflows were partially offset by the collection of our $191.1 million 2002 income tax refund in 2003.

Cash Flows from Investing Activities—Cash flows from investing activities increased in the first six months of 2003 primarily due to the collection of cash proceeds in 2003 from the sale of assets in 2002 and reduced Merchant capital expenditures due to the completion of construction on several new plants in 2002.

Cash Flows from Financing Activities—Cash flows from financing activities decreased in the first six months of 2003 compared to 2002 primarily as a result of our issuance in 2002 of common stock and senior notes. These proceeds were used to pay down short-term debt on our revolving credit agreement and to replace the liquidity under the Merchant Services accounts receivable sales program that was terminated. In the first six months of 2003, the primary financing activities were the borrowings under the secured credit facilities, the repayment of debt under the revolving credit facility, the Clay County and Piatt County construction financings and the repayment of Australian notes.

Certain Trading Activities

We engage in price risk management activities for both trading and non-trading activities. Transactions carried out in connection with trading activities that are derivatives under SFAS 133 are accounted for under the mark-to-market method of accounting. Through October 2002, these contracts were accounted for under EITF 98-10 which also required the use of the mark-to-market method. 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 2003 are summarized below:

In millions	Wholesale Services			Capacity Services and other			Total

Fair value at December 31, 2002	$	180.2		$	104.3		$	284.5
Change in fair value during the period		45.4			(24.6	)		20.8
Contracts realized or cash settled		(18.8	)		13.7			(5.1	)

Fair value at June 30, 2003	$	206.8		$	93.4		$	300.2

The fair value of contracts maturing in the remainder of 2003, each of the next three years and thereafter are shown below:

In millions	Wholesale Services		Capacity Services and other		Total

2003	$	6.6	$	23.2	$	29.8
2004		40.2		21.1		61.3
2005		35.6		6.7		42.3
2006		30.3		19.4		49.7
Thereafter (a)		94.1		23.0		117.1

Total fair value	$	206.8	$	93.4	$	300.2

(a): As these contracts have been significantly hedged, movement in commodity prices will have a limited impact on the net cash value provided.

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 control 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

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

We held our annual meeting of shareholders on June 4, 2003. At the meeting, the following matter was voted on by the shareholders:

1. Election of Directors:

Director	Term	Votes For	Votes Withheld
Dr. Michael M. Crow	3 years	148,991,179	13,303,928
Richard C. Green, Jr.	3 years	147,578,325	14,716,782
Gerald L. Shaheen	3 years	145,043,090	17,252,017
Following the election, our Board of Directors consists of Richard C. Green, Jr. (Chairman); John R. Baker; Herman Cain; Dr. Michael M. Crow; Irvine O. Hockaday, Jr.; Heidi E. Hutter; Dr. Stanley O. Ikenberry; and Gerald L. Shaheen.

Item 6. Exhibits and Reports on Form 8-K

(a) List of Exhibits

Exhibit No.		Description
10.1		Severance Payment Agreement Release and Waiver of Claims dated as of July 10, 2003 by and between the Company and Cadwallader Payne, Jr.
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

(b) Reports on Form 8-K

We furnished Current Reports on Form 8-K to the Securities and Exchange Commission during the quarter ended June 30, 2003, as follows:

Date Filed	Item No.
April 15, 2003	Item 7—	Press release dated April 15, 2003.
	Item 9—	Announcement of fourth quarter and year ended December 31, 2002 results.
May 15, 2003	Item 7—	Press release dated May 15, 2003.
	Item 9—	Announcement of first quarter 2003 results.

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 Chief Financial Officer
		Signing on behalf of the registrant and as principal financial and accounting officer
Date:		August 12, 2003

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PART I—FINANCIAL INFORMATION
PART II—OTHER INFORMATION

Part I. Financial Information

Item 1. Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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

Item 4. Controls and Procedures

Part II—Other Information

Item 1. Legal Proceedings

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

Item 6. Exhibits and Reports on Form 8-K

Signatures