Dynegy Illinois 10-Q 2003 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2003

¨ 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: 1-15659

DYNEGY INC.

(Exact name of registrant as specified in its charter)

Illinois	74-2928353
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1000 Louisiana, Suite 5800

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 507-6400

(Registrant’s telephone number, including area code)

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. Yesx No¨

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

Number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: Class A common stock, no par value per share, 277,739,959 shares outstanding as of August 11, 2003; Class B common stock, no par value per share, 96,891,014 shares outstanding as of August 11, 2003.

DYNEGY INC.

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1.    CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
Condensed Consolidated Balance Sheets:
June 30, 2003 and December 31, 2002	4
Condensed Consolidated Statements of Operations:
For the three and six months ended June 30, 2003 and 2002	5
Condensed Consolidated Statements of Cash Flows:
For the six months ended June 30, 2003 and 2002	6
Condensed Consolidated Statements of Comprehensive Income (Loss):
For the three and six months ended June 30, 2003 and 2002	7
Notes to Condensed Consolidated Financial Statements	8
Item 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	47
Item 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	77
Item 4.    CONTROLS AND PROCEDURES	79
PART II. OTHER INFORMATION
Item 1.    LEGAL PROCEEDINGS	80
Item 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	80
Item 6.    EXHIBITS AND REPORTS ON FORM 8-K	81

Glossary of Key Terms

ARO	Asset retirement obligation.
Bcf/d	Billion cubic feet per day.
Cal ISO	The California Independent System Operator.
Cal PX	The California Power Exchange.
CDWR	California Department of Water Resources.
CFTC	Commodity Futures Trading Commission.
CMS Energy	CMS Energy Corporation.
CRM	Our customer risk management business segment.
Destec	Dynegy Power Corp., formerly Destec Energy, Inc.
DGC	Dynegy Global Communications.
DGC-Asia	Dynegy Global Communications-Asia, our former Asian communications business.
DHI	Dynegy Holdings Inc., our primary financing subsidiary.
DMS	Dynegy Midstream Services.
DMT	Dynegy Marketing and Trade.
DPM	Dynegy Power Marketing Inc.
Dynegy	Dynegy Inc.
DynegyConnect	DynegyConnect, L.P.
EBIT	A non-GAAP measure of Earnings Before Interest and Taxes. As an indicator of our segment operating performance, EBIT should not be considered an alternative to, or more meaningful than, net income or cash flows from operations as determined in accordance with GAAP.

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EITF	Emerging Issues Task Force.
EPA	Environmental Protection Agency.
ERCOT	Electric Reliability Council of Texas, Inc.
ERISA	The Employee Retirement Income Security Act of 1974, as amended.
FASB	Financial Accounting Standards Board.
FERC	Federal Energy Regulatory Commission.
FIN	FASB Interpretation.
Form 10-K/A	Amendment No. 1 to our Annual Report on Form 10-K for the year ended December 31, 2002, filed on July 25, 2003.
GAAP	Generally Accepted Accounting Principles.
GEN	Our power generation business segment.
ICC	Illinois Commerce Commission.
Illinois Power	Illinois Power Company.
Illinova	Illinova Corporation, a wholly owned subsidiary of Dynegy and the direct parent company of Illinois Power.
Kroger	The Kroger Co.
MMBtu	Millions of British thermal units.
MW	Megawatts.
NGL	Our natural gas liquids business segment.
Nicor Energy	Nicor Energy L.L.C., a joint venture with Nicor Inc.
Northern Natural	Northern Natural Gas Company.
NOV	Notice of Violation issued by the EPA.
NRG Energy	NRG Energy, Inc.
PUCT	Public Utility Commission of Texas.
PUHCA	The Public Utility Holding Company Act of 1935, as amended.
REG	Our regulated energy delivery business segment.
SEC	U.S. Securities and Exchange Commission.
Series B Exchange	The restructuring transaction consummated on August 11, 2003 pursuant to which a subsidiary of ChevronTexaco exchanged $1.5 billion in Series B Mandatorily Convertible Redeemable Preferred Stock for $225 million in cash and $625 million in newly issued securities.
SFAS	Statement of Financial Accounting Standards.
Southern Power	Southern Power Company.
VaR	Value at Risk.
Versado	Versado Gas Processors, L.L.C.
WECC	Western Electricity Coordinating Council.
WEN	Our former wholesale energy network business segment.
West Coast Power	West Coast Power, LLC, a joint venture equally owned by Dynegy and NRG Energy.

Additionally, the terms “Dynegy,” “we,” “us” and “our” refer to Dynegy Inc. and its subsidiaries, unless the context clearly indicates otherwise.

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DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)

	June 30, 2003			December 31, 2002
ASSETS
Current Assets
Cash and cash equivalents	$	801		$	757
Restricted cash		18			17
Accounts receivable, net of allowance for doubtful accounts of $162 million and $151 million, respectively		1,110			2,791
Accounts receivable, affiliates		39			31
Inventory		274			236
Assets from risk-management activities		1,435			2,618
Prepayments and other assets		588			1,136
Total Current Assets		4,265			7,586
Property, Plant and Equipment		9,687			9,659
Accumulated depreciation		(1,331	)		(1,270	)
Property, Plant and Equipment, Net		8,356			8,389
Other Assets
Unconsolidated investments		686			668
Assets from risk-management activities		1,094			2,529
Goodwill		396			396
Other assets		458			462
Total Assets	$	15,255		$	20,030	��
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	585		$	1,586
Accounts payable, affiliates		95			65
Accrued liabilities and other		849			1,818
Liabilities from risk-management activities		1,388			2,418
Notes payable and current portion of long-term debt		531			861
Total Current Liabilities		3,448			6,748
Long-Term Debt		5,561			5,454
Other Liabilities
Liabilities from risk-management activities		1,162			2,366
Deferred income taxes		785			951
Other long-term liabilities		744			855
Total Liabilities		11,700			16,374
Minority Interest		128			146
Commitments and Contingencies (Note 9)
Redeemable Preferred Securities, redemption value of $1,711		1,588			1,423
Stockholders’ Equity
Class A Common Stock, no par value, 900,000,000 shares authorized at June 30, 2003 and December 31, 2002, 277,450,291 and 274,850,589 shares issued and outstanding at June 30, 2003 and December 31, 2002, respectively		2,845			2,825
Class B Common Stock, no par value, 360,000,000 shares authorized at June 30, 2003 and December 31, 2002, 96,891,014 shares issued and outstanding at June 30, 2003 and December 31, 2002		1,006			1,006
Additional paid-in capital		699			705
Subscriptions receivable		(11	)		(12	)
Accumulated other comprehensive loss, net of tax		(10	)		(55	)
Accumulated deficit		(2,622	)		(2,314	)
Treasury stock, at cost, 1,679,183 shares at June 30, 2003 and December 31, 2002		(68	)		(68	)
Total Stockholders’ Equity		1,839			2,087
Total Liabilities and Stockholders’ Equity	$	15,255		$	20,030

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
Revenues (Note 1)	$	1,054		$	1,364		$	2,799		$	2,803
Cost of sales, exclusive of depreciation shown separately below (Note 1)		(1,200	)		(1,289	)		(2,574	)		(2,459	)
Depreciation and amortization expense		(116	)		(100	)		(231	)		(193	)
Gain on sale of assets		14			1			15			1
Impairment and other charges		—			(42	)		7			(42	)
General and administrative expenses		(126	)		(77	)		(203	)		(168	)
Operating loss		(374	)		(143	)		(187	)		(58	)
Earnings from unconsolidated investments		38			18			91			53
Interest expense		(109	)		(64	)		(219	)		(130	)
Other income and expense, net		3			(13	)		11			7
Minority interest income (expense)		(8	)		(9	)		9			(39	)
Accumulated distributions associated with trust preferred securities		(4	)		(3	)		(8	)		(7	)
Loss from continuing operations before income taxes		(454	)		(214	)		(303	)		(174	)
Income tax benefit		168			75			112			82
Loss from continuing operations		(286	)		(139	)		(191	)		(92	)
Loss on discontinued operations, net of taxes (Note 2)		(4	)		(422	)		(7	)		(482	)
Loss before cumulative effect of change in accounting principles		(290	)		(561	)		(198	)		(574	)
Cumulative effect of change in accounting principles, net of taxes (Notes 1 and 3)		—			—			55			(234	)
Net loss		(290	)		(561	)		(143	)		(808	)
Less: preferred stock dividends		82			82			165			165
Net loss applicable to common stockholders	$	(372	)	$	(643	)	$	(308	)	$	(973	)
Net Loss Per Share:
Basic loss per share:
Loss from continuing operations	$	(0.99	)	$	(0.61	)	$	(0.96	)	$	(0.71	)
Loss from discontinued operations		(0.01	)		(1.15	)		(0.02	)		(1.32	)
Cumulative effect of change in accounting principles		—			—			0.15			(0.64	)
Basic loss per share	$	(1.00	)	$	(1.76	)	$	(0.83	)	$	(2.67	)
Diluted loss per share (Note 8):
Loss from continuing operations	$	(0.99	)	$	(0.61	)	$	(0.96	)	$	(0.71	)
Loss from discontinued operations		(0.01	)		(1.15	)		(0.02	)		(1.32	)
Cumulative effect of change in accounting principles		—			—			0.15			(0.64	)
Diluted loss per share (Note 8)	$	(1.00	)	$	(1.76	)	$	(0.83	)	$	(2.67	)
Basic shares outstanding		373			366			372			364
Diluted shares outstanding		375			370			374			369

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

	Six Months Ended June 30,
	2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(143	)	$	(808	)
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		258			278
Impairment and other charges		—			670
(Earnings) losses from unconsolidated investments, net of cash distributions		(22	)		43
Risk-management activities		290			399
Gain on sale of assets		(39	)		—
Deferred income taxes		(122	)		(338	)
Cumulative effect of change in accounting principles (Notes 1 and 3)		(55	)		234
Other		49			41
Changes in working capital:
Accounts receivable		1,615			63
Inventory		102			(19	)
Prepayments and other assets		546			(6	)
Accounts payable and accrued liabilities		(2,014	)		(211	)
Other, net		(25	)		(18	)
Net cash provided by operating activities		440			328
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(189	)		(631	)
Investments in unconsolidated affiliates		—			(12	)
Business acquisitions, net of cash acquired		—			(20	)
Proceeds from asset sales, net		33			10
Net cash used in investing activities		(156	)		(653	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from long-term borrowings		301			574
Net proceeds from short-term borrowings		—			245
Repayments of borrowings		(425	)		(216	)
Net cash flow from commercial paper and revolving lines of credit		(128	)		(233	)
Proceeds from issuance of capital stock		6			236
Purchase of serial preferred securities of a subsidiary		—			(28	)
Purchase of treasury stock		—			(1	)
Dividends and other distributions, net		—			(55	)
(Increase) decrease in restricted cash		(1	)		14
Other financing, net		—			(17	)
Net cash provided by (used in) financing activities		(247	)		519
Effect of exchange rate changes on cash		7			(35	)
Net increase in cash and cash equivalents		44			159
Cash and cash equivalents, beginning of period		757			208
Cash and cash equivalents, end of period	$	801		$	367

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)

	Three Months Ended June 30,
	2003			2002
Net loss	$	(290	)	$	(561	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		33			(2	)
Reclassification of mark-to-market (gains) losses to earnings, net		(2	)		11
Unrealized net gains (losses)		31			9
Foreign currency translation adjustments		(3	)		28
Unrealized holding gains on securities arising during period		—			2
Other comprehensive income, net of tax		28			39
Comprehensive loss	$	(262	)	$	(522	)

	Six Months Ended June 30,
	2003			2002
Net loss	$	(143	)	$	(808	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		45			(3	)
Reclassification of mark-to-market (gains) losses to earnings, net		(21	)		2
Unrealized net gains (losses)		24			(1	)
Foreign currency translation adjustments		21			31
Unrealized holding gains on securities arising during period		—			8
Other comprehensive income, net of tax		45			38
Comprehensive loss	$	(98	)	$	(770	)

See the notes to condensed consolidated financial statements.

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DYNEGY. INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Note 1—Accounting Policies

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in our Form 10-K/A. Our periodic SEC reports, including this report, remain subject to an ongoing review by the SEC Division of Corporation Finance.

The unaudited condensed consolidated financial statements contained in this report include all material adjustments that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods. Interim period results are not necessarily indicative of the results for the full year. The preparation of the condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to develop estimates and make assumptions that affect reported financial position and results of operations and that impact the nature and extent of disclosure, if any, of contingent assets and liabilities. We review significant estimates affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Judgments and estimates are based on our beliefs and assumptions derived from information available at the time such judgments and estimates are made. Adjustments made with respect to the use of these estimates often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates are primarily used in (1) developing fair value assumptions, including estimates of future cash flows and discount rates, (2) analyzing tangible and intangible assets for impairment, (3) estimating the useful lives of our assets, (4) assessing future tax exposure and the realization of tax assets, (5) determining the amounts to accrue related to contingencies and (6) estimating various factors that impact the valuation of our pension assets. Actual results could differ materially from any such estimates. Certain reclassifications have been made to prior period amounts in order to conform to current year presentation, primarily related to discontinued operations and our new segment presentation.

Accounting Principles Adopted

EITF Issue 02-03.    In 2002, the EITF reached consensus on two issues presented in EITF Issue 02-03, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” First, the EITF concluded that all mark-to-market gains and losses on energy trading contracts (whether realized or unrealized) should be shown net in the income statement, irrespective of whether the contract is physically or financially settled. In the third quarter 2002, we began presenting all mark-to-market gains and losses on a net basis to reflect this change in accounting principle. In accordance with the transition provisions in the consensus, comparative period financial statements have been conformed to reflect this change in accounting principle. Prior to the change in accounting principle, we classified net unrealized gains and losses from energy trading contracts as revenue in our unaudited condensed consolidated statements of operations. Physical transactions that were realized and settled were previously reflected gross in revenues and cost of sales. This change in accounting classification has no impact on our operating income, net income (loss), earnings (loss) per share or cash flow from operations.

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

The following table reconciles the revenues and costs of sales reported under prior accounting guidance to the amounts reported herein in connection with the change in accounting principle (in millions):

	Three Months Ended June 30, 2002			Six Months Ended June 30, 2002
Revenues as previously reported	$	9,676		$	18,102
Adjustment for discontinued operations (See Note 2)		(340	)		(680	)
Change in accounting principle		(7,972	)		(14,619	)
Revenues as reported herein	$	1,364		$	2,803
Cost of sales as previously reported	$	9,548		$	17,623
Adjustment for discontinued operations (See Note 2)		(287	)		(545	)
Change in accounting principle		(7,972	)		(14,619	)
Cost of sales as reported herein	$	1,289		$	2,459

Second, in October 2002, the EITF reached a consensus to rescind EITF Issue 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” which previously required us to use mark-to-market accounting for our energy trading contracts. While the rescission of EITF Issue 98-10 will reduce the number of contracts accounted for on a mark-to-market basis, it does not eliminate mark-to-market accounting. All derivative contracts that either do not qualify, or are not designated, as hedges or as normal purchases or sales, as defined by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” will continue to be marked-to-market in accordance with SFAS No. 133. Any earnings/losses previously recognized under EITF Issue 98-10 that would not have been recognized under SFAS No. 133 were reversed in the first quarter 2003 pursuant to the adoption provisions of EITF Issue 02-03. The cumulative effect of this change in accounting principle resulted in after-tax earnings of $21 million in the first quarter 2003 and was comprised of the following items, which are no longer required to be recorded using mark-to-market accounting (in millions):

Removal of net risk-management assets representing the value of natural gas storage contracts	$	(176	)
Removal of other net risk-management assets		(24	)
Removal of net risk-management liabilities representing the value of power tolling arrangements		103
Net change in risk-management assets and liabilities		(97	)
Addition of natural gas and coal inventory previously included in risk-management assets (1)		130
Pre-tax gain recorded from change in accounting principle		33
Income tax provision		(12	)
After-tax gain recorded in the unaudited condensed consolidated statements of operations	$	21

(1) A substantial portion of this natural gas inventory was sold during the three months ended March 31, 2003, with the remainder being sold in the second quarter 2003.

SFAS No. 143.    In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” We adopted SFAS No. 143 effective January 1, 2003. SFAS No. 143 provides accounting

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

requirements for costs associated with legal obligations to retire tangible, long-lived assets. Under SFAS No. 143, the ARO is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its fair value and the capitalized costs are depreciated over the useful life of the related asset. The cumulative effect of applying SFAS No. 143 has been recognized as a change in accounting principle in the unaudited condensed consolidated statements of operations.

As part of the transition adjustment in adopting SFAS No. 143, existing environmental liabilities in the amount of $73 million were reversed in the first quarter 2003. The fair value of the remediation costs estimated to be incurred upon retirement of the respective assets is included in the ARO and was recorded upon adoption of SFAS No. 143. Since the previously accrued liabilities exceeded the fair value of the future retirement obligations, the impact of adopting SFAS No. 143 was an increase in earnings, net of tax, of approximately $34 million in the first quarter 2003, which is reflected as a cumulative effect of a change in accounting principle in the unaudited condensed consolidated financial statements. The annual amortization of the assets resulting from adoption of this standard and the accretion of the liability to its fair value is estimated to be approximately $6 million in 2003. In addition to these liabilities, we also have potential retirement obligations for the dismantlement of power generation facilities, power transmission assets, a fractionation facility and natural gas storage facilities. It is our current intent to maintain these facilities in a manner such that the facilities will be operational indefinitely. As such, we cannot estimate any potential retirement obligations associated with these assets. At the time we are able to estimate any new AROs, liabilities will be recorded in accordance with SFAS No. 143.

At January 1, 2003, our ARO liabilities were $26 million for our GEN segment, $9 million for our NGL segment and $6 million for our REG segment. These retirement obligations related to activities such as ash pond and landfill capping, closure and post-closure costs, environmental testing, remediation, monitoring and land and equipment lease obligations. During the three- and six-month periods ended June 30, 2003, accretion expense recognized for the fair value for all of our ARO liabilities totaled approximately $1 million and $3 million, respectively. There were no additional AROs recorded or settled, nor were there any revisions to estimated cash flows associated with existing AROs, during the three- and six-month periods ended June 30, 2003. At June 30, 2003, our ARO liability totaled $44 million.

Had SFAS No. 143 been applied retroactively in the three- and six-month periods ended June 30, 2002, our net loss applicable to common stockholders would have been $645 million and $976 million, respectively. Basic and diluted loss per share for the three months ended June 30, 2002 would be unchanged. Basic and diluted loss per share for the six months ended June 30, 2002 would have been $2.68.

SFAS No. 146.    In July 2002, the FASB issued SFAS No. 146, “Accounting for Exit or Disposal Activities.” SFAS No. 146 addresses issues regarding the recognition, measurement and reporting of costs that are associated with exit and disposal activities, including restructuring activities that were previously accounted for pursuant to the guidance in EITF Issue 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. We have not initiated any such activities during the first six months of 2003 but intend to apply provisions of SFAS No. 146 for any exit or disposal activities initiated in the future.

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

SFAS No. 148.    In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure.” SFAS No. 148 amends SFAS No. 123 and provides alternative methods of transition (prospective, modified prospective or retroactive) for entities that voluntarily change to the fair value-based method of accounting for stock-based employee compensation in a fiscal year beginning before December 16, 2003. SFAS No. 148 requires prominent disclosure about the effects on reported net income of an entity’s accounting policy decisions with respect to stock-based employee compensation. We transitioned to a fair value-based method of accounting for stock-based compensation in the first quarter 2003 and are using the prospective method of transition as described under SFAS No. 148. As a result, an annual charge of approximately $1 million will be reflected in general and administrative expenses in the unaudited condensed consolidated statements of operations.

Under the prospective method of transition, all stock options granted since January 1, 2003 will be accounted for on a fair value basis. Options granted prior to January 1, 2003 continue to be accounted for using the intrinsic value method. Had compensation cost for stock options issued prior to 2003 been determined on a fair value basis consistent with SFAS No. 123, our net income (loss) and basic and diluted earnings (loss) per share amounts would have approximated the following pro forma amounts for the three- and six-month periods ended June 30, 2003 and 2002, respectively.

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
	(in millions, except per share data)
Net loss as reported	$	(290	)	$	(561	)	$	(143	)	$	(808	)
Add: Stock-based employee compensation expense included in reported net loss, net of related tax effects		—			1			1			2
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(14	)		(20	)		(27	)		(39	)
Pro forma net loss	$	(304	)	$	(580	)	$	(169	)	$	(845	)
Loss per share:
Basic—as reported	$	(1.00	)	$	(1.76	)	$	(0.83	)	$	(2.67	)
Basic—pro forma	$	(1.03	)	$	(1.81	)	$	(0.90	)	$	(2.77	)
Diluted—as reported	$	(1.00	)	$	(1.76	)	$	(0.83	)	$	(2.67	)
Diluted—pro forma	$	(1.03	)	$	(1.81	)	$	(0.90	)	$	(2.77	)

FIN No. 45.    In November 2002, the FASB issued FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” As required by FIN No. 45, we adopted the disclosure requirements on December 31, 2002. On January 1, 2003, we adopted the initial recognition and measurement provisions for guarantees issued or modified after December 31, 2002. The adoption of the recognition and measurement provisions did not have any impact on our financial statements.

Accounting Principles Not Yet Adopted

FIN No. 46.    In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities—an Interpretation of ARB No. 51.” In summary, this interpretation increases the level of risk that must be

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

assumed by equity investors in special purpose entities. FIN No. 46 requires that the equity investor have significant equity at risk (a minimum of 10 percent with few exceptions, which is an increase from the 3 percent required under previous guidance) and hold a controlling interest, evidenced by voting rights, risk of loss and the benefit of residual returns. If the equity investor is unable to evidence these characteristics, the entity that retains these ownership characteristics will be required to consolidate the variable interest entity. While we have not entered into any arrangements in 2003 that would be subject to FIN No. 46, we are analyzing the structures of entities previously formed to determine whether we have any arrangements that are impacted. FIN No. 46 was applicable immediately to variable interest entities created or obtained after January 31, 2003. For variable interest entities created or obtained before February 1, 2003, FIN No. 46 is applicable as of July 1, 2003. The impact of adopting FIN No. 46 will be reflected as a cumulative effect of a change in accounting principle in the third quarter 2003.

SFAS No. 149.    In April 2003, the FASB issued SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 clarifies and amends various issues related to derivatives and financial instruments addressed in SFAS No. 133 and interpretations issued by the Derivatives Implementation Group. In particular, SFAS No. 149 clarifies (1) under what circumstances a contract with an initial net investment meets the characteristics of a derivative, (2) when a derivative contains a financing component that should be reflected as a financing on the balance sheet and the statement of cash flows, (3) the definition of an “underlying” in SFAS No. 133 to conform to the language used in FIN No. 45 and (4) other derivative concepts. SFAS No. 149 is applicable to all contracts entered into or modified after June 30, 2003 and to all hedging relationships designated after June 30, 2003. We do not believe the adoption of SFAS No. 149 will materially impact the accounting for our price risk-management and other derivative contracts.

SFAS No. 150.    In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.”SFAS No. 150 establishes how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. Instruments which have an unconditional obligation requiring the issuer to redeem the instrument by transferring an asset at a specified date are required to be classified as liabilities on the balance sheet. Instruments which require the issuance of a variable number of equity shares by the issuer generally do not have the risks associated with equity instruments and as such should also be classified as liabilities on the balance sheet. SFAS No. 150 is effective for contracts in existence or created or modified for the first interim period beginning after June 15, 2003. We are currently reviewing the impact SFAS No. 150 will have on the classification of certain instruments on our balance sheet. We expect approximately $200 million of Company Obligated Preferred Securities, currently recorded in the mezzanine section of our balance sheet between liabilities and equity, to be reclassified to long-term liabilities. Accordingly, the interest related to this instrument will be recorded as interest expense beginning July 1, 2003. Previously, the preferred return on this instrument was reported in Accumulated distributions associated with trust preferred securities in the condensed consolidated statements of operations. Further, the $400 million in Series C convertible preferred stock issued to ChevronTexaco in August 2003 in connection with the Series B Exchange will be classified within the mezzanine section of our balance sheet due to the $5.78 per share substantive conversion option. Please read Note 6 – Debt – ChevronTexaco Series B Preferred Stock Restructuring for further discussion. We do not expect any other material impact from the adoption of this statement.

12

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Note 2—Dispositions, Contract Terminations and Discontinued Operations

Dispositions and Contract Terminations

SouthStar Energy Services.    During the first quarter 2003, we completed the sale of our 20 percent equity investment in SouthStar Energy Services LLC. We received cash proceeds of approximately $20 million and recognized an after-tax gain on the sale of approximately $0.8 million. The gain is included in gain on sale of assets in the unaudited condensed consolidated statements of operations.

Hackberry LNG Project.    During the first quarter 2003, we entered into an agreement to sell our interest in Hackberry LNG Terminal LLC, the entity we formed in connection with our proposed LNG terminal/gasification project in Hackberry, Louisiana, to Sempra LNG Corp., a subsidiary of San Diego-based Sempra Energy. The transaction closed on April 23, 2003. At closing, we received an initial payment of $20 million and have the right to receive additional contingent payments based upon project development milestones. We recognized an after-tax gain of approximately $12 million in the second quarter 2003 in relation to this sale. Additionally, we are entitled to a portion of the return on the project if specified performance targets are achieved in the future.

Southern Power Company Tolling Arrangements.    In April 2003, we reached an agreement in principle with Southern Power to terminate three power tolling arrangements among Dynegy, Southern Power and our respective affiliates covering an aggregate of 1,100 MW. Under the terms of the agreement, we paid Southern Power $155 million to terminate two of these arrangements effective May 30, 2003 and the third such arrangement effective October 31, 2003. The terminations resulted in $89 million of net collateral being returned to us and eliminated our obligation to make $1.7 billion in capacity payments to Southern Power over the next 30 years. The transaction closed in May 2003, and we recognized an after-tax loss of approximately $84 million.

Kroger Company Settlement.    In July 2003, we reached a settlement with Kroger related to four power supply contracts. Under the terms of the settlement agreement, which was approved by the FERC on July 23, 2003, Kroger will pay us $110 million to terminate two of the four power contracts and to restructure at current market prices the remaining two contracts through which we provide electricity to Kroger subsidiary stores in California. As part of the settlement, we also resolved an outstanding FERC dispute related to contract pricing.

The four contracts were derivatives under SFAS No. 133 and were carried at their fair value on the condensed consolidated balance sheets, with changes in fair value recognized in earnings. Our net risk management asset related to these contracts was approximately $140 million at June 30, 2003. Therefore, the $30 million difference between the cash payment of $110 million and the carrying value of the net risk management asset was recorded as a charge in the second quarter 2003. The remaining two contracts will continue to be carried at fair value with changes in fair value recognized in earnings. The $110 million cash payment we expect to receive from Kroger in the third quarter 2003 is not contingent upon future performance under the two remaining contracts.

Discontinued Operations

During 2002, we sold our ownership interests in each of Northern Natural, our United Kingdom natural gas storage business, our global liquids business and DGC-Asia. The historical results from these operations are included in discontinued operations for the first six months of 2002. In addition, as part of our restructuring plan, we sold or liquidated portions of our operations during the first six months of 2003, some of which have been accounted for as discontinued operations under SFAS No. 144, as further discussed below.

13

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Global Communications.    During January 2003, we disposed of Dynegy Europe Communications to an affiliate of Klesch & Company, a London-based private equity firm. We recognized an after-tax gain on the sale of approximately $19 million in the first quarter 2003. During May 2003, we disposed of our U.S. communications network to an affiliate of 360networks Corporation. During the second quarter 2003, we recognized an after-tax gain on the sale of approximately $2 million, the closing of which completed our exit from the communications business. Approximately $15 million of undiscounted obligations with respect to this business remain following these sales.

U.K. CRM.    During the first quarter 2003, the wind-down efforts of the U.K. CRM business were substantially completed. During the first six months of 2003, we recognized an after-tax loss of $9 million resulting primarily from selling and terminating all U.K. gas and power positions, offset by administrative expenses, depreciation and amortization, shut-down costs and currency translation losses. In connection with the wind-down, collateral postings totaling $95 million were eliminated. We do not expect the U.K. CRM business to have a material impact on our results in the future.

The following table summarizes information related to our discontinued operations (in millions):

	Northern Natural			U.K. Storage		U.K. CRM		Global Liquids			DGC			Total
Three Months Ended June 30, 2003
Revenue	$	—		$	—	$	—	$	—		$	1		$	1
Income (loss) from operations before taxes		—			—		4		(1	)		(10	)		(7	)
Gain on sale before taxes		—			—		—		—			4			4
Gain on sale after taxes		—			—		—		—			2			2
Three Months Ended June 30, 2002
Revenue	$	79		$	45	$	10	$	200		$	6		$	340
Income (loss) from operations before taxes(1)		(8	)		13		5		(4	)		(664	)		(658	)

	Northern Natural		U.K. Storage		U.K. CRM			Global Liquids			DGC			Total
Six Months Ended June 30, 2003
Revenue	$	—	$	—	$	21		$	—		$	5		$	26
Loss from operations before taxes		—		—		(11	)		(1	)		(29	)		(41	)
Gain on sale before taxes		—		—		—			—			25			25
Gain on sale after taxes		—		—		—			—			21			21
Six Months Ended June 30, 2002
Revenue	$	177	$	85	$	12		$	396		$	10		$	680
Income (loss) from operations before taxes(1)		37		20		(9	)		(5	)		(773	)		(730	)

(1) During the second quarter 2002, we reviewed DGC’s long-lived assets for impairment in accordance with SFAS No. 144 and determined that future cash flows from DGC’s operations were insufficient to cover the carrying value of its long-lived assets. As a result, a pre-tax impairment charge totaling $611 million was recorded in Impairment and Other Charges, and subsequently reclassified to discontinued operations.

14

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Note 3—Restructuring and Other Charges

Restructuring and Other Charges

During the second quarter 2002, we recognized a $683 million pre-tax ($444 million after-tax) charge principally related to the impairment, write-off or obsolescence of certain assets and an accrual for severance related to a corporate restructuring. The charge primarily relates to the impairment of our investment in the communications business, the impairment of investments in securities of entities engaged in technology-related ventures and a severance charge related to a plan of restructuring of our operations. The pre-tax charge consisted of the following (in millions):

Impairment of communications business	$	611
Impairment of technology investments		23
Restructuring charge		37
Write-off of other obsolete assets		12
	$	683

Impairment of Communications Business.    As discussed in Note 2 – Dispositions, Contract Terminations and Discontinued Operations, during the second quarter 2002, a pre-tax impairment charge totaling $611 million ($397 million after-tax) was recorded in Impairment and Other Charges, and subsequently reclassified to discontinued operations.

Impairment of Technology Investments.    During the second quarter 2002, we recognized an impairment charge associated with certain technology investments. The $23 million pre-tax ($15 million after-tax) charge was recorded in Earnings from Unconsolidated Investments and $4 million of the charge ($3 million after-tax) was subsequently reclassified to discontinued operations.

Restructuring Charges.    During the second quarter 2002, we recognized a $37 million charge for severance benefits in connection with a reduction in force affecting approximately 325 employees. In October 2002, we announced a restructuring plan designed to improve operational efficiencies and performance across our lines of business. As part of this restructuring, which included a further reduction in force affecting approximately 780 employees, we recognized a pre-tax charge of $182 million during the fourth quarter 2002.

The following is a schedule of 2003 activity for the liabilities recorded in connection with these charges (in millions):

	Severance			Cancellation Fees and Operating Leases			Total
Balance at December 31, 2002	$	71		$	61		$	132
2003 adjustments to liability		(6	)		1			(5	)
Cash payments		(36	)		(30	)		(66	)
Balance at June 30, 2003	$	29		$	32		$	61

The adjustment to the accrued liability during the first six months of 2003 reflects reductions in the severance accrual provided for employees that will now be retained, as well as for individuals in our foreign operations.

15

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Write-off of Other Obsolete Assets.    The remaining pre-tax non-cash charge of $12 million ($8 million after-tax) relates to the retirement of partially depreciated information technology equipment and software replaced during the second quarter 2002 with new system applications and arrangements as well as miscellaneous deposits that are not expected to provide future value. The charge was recorded in Impairment and Other Charges and $1 million of the charge ($1 million after-tax) was subsequently reclassified to discontinued operations.

Cumulative Effect of Change in Accounting Principles

We adopted SFAS No. 143 and provisions of EITF Issue 02-03 in the first quarter 2003. Please see Note 1 for a discussion of the impact of adopting these standards.

We adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” effective January 1, 2002, and, accordingly, tested for impairment all amounts recorded as goodwill. We determined that goodwill associated with our communications business was impaired and recognized a charge of $234 million for this impairment in the first quarter 2002. The fair value of this reporting segment was estimated using expected discounted future cash flows. The value was negatively impacted by continued weakness in the communications and broadband markets. The first quarter 2002 impairment charge is reflected in the unaudited condensed consolidated statements of operations as a cumulative effect of change in accounting principle. There were no changes in the carrying amount of goodwill for any of our reporting units for the three- and six-month periods ended June 30, 2003.

Note 4—Commercial Operations, Risk Management Activities and Financial Instruments

The nature of our business necessarily involves market and financial risks. We enter into financial instrument contracts in an attempt to mitigate or eliminate these various risks. These risks and our strategy for mitigating them are more fully described in Note 5 to our Form 10-K/A beginning on page F-36.

From time to time, we enter into various financial derivative instruments that qualify as cash flow hedges. Instruments related to our power generation and natural gas liquids businesses are entered into for purposes of hedging future fuel requirements and power sales commitments for power generation and fractionation facilities and locking in future margin in the domestic natural gas liquids and power generation businesses. In addition, prior to exiting the global liquids business, we utilized these instruments to hedge price risks associated with that business. Interest rate swaps are also used to convert the floating interest-rate component of some obligations to fixed rates.

During the three- and six-month periods ended June 30, 2003 and 2002, there was no material ineffectiveness from changes in fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. Additionally, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.

The balance in cash flow hedging activities, net at June 30, 2003 is expected to be reclassified to future earnings, contemporaneously with the related purchases of fuel, sales of electricity or natural gas liquids and payments of interest, as applicable to each type of hedge. Of this amount, approximately $18 million of after-tax gains is estimated to be reclassified into earnings over the twelve-month period ending June 30, 2004. The actual amounts that will be reclassified to earnings over the next year and beyond could vary materially from this estimated amount as a result of changes in market conditions and other factors.

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

From time to time, we also enter into derivative instruments that qualify as fair-value hedges. We use interest rate swaps to convert a portion of our non-prepayable fixed-rate debt into variable-rate debt. During the three- and six-month periods ended June 30, 2003 and 2002, there was no ineffectiveness from changes in the fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. Additionally, no amounts were recognized in relation to firm commitments that no longer qualified as fair-value hedge items.

We have investments in foreign subsidiaries, the net assets of which are exposed to currency exchange-rate volatility. We have used derivative financial instruments, including foreign exchange forward contracts and cross-currency interest rate swaps, to hedge this exposure. As of June 30, 2003, we had no net investment hedges in place. For the six months ended June 30, 2002, approximately $64 million of net losses related to these contracts were included in the foreign currency translation adjustment. This amount offsets the cumulative translation gains of the underlying net investments in foreign subsidiaries for the period the derivative financial instruments were outstanding.

During the six months ended June 30, 2003, our efforts to exit the U.K. CRM business and the European communications business were substantially completed. As required by SFAS No. 52, “Foreign Currency Translation,” unrealized gains and losses resulting from translation and financial instruments utilized to hedge currency exposures previously recorded in stockholders’ equity were recognized in income, resulting in an after-tax loss of approximately $10 million.

Accumulated other comprehensive loss, net of tax, is included in stockholders’ equity on the unaudited condensed consolidated balance sheets as follows (in millions):

	June 30, 2003			December 31, 2002
Cash Flow Hedging Activities, Net	$	32		$	8
Foreign Currency Translation Adjustment		24			3
Minimum Pension Liability		(66	)		(66	)
Accumulated Other Comprehensive Loss, Net of Tax	$	(10	)	$	(55	)

Note 5—Unconsolidated Investments

A summary of our unconsolidated investments is as follows (in millions):

	June 30, 2003		December 31, 2002
Equity Affiliates:
GEN investments	$	560	$	542
NGL investments		95		102
CRM investments		2		4
Total equity affiliates		657		648
Other affiliates, at cost		29		20
Total Unconsolidated Investments	$	686	$	668

17

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Summarized aggregate financial information for unconsolidated investments and our equity share thereof was (in millions):

	Six Months Ended June 30,
	2003				2002
	Total		Equity Share		Total		Equity Share
Revenues	$	1,552	$	634	$	1,851	$	703
Operating income		270		118		263		90
Net income		215		94		210		72

As previously described in the Form 10-K/A, a petition was filed in the United States Bankruptcy Court for the District of Minnesota by several former officers of NRG Energy, the parent company of the partner and operator in two of our joint ventures (including our largest investment, West Coast Power), to put NRG Energy into bankruptcy. This proceeding was settled and the involuntary bankruptcy was dismissed in early May 2003. NRG Energy and certain of its affiliates subsequently made voluntary Chapter 11 bankruptcy filings in the United States Bankruptcy Court for the Southern District of New York, together with a filing of a plan of reorganization. Although we cannot predict with any degree of certainty the effects of these actions on the operations of the joint ventures, NRG Energy has stated that it will continue to operate in the ordinary course of business and we do not expect these filings to significantly impact the joint ventures.

In June 2003, West Coast Power, a joint venture owned equally by Dynegy and NRG Energy with generation assets in California, repaid the remaining outstanding balance on a $120 million non-recourse bank facility with cash on hand within the joint venture entity. Concurrent with the retirement of the bank facility, West Coast Power entered into a $50 million cash collateralized letter of credit facility that will be used to collateralize West Coast Power’s obligations.

We own a 50 percent interest in Nicor Energy, a joint venture with Nicor Inc. that markets retail gas and electricity in the Midwest. During the first quarter of 2003, substantially all of the operations of Nicor Energy were sold, and we substantially liquidated the company in the second quarter 2003.

Note 6—Debt

Revolvers and Commercial Paper.    During the three- and six-month periods ended June 30, 2003, we repaid $840 million and $128 million, respectively, under our revolving credit facilities. Additionally, during the three- and six-month periods ended June 30, 2003, we eliminated an aggregate of approximately $160 million and $590 million, respectively, of letters of credit under these revolving credit facilities. During the period from June 30, 2003 through August 11, 2003, we issued $126 million of letters of credit under these revolving credit facilities.

On April 2, 2003, DHI entered into a $1.66 billion credit facility consisting of:

• a $1.1 billion DHI secured revolving credit facility, which matures on February 15, 2005;

• a $200 million DHI secured term loan (“Term A Loan”), which was scheduled to mature on February 15, 2005; and

• a $360 million DHI secured term loan (“Term B Loan”), which matures on December 15, 2005.

18

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

The credit facility replaced, and preserved the commitment of each lender under, DHI’s $900 million and $400 million former revolving credit facilities, which had maturity dates of April 28, 2003 and May 27, 2003, respectively, and Dynegy’s $360 million DGC secured debt, which had a maturity date of December 15, 2005. The restructured credit facility provides funding for general corporate purposes. The revolving facility is also available for the issuance of letters of credit. Borrowings under the credit facility bear interest, at our option, at (i) a base rate plus 3.75% per annum or (ii) LIBOR plus 4.75% per annum. A letter of credit fee is payable on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 4.75% of such undrawn amount. A 0.15% fronting fee is incurred upon the issuance of letters of credit. An unused commitment fee of 0.50% per annum is payable on the unused portion of the revolving facility. Please read Note 10 to the Form 10-K/A beginning on page F-47 for further discussion of our restructured credit facility.

We incurred upfront fees aggregating approximately $41 million in connection with the April 2003 credit facility. Such amounts have been capitalized and are being amortized over the term of the credit facility.

Amended Credit Facility.    In July 2003, in conjunction with the long-term refinancing and restructuring transactions described elsewhere in this report, we entered into an amendment to DHI’s credit facility to, among other things, permit the consummation of the then-proposed transactions, which included repaying a portion of the credit facility. The amendment became effective on August 11, 2003 upon closing of DHI’s private placement offering of $1.45 billion in second priority senior secured notes and Dynegy’s offering of $175 million in convertible subordinated debentures.

The amended credit facility consists of:

• a $1.1 billion secured revolving credit facility that matures on February 15, 2005; and

• a secured term loan (Term B Loan) that matures on December 15, 2005 in an aggregate principal amount of approximately $245 million.

The amended credit facility contains mandatory commitment reductions and prepayment events. The commitments, subject to specified exceptions, must be permanently reduced:

• with 100% of the net cash proceeds of all non-ordinary course asset sales, except that a portion of such proceeds may be used to make mandatory prepayments on the Dynegy Junior Unsecured Subordinated Notes due 2016 issued in connection with the Series B Exchange, which we refer to in this report as the junior notes, so long as the revolving commitments are reduced in connection with such prepayments according to a formula, with such reduction in the commitments in connection with any prepayments on the junior notes not to exceed $100 million;

• with 50% of the net cash proceeds from the issuance of equity, subordinated debt or additional second lien debt (other than the proceeds from the DHI second priority senior secured notes and the Dynegy convertible subordinated debentures), except that we may retain up to $250 million of proceeds of equity issuances and, in addition to such retained amounts, such proceeds may be used to make mandatory prepayments on the junior notes so long as the revolving commitments are reduced in connection with such prepayments according to a formula, with such reduction in the commitments in connection with any prepayments on the junior notes not to exceed $100 million;

• with 100% of the net cash proceeds from the issuance of senior debt, other than the proceeds from the DHI second priority senior secured notes;

• with 50% of extraordinary receipts (as defined in the amended credit facility); and

19

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

• in connection with the payment of cash dividends on the Dynegy Series C Preferred Stock issued in connection with the Series B Exchange or the repurchase of DHI Senior Notes that have maturity dates on or after 2007, by an amount determined according to a formula, provided that we have $500 million of liquidity after giving effect to such payment or repurchase.

The amended credit facility provides for no amortization of principal amounts outstanding prior to the maturity dates except upon the occurrence of a mandatory prepayment event.

The amended credit facility generally prohibits us and our subsidiaries, including DHI but excluding Illinois Power, from pre-paying, redeeming or repurchasing outstanding debt or preferred stock, except that we may, among other things:

• pay cash dividends on the Dynegy Series C Preferred Stock issued in connection with the Series B Exchange, subject to the following conditions: (i) no default shall have occurred and be continuing, (ii) a voluntary prepayment of the credit facility is made in connection with such payments according to a formula, and (iii) we must have $500 million of liquidity after giving effect to such payment;

• prepay, repurchase or redeem the balance of DHI’s outstanding 2005-2006 senior notes, the CoGen Lyondell facility, the Project Alpha credit facility and the Riverside facility with the net cash proceeds of extraordinary receipts (as defined in the amended credit facility) or issuances of equity or subordinated debt, or cash on hand; provided that in the case of any prepayment of the Project Alpha credit facility or the Riverside facility, we must have $500 million of liquidity for ten days prior to and as of the date of such prepayment; and

• repurchase up to $100 million of DHI senior notes that have maturity dates on or after 2007 so long as we have $500 million of liquidity for ten days prior to and as of the date of such repurchase and the credit facility is prepaid in connection with such payments according to a formula; provided that up to $300 million of such notes (including any amount repurchased under the foregoing clause) may be repurchased without a concurrent prepayment under the credit facility with the net cash proceeds of extraordinary receipts (as defined in the amended credit facility) or issuances of equity or subordinated debt.

The amended credit facility also includes a change to the financial covenant that requires a specified level of Secured Debt to EBITDA (in each case as defined in the amended credit facility). Under the amended covenant, we and our subsidiaries, including DHI but excluding Illinois Power and DGC, are prohibited from permitting our Secured Debt/EBITDA ratio from and after September 30, 2003 to be greater than the ratios set forth below:

Measurement Period Ending	Maximum Secured Debt/ EBITDA Ratio
September 30, 2003	9.0:1.0
December 31, 2003	9.0:1.0
March 31, 2004	8.4:1.0
June 30, 2004	8.0:1.0
September 30, 2004	7.1:1.0
December 31, 2004 and each fiscal quarter thereafter	6.7:1.0

The definition of EBITDA in the amended credit facility specifically excludes, among other items, (i) Discontinued Business Operations, as defined therein (including third-party marketing and trading, communications and tolling arrangements), (ii) disclosed litigation, (iii) extraordinary gains or losses, (iv) any impairment, abandonment, restructuring or similar non-cash expenses, (v) interest expense, (vi) gains/losses on extinguishment of debt and (vii) turbine cancellation payments up to $50 million in the aggregate.

20

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Refinancing.    In August 2003, we consummated a series of refinancing transactions, which we refer to as the Refinancing, comprised of the following:

• Issuance by DHI of $1.45 billion of second priority senior secured notes in a private placement transaction pursuant to Rule 4(2) of the Securities Act of 1933, which notes are secured on a second priority basis by substantially the same collateral that secures the obligations under DHI’s credit facility, which consists of a substantial portion of the available assets and stock of our direct and indirect subsidiaries, excluding Illinois Power;

• Issuance by Dynegy of $175 million of convertible subordinated debentures in a private placement transaction pursuant to Rule 4(2) of the Securities Act of 1933, which debentures are convertible into Dynegy’s Class A common stock and guaranteed on a senior unsecured basis by DHI; and

• A cash tender offer and related consent solicitation for all of DHI’s outstanding 8.125% Senior Notes due 2005, 6 ³/4% Senior Notes due 2005 and 7.450% Senior Notes due 2006.

Pursuant to the cash tender offer, which expired on August 8, 2003, we purchased approximately $282 million in principal amount of the 8.125% Senior Notes due 2005, approximately $150 million in principal amount of the 6 ³/4% Senior Notes due 2005 and approximately $180 million in principal amount of the 7.450% Senior Notes due 2006. We paid approximately $5 million above par value of the notes in connection with the purchase of these notes and the consent fee paid in connection with the related solicitation of the consents to eliminate several of the restrictive covenants and certain other provisions previously contained in the indentures governing these notes. As a result of obtaining the required consents, DHI executed and delivered supplemental indentures setting forth amendments to the applicable indentures, which govern the notes remaining outstanding following the expiration of the tender offer.

The net proceeds from the Refinancing, along with cash on hand, were utilized to make the cash payment required under the Series B Exchange, as described below, and to prepay certain of our indebtedness including:

• Prepay in full the $200 million Term A Loan outstanding under the DHI credit facility;

• Prepay approximately $115 million of the $360 million Term B Loan outstanding under the DHI credit facility;

• Repurchase approximately $612 million in the aggregate of DHI’s outstanding 8.125% Senior Notes due 2005, 6 ³/4% Senior Notes due 2005 and 7.45% Senior Notes due 2006; and

• Prepay the $696 million of debt outstanding under the Black Thunder secured financing.

The prepayment of the debt above will result in accelerated charges during the third quarter 2003 of approximately $20 million, pre-tax, of unamortized financing costs and the settlement value of the associated interest rate hedge instruments. We incurred upfront fees aggregating approximately $60 million in connection with the Refinancing. Such amounts have been capitalized and will be amortized over the term of the Refinancing.

DHI Second Priority Senior Secured Notes.    In connection with the Refinancing, in August 2003 DHI issued $1.45 billion in second priority senior secured notes, comprised of $225 million in floating rate notes due 2008 which accrue interest at a rate of LIBOR plus 650 basis points (reset on a quarterly basis), $525 million of 9.875% notes due 2010 with a yield to maturity of 10.0% and $700 million in 10.125% notes due 2013 with a yield to maturity of 10.25%. Each of DHI’s existing and future wholly owned domestic subsidiaries that guarantee DHI’s obligations under its existing credit facility guarantee the obligations under the notes on a senior secured basis. In addition, Dynegy and its other subsidiaries that guarantee DHI’s existing credit facility guarantee the obligations under the notes on a senior secured basis.

21

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

The notes and guarantees are senior obligations secured by a second-priority lien on, subject to certain exceptions and permitted liens, all of DHI’s and its guarantors’ existing and future property and assets that secure DHI’s obligations under its credit facility.

The indenture governing the notes contains restrictive covenants that limit the ability of DHI and its subsidiaries that guarantee the notes to, among other things:

• pay dividends or distributions on, or redeem or repurchase, capital stock;

• make investments;

• incur or guarantee additional indebtedness;

• create certain liens;

• engage in sale and leaseback transactions;

• make restricted payments;

• consolidate, merge or transfer all or substantially all of its assets; or

• engage in certain transactions with affiliates.

These covenants are described in more detail in the indenture governing the notes, which is filed as an exhibit to this Form 10-Q.

Dynegy Convertible Subordinated Debentures.    Concurrently with the issuance of DHI’s second priority senior secured notes, Dynegy issued $175 million in 4.75% convertible subordinated debentures due 2023. We have also granted the initial purchasers of the debentures a 30-day option to purchase up to $50 million of additional debentures on these same terms. The debentures are convertible into shares of our Class A common stock at any time at a conversion price of $4.1210 per share, subject to specified adjustments for dividend payments and other actions. The debentures are subordinated to Dynegy’s existing and future senior indebtedness and effectively subordinated to all indebtedness and liabilities of Dynegy’s non-guarantor subsidiaries. The debentures are guaranteed on a senior unsecured basis by DHI. We have agreed to file a registration statement covering resale of the debentures and the Class A common stock issuable upon conversion of the debentures, subject to the requirement to pay additional interest if such registration statement does not become effective within 360 days from August 11, 2003.

The debentures are described in more detail in the indenture governing the debentures, which is filed as an exhibit to this Form 10-Q.

ChevronTexaco Series B Preferred Stock Restructuring.    Also in August 2003, we consummated a restructuring of the $1.5 billion in Series B Mandatorily Convertible Redeemable Preferred Stock previously held by a subsidiary of ChevronTexaco. Pursuant to the restructuring, which we refer to as the Series B Exchange, this ChevronTexaco subsidiary exchanged its Series B preferred stock for the following:

• a $225 million cash payment;

• $225 million principal amount of Junior Unsecured Subordinated Notes due 2016 issued by Dynegy; and

• 8 million shares of Dynegy’s Series C Convertible Preferred Stock due 2033 (liquidation preference of $50 per share).

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

The junior notes bear interest at a rate of 9.00% per annum during the first two years and a rate of 13.75% per annum thereafter, in each case, compounded semi-annually and, at our option, payable in kind by issuance of additional junior notes. The junior notes are subject to mandatory prepayment during the first two years and until such time as ChevronTexaco elects otherwise with:

• 100% of net cash proceeds from the issuances of qualified capital stock in excess of the first $250 million of qualified capital stock issued after the Series B Exchange;

• 50% of net cash proceeds from issuances of subordinated or convertible debt, mandatorily redeemable preferred stock or convertible equity (excluding refinancings thereof);

• 25% of net cash proceeds from asset sales (other than sales of Illinois Power assets or equity) up to $200 million of asset sale proceeds in the aggregate from and after the consummation of the Series B Exchange; and

• 75% of net cash proceeds from the sale of Illinois Power assets or equity, provided that such net cash proceeds will not include any amounts used for the payment of any debt associated with Illinois Power.

To the extent any mandatory prepayment is not made due to restrictions contained in our current or future debt instruments or applicable law, interest will accrue at the rate of 13.75% on the blocked prepayment amount. The junior notes may be prepaid at our option at par plus accrued interest at any time prior to maturity, provided, however, that the junior noteholders may, at any time after the date that is 90 days prior to the two-year anniversary of the closing of the Series B Exchange, elect to terminate the mandatory prepayment provisions. If such an election is made, we will be prohibited from redeeming the junior notes through the seven-year anniversary of the Series B Exchange. Following this seven-year anniversary, we would then be entitled to redeem the junior notes at par plus accrued interest plus a premium equal to one-half the coupon, declining ratably to par in year ten.

With respect to the Series C preferred stock, dividends are payable at a rate of 5.5% per annum in cash semi-annually. At our election, we may defer dividend payments for up to 10 consecutive semi-annual dividend payment periods. Upon termination of any deferral period, all accrued and unpaid amounts are due in cash. We may not pay dividends on our common stock during any deferral period. Additionally, if we fail to obtain shareholder approval within one year for conversion of the Series C preferred stock into shares of our Class B common stock, the dividend rate on the Series C preferred stock will increase to 10% until such time as we obtain such approval or it is determined that such approval is not required under NYSE rules and other applicable laws and regulations. Following the receipt of such approval, the shares of Series C preferred stock generally are convertible, at the option of the holder, at a price of $5.78 per share. The initial holder of the Series C preferred stock may not transfer the shares of the Series C preferred stock (other than to affiliates) until the earlier of (a) 18 months following the closing of the Series B Exchange or (b) 120 days following the consummation of one or more public or private sales of our qualified capital stock resulting in gross proceeds to us of at least $250 million. On or after the third anniversary of this “lock-up” period, we may, at our option, cause the Series C preferred stock to be converted into shares of our Class B common stock at any time the closing price of our Class A common stock exceeds 130% of the conversion price then in effect for at least 20 trading days within any period of 30 consecutive trading days prior to such conversion. Upon any conversion of the Series C preferred stock, we have the right to deliver, in lieu of shares of our Class B common stock, cash or a combination of cash and shares of our Class B common stock. At any time after the tenth anniversary of the closing of the Series B Exchange, we may, at our option, redeem all of the shares of Series C preferred stock for a redemption price equal to $50 per share plus accrued and unpaid dividends.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

In connection with the Series B Exchange, we also amended the shareholder agreement and registration rights agreement between us and ChevronTexaco and entered into two new registration rights agreements covering the junior notes, the Series C preferred stock and the shares of Class B common stock issuable on the conversion of the Series C preferred stock.

As part of the Series B Exchange, we also renegotiated certain prepayment arrangements with ChevronTexaco such that ChevronTexaco returned to us approximately $40 million in pre-payments relating to our commodity purchase obligations and converted our prepayment obligation from thirty days to seven days.

For a complete description of the junior notes and the Series C preferred stock, please read the agreements between us and ChevronTexaco entered into in connection with the Series B Exchange that are filed as exhibits to this Form 10-Q.

Renaissance and Rolling Hills Credit Facility.    In July 2002, we completed a $200 million interim financing, bearing interest at LIBOR plus 1.38%. This loan was scheduled to mature in January 2003 and was secured by interests in our Renaissance and Rolling Hills merchant power generation facilities. In January 2003, we repaid $94 million of this facility and refinanced the remaining $106 million. The maturity date on the remaining $106 million was extended to October 15, 2003 and the interest rate on the remaining balance was changed to LIBOR plus 5%. On April 16, 2003, we prepaid the remaining $106 million.

Illinova Senior Notes.    In March 2003, we purchased on the open market $5 million in aggregate principal amount of Illinova’s 7.125% Senior Notes due 2004. The repurchased notes have been cancelled and are no longer outstanding. As a result, $95 million in aggregate principle amount of the notes remain outstanding at June 30, 2003 and is included within current portion of long-term debt on the unaudited condensed consolidated balance sheets.

Illinois Power Term Loan.    In May 2003, Illinois Power used a portion of the proceeds from its December 2002 sale of $550 million in 11½% Mortgage Bonds due 2010, $150 million of which were issued in January 2003 following receipt of a required approval from the ICC, to pay down the $100 million then outstanding under its one-year term loan.

Note 7—Related Party Transactions

In connection with our previously announced exit from third-party risk management aspects of the marketing and trading business, we agreed with ChevronTexaco to terminate the natural gas purchase agreement between the parties and to provide for an orderly transition of responsibility for marketing ChevronTexaco’s domestic natural gas production. This agreement did not affect our contractual agreements with ChevronTexaco relative to its U.S. natural gas processing and the marketing of its domestic natural gas liquids. The cancellation of the agreement was effective January 1, 2003. In accordance with the termination of the natural gas purchase agreement, we paid $13 million to ChevronTexaco. As part of the transition, we also provided scheduling, accounting and reporting services to ChevronTexaco through June 2003. We also engage in other transactions with ChevronTexaco, including purchases and sales of natural gas, natural gas liquids and crude oil, which we believe are executed on terms that are fair and reasonable.

In August 2003, we consummated a restructuring of the $1.5 billion in Series B Mandatorily Convertible Redeemable Preferred Stock previously held by a subsidiary of ChevronTexaco. In conjunction with the restructuring, we will recognize approximately $1.21 billion as a preferred stock dividend credit in the third quarter 2003, offset by a $660 million reduction to additional paid in capital, resulting in a net increase to equity of approximately $550 million. Please read Note 6—Debt—ChevronTexaco Series B Preferred Stock Restructuring for further discussion.

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Note 8—Earnings (Loss) Per Share

Basic earnings (loss) per share represents the amount of earnings (loss) for the period available to each share of common stock outstanding during the period. Diluted earnings (loss) per share represents the amount of earnings (loss) for the period available to each share of common stock outstanding during the period plus each share that would have been outstanding assuming the issuance of common shares for all dilutive potential common shares outstanding during the period. In-the-money outstanding options contribute to the differences between basic and diluted shares outstanding in all periods. The diluted shares do not include the effect of the preferential conversion to Class B common stock of the Series B Mandatorily Convertible Redeemable Preferred Securities previously held by ChevronTexaco, as such inclusion would be anti-dilutive.

When an entity has a net loss from continuing operations, SFAS No. 128, “Earnings per Share,” prohibits the inclusion of potential common shares in the computation of diluted per-share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three and six months ended June 30, 2003 and 2002.

Note 9—Commitments and Contingencies

Set forth below is a description of our material legal proceedings. In addition to the matters described below, we are party to legal proceedings arising in the ordinary course of business. In the opinion of management, the disposition of these ordinary course matters will not have a material adverse effect on our financial condition, results of operations or cash flows.

We record reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable in accordance with SFAS No. 5, “Accounting for Contingencies.” For environmental matters, we record liabilities when environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Please see Note 2—Accounting Policies beginning on page F-17 of the Form 10-K/A for further discussion. During the second quarter 2003, we recorded a pre-tax litigation reserve of $50 million related to contingencies for which the amount of loss became probable and reasonably estimable during the period.

With respect to some of the items listed below, we have determined that a loss is not probable or that any such loss, to the extent probable, is not reasonably estimable. Notwithstanding the foregoing, management has assessed these matters based on currently available information and made an informed judgment concerning the potential outcome of such matters, giving due consideration to the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may, as a result of facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.

Shareholder Litigation.    Since April 2002, a number of purported class action lawsuits have been filed on behalf of purchasers of our publicly traded securities generally during the period between April 2001 and April 2002. These lawsuits principally assert that Dynegy and certain of our executive officers and directors violated the federal securities laws in connection with our accounting treatment and disclosure of Project Alpha. These lawsuits have been consolidated in the United States District Court for the Southern District of Texas (Houston Division). On October 28, 2002, the court in which the cases have been consolidated appointed the Regents of the University of California as lead plaintiff and the law firm of Milberg Weiss as class counsel. On June 6,

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

2003, plaintiffs filed a consolidated amended complaint. This amended complaint included, among other items, additional allegations regarding Project Alpha, round-trip trading, the submission of false trade reports to publications that calculate natural gas index prices, the alleged manipulation of the California power market, and the restatement of financial statements for periods since 1999. The original complaint covered a class period from April 2001 to April 2002. The amended complaint extended the class period to encompass the period from January 27, 2000 to July 22, 2002. An adverse result could have a material adverse effect on our financial condition, results of operations and cash flows. In light of the amended complaint, including its new allegations and extended class period, we have recorded a reserve in connection with this litigation.

In addition, several derivative lawsuits have been filed in which we are a nominal defendant. Those claims have all been consolidated into two groups—one derivative group pending in Federal court (Derusha) and the other derivative group pending in state court (Gillies). The lawsuits relate to Project Alpha, round-trip trades and alleged manipulation of the California power market. The lawsuits seek recovery on behalf of Dynegy from various present and former officers and directors. Dynegy’s motion to dismiss the federal derivative claim is currently pending and is set for hearing on August 25, 2003. All discovery in the state derivative claim has currently been stayed by the Court of Appeals as it considers Dynegy’s motion to dismiss those claims for a lack of standing because of a failure to make a demand on the corporation prior to filing. Because of the nature of these derivative lawsuits, we do not expect to incur any material liability with respect to these derivative claims.

ERISA/401(k) Litigation.    On August 15, 2002, a purported class action complaint was filed against Dynegy in the United States District Court for the Southern District of Texas (Houston Division) alleging violations of the Employee Retirement Income Security Act. The lawsuit concerns the Dynegy Inc. 401(k) Savings Plan and claims that our Board and former and current officers involved in the administration of the 401(k) Plan breached their fiduciary duties to the Plan’s participants and beneficiaries in connection with the Plan’s investment in the Dynegy common stock fund. The lawsuit seeks unspecified damages for the losses to the Plan resulting from the alleged breaches of fiduciary duties, as well as attorney’s fees and certain other costs. The putative class was originally defined as participants holding Dynegy common stock in the plan as of April 17, 2001 or later. On February 12, 2003, the plaintiffs filed an amended complaint, which extended the putative class period back to April 27, 1999. Additional past Board members were named as defendants, as were past and present members of our Benefit Plans Committee. The amended complaint alleges that our earnings and business conditions were misstated from 1999 forward and that, during such period, Dynegy Inc. and members of the Board, including members of the Compensation and Human Resources Committee of the Board, breached fiduciary duties by failing to disclose to the Benefit Plans Committee information regarding risks associated with its business due to misstatements about revenues, earnings and operations, which information was material to the appropriateness of Dynegy common stock as an investment option, and by failing to monitor the Benefit Plans Committee. The amended complaint further alleges that the Benefit Plans Committee breached fiduciary duties by failing to disclose complete and accurate information with respect to the suitability of investing in common stock and by failing to eliminate Dynegy common stock as a Plan investment option, and that the Benefit Plans Committee breached its duty of loyalty to discharge its duty to the Plan solely in the interest of the participants and beneficiaries. The amended complaint also alleges that we breached co-fiduciary duties under ERISA and, to the extent we are found not to be a fiduciary, that we benefited by knowingly participating in fiduciary breaches by others. The plaintiff filed a second amended complaint on April 7, 2003, which names as additional defendants certain former employees who served on a predecessor committee to the Benefit Plans Committee. The plaintiff also included in the second amended complaint allegations relating to Project Alpha, round-trip trades and the gas price index investigation. The plaintiff filed a third amended complaint on June 10, 2003, which names, as additional defendants, certain former employees who served on a predecessor committee to the

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Benefits Plan Committee as well as Vanguard Fiduciary Trust Company, which served as the Trustee of the trust that held the assets of the Plan during a portion of the putative class period. On July 11, 2003, Dynegy filed a motion to dismiss this action.

We are analyzing these claims and intend to defend against them vigorously. It is not possible to predict with certainty whether we will incur any liability or to estimate the damages, if any, that might be incurred in connection with this lawsuit. However, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

Baldwin Station Litigation.    Illinois Power and DMG, collectively referred to in this section as the Defendants, are currently the subject of an NOV from the EPA and a complaint filed by the EPA and the Department of Justice alleging violations of the Clean Air Act, the regulations promulgated thereunder and certain Illinois regulations adopted pursuant to the Clean Air Act. Eight similar notices and complaints were filed against other owners of coal-fired power plants. Both the NOV and the complaint allege that certain equipment repairs, replacements and maintenance activities at the Defendants’ three Baldwin Station generating units constituted “major modifications” under the Prevention of Significant Deterioration (PSD), the New Source Performance Standard (NSPS) regulations and the applicable Illinois regulations, and that the Defendants failed to obtain required operating permits under the applicable Illinois regulations. When activities that meet the definition of “major modifications” occur and are not otherwise exempt, the Clean Air Act and related regulations generally require that the generating facilities at which such activities occur meet more stringent emissions standards, which may entail the installation of potentially costly pollution control equipment.

We have undertaken activities to significantly reduce emissions at the Baldwin Station since the complaint was filed in 1999. In 2000, the Baldwin Station was converted from high to low sulfur coal, resulting in sulfur dioxide emission reductions of over 90% from 1999 levels. Furthermore, selective catalytic reduction equipment has been installed at two of the three units at Baldwin Station, resulting in significant emission reductions of nitrogen oxides. However, the EPA may seek to require the installation of the “best available control technology,” or the equivalent, at the Baldwin Station. Current estimates indicate that we could incur capital expenditures of up to $410 million if the installation of best available control technology were required. The EPA also has the authority to seek penalties for the alleged violations at the rate of up to $27,500 per day for each violation.

On February 19, 2003, the Court granted our motion for partial summary judgment based on the five-year statute of limitations. As a result, the EPA is not permitted to seek any monetary civil penalties for claims related to construction without a permit under the PSD regulations. The Court’s ruling also precludes monetary civil penalties for a portion of the claims under the NSPS regulations and the applicable Illinois regulations. We believed that we had meritorious defenses against the remaining claims and vigorously defended against them at trial. The trial to address these remaining issues began in June 2003. The submission of evidence concluded on June 27, 2003. The final briefing in the trial is expected to occur in August 2003, and closing arguments are scheduled for September 29, 2003. We have recorded a reserve for potential penalties that could be imposed if the EPA were to prosecute successfully these remaining claims for penalties.

None of the Defendants’ other facilities are covered in the complaint and NOV, but the EPA has officially requested information, and we have provided such information, concerning activities at the Defendants’ Vermilion, Wood River and Hennepin plants as well as the Danskammer and Roseton plants operated by other Dynegy subsidiaries. The EPA could eventually commence enforcement actions based on activities at these plants.

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

California Market Litigation.    Six class action lawsuits were filed in 2000-2001 against various Dynegy entities based on the events occurring in the California power market. All six complaints allege violations of California’s Business and Professions Code, Unfair Trade Practices Act and other related statutes. The plaintiffs allege that the defendants, including the owners of in-state generation and various power marketers, conspired to manipulate the California wholesale power market to the detriment of California consumers. Included among the acts forming the basis of the plaintiffs’ claims are the alleged improper sharing of generation outage data, improper withholding of generation capacity and the manipulation of power market bid practices. The plaintiffs seek unspecified treble damages. Dynegy initially immediately removed and consolidated these cases to Federal court before Judge Robert Whaley on the grounds of FERC preemption and the filed rate doctrine.

The plaintiffs moved in opposition to remand, and the cases were remanded to state court on July 31, 2001. All six lawsuits were consolidated before Judge Sammartino, Superior Court Judge for the County of San Diego (the “Gordon-Hendricks Cases”). Subsequent to this consolidation, two of the defendants filed cross-complaints against a number of corporations and governmental agencies that sold power in California’s wholesale energy markets. Four cross-defendants removed the six cases to the United States District Court for the Southern District of California (San Diego) and the cases were returned to Multi-District Litigation Proceeding 1405, referred to as the California Wholesale Electricity Antitrust Litigation. The original plaintiffs in the six consolidated complaints again filed motions to remand the consolidated cases back to state court, which motions were granted. Some of the cross-defendants then appealed that ruling and, prior to the remand taking effect, the Ninth Circuit Court of Appeals granted review and stayed the remand order. A ruling by the Ninth Circuit is not expected until late this year at the earliest.

On April 17 and October 7, 2002, respectively, two additional cases,People of the State of California ex rel. Bill Lockyer, AG andPublic Utility District No. 1 of Snohomish County, were consolidated before Judge Whaley with the six cases referenced above pursuant to Multi-District Litigation Proceeding 1405. Dynegy filed motions to dismiss these cases on the grounds of FERC preemption and the filed rate doctrine and, on March 25 and January 6, 2003, respectively, Judge Whaley dismissed with prejudice both cases. The plaintiffs have appealed both decisions, and the appeals are currently set to be heard before the Ninth Circuit Court of Appeals in August 2003.

In addition to the eight consolidated lawsuits discussed above, nine other putative class actions and/or representative actions were filed on behalf of business and residential electricity consumers against Dynegy and numerous other defendants between April and October, 2002 (“T&E Pastorino Cases”). The lawsuits were filed in various state courts and in the United States District Court for the Northern District of California. The defendants named in these lawsuits are various power generators and marketers, including Dynegy and some of our affiliates. The complaints allege unfair, unlawful and deceptive practices in violation of the California Unfair Business Practices Act and seek to enjoin illegal conduct, restitution and unspecified damages. While some of the allegations in these lawsuits are similar to the allegations in the other six lawsuits, these lawsuits include additional allegations based on events occurring subsequent to the filing of the other six lawsuits. These additional allegations include allegations similar to those made by the California Attorney General in the March 11, 2002 lawsuit described below as well as allegations that contracts between these power generators and the CDWR constitute unfair business practices resulting from market manipulation. The lawsuits filed in state court were removed to federal court (with one subsequently remanded) and ultimately these cases were added to the California Wholesale Electricity Antitrust Litigation (proceeding 1405) on October 18, 2002. On June 10, 2003 Dynegy filed a motion to dismiss, based upon the filed rate doctrine and federal preemption principles, the eight cases currently pending in federal court and an oral hearing on that motion occurred on July 31, 2003.

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Dynegy awaits the court’s ruling. The ninth case,Millar v. Allegheny Energy Supply et al., was recently remanded to state court and Dynegy is preparing to file a demurrer to dismiss these allegations.

In December 2002, two additional actions were filed with allegations similar to those in the California Wholesale Electricity Antitrust Litigation on behalf of residents of the State of Washington and residents of the State of Oregon.Symonds v. Dynegy was filed in the United States District Court for the Western District of Washington.Lodewick v. Dynegy was originally filed in the State Court of Oregon and was later removed to the United States District Court for the District of Oregon. Defendants in these matters sought to have these actions included in the California Wholesale Electricity Antitrust Litigation; however, the Multi-District Litigation panel indicated that since Judge Whaley was a resident of the State of Washington, it was unlikely that the cases would be assigned to the California Wholesale Electricity Antitrust Litigation. In May 2003, the plaintiffs voluntarily dismissed these actions and refiled them asEgger v. Dynegy Inc., et al. in the Superior Court of California in the County of San Diego as a class action complaint. The suit alleges violations of the Cartwright Act and unfair business practices. The action is brought on behalf of consumers and businesses in Oregon, Washington, Utah, Nevada, Idaho, New Mexico, Arizona and Montana that purchased energy from the California market. We have moved to remove the action from state court and consolidate it with existing actions pending before Judge Walker in the United States District Court for the Northern District of California. Most recently, the Attorney General for the State of Montana has filed a case alleging similar antitrust and market manipulation claims styledPeople of the State of Montana ex rel. Mike McGrath v. Williams et al. Dynegy has not yet been served with this lawsuit.

On November 20, 2002, a class action was filed in the Superior Court of the State of California for the County of Los Angeles styledCruz Bustamante v. The McGraw Hill Companies, Inc., et al. on behalf of purchasers of natural gas and electricity in the State of California. Plaintiffs alleged damages as the result of the defendants’ alleged false reporting of pricing and volume information regarding natural gas transactions. On July 8, 2003, the Court granted defendants’ demurrers on the basis of FERC preemption and the filed-rate doctrine and dismissed the complaints as filed. The judge has granted plaintiffs leave to amend.

We believe that we have meritorious defenses to these claims and intend to defend against them vigorously. It is not possible to predict with certainty whether we will incur any liability or to estimate the range of possible loss, if any, that we might incur in connection with this lawsuit. However, an adverse result in any of these proceedings could have a material adverse effect on our financial condition, results of operations and cash flows.

FERC and Related Regulatory Investigations.

Requests for Refunds.    On July 25, 2001, the FERC initiated a hearing to establish refunds to electricity customers, or offsets against amounts owed to electricity suppliers, during the period of October 2, 2000 through June 19, 2001. In particular, the FERC established a methodology to calculate mitigated market clearing prices in the Cal ISO and the Cal PX markets. During March 2002 and August 2002, hearings on this matter were held before an administrative law judge. On December 12, 2002, the administrative law judge issued his recommendations regarding the appropriate level of refunds or offsets. Those recommendations, however, do not fully reflect proposed refund or offset amounts for individual companies. In order to determine such amounts, the Cal ISO and Cal PX must rerun their settlement processes in a compliance stage of the proceeding. We subsequently filed briefs with the FERC supporting certain aspects of the administrative law judge’s decision and opposing others. The matter is awaiting a decision from the FERC.

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

In August 2002, the FERC requested comments on a proposal made by the FERC staff to change the method for determining natural gas prices for purposes of computing the mitigated market-clearing price that it intends to utilize in calculating refunds for sales of power in California power markets during the period from October 2, 2000 to June 19, 2001. The proposal replaces the gas prices used in the computation, thus reducing the mitigated market clearing price for power and increasing calculated refunds, subject to a provision that generally would provide full recoverability of gas costs paid by the generators to unaffiliated third parties. This proposal was adopted by the FERC on March 26, 2003.

On November 20, 2002, the FERC granted a motion filed jointly by the People of the State of California, ex rel. Bill Lockyer, Attorney General, the California Electricity Oversight Board, the Public Utilities Commission of the State of California, Pacific Gas and Electric Company, and Southern California Edison Company, referred to in this section as the California Parties, to reopen the record in the refund proceeding to allow 100 days of discovery into allegations of market manipulation. The California Parties submitted the results of their discovery effort on March 3, 2003. Other parties also made such submissions. The California Parties sought increased refunds for the period from October 2, 2000 to June 19, 2001 based on, among other things, the adoption of the FERC staff’s proposal to change the gas prices used in computing refunds. The California Parties also sought refunds for the period from May 1, 2000 through October 1, 2000. We submitted our response on March 20, 2003. On March 27, 2003, the FERC issued a decision in the refund case in which it essentially adopted the FERC staff’s proposal to change the gas-pricing component of the refund calculations. The FERC did, however, recognize that many generators paid higher prices for gas than would be reflected in this new calculation and provided a mechanism whereby generators can submit evidence of their actual out-of-pocket spot gas purchase costs and have those costs deducted from the refund calculations. We intend to vigorously pursue relief under this procedure. The FERC otherwise affirmed the decision by the administrative law judge, and indicated that it expected to have specific refund or offset calculations by the end of the Summer 2003. On April 25, 2003, Dynegy sought rehearing of the FERC’s decision changing the gas pricing methodology.

On June 25, 2003, the FERC issued an order to show cause why the activities of certain participants in the California power markets from January 1, 2000 to June 20, 2001, including Dynegy, did not constitute gaming and/or anomalous market behavior as defined in the Cal ISO and Cal PX tariffs. The order also requires that further trial proceedings be held to allow participants to demonstrate why they should not be found to have engaged in such gaming practices. In the event that participants’ conduct is found to violate the tariffs, the order directs the administrative law judge to quantify the extent to which the participants were unjustly enriched by such practices and orders disgorgement of all such profits from that period. Additionally, on June 25, 2003, the FERC issued an order requiring parties to demonstrate that certain bids did not constitute anomalous market behavior. Specifically, the order requires the FERC Staff to investigate all parties who bid above the level of $250/MWH in the Cal ISO and Cal PX markets during the period from May 1, 2000 to October 2, 2000. Parties identified through this process will be required to demonstrate why this bidding behavior did not violate market protocols. The order also states that, to the extent such practices are not found to be legitimate business behavior, the FERC will require the disgorgement of all unjust profits for that period and will consider other non-monetary remedies, such as the revocation of market-based rate authority. We believe that we have meritorious defenses against these claims and intend to defend against them vigorously. See “West Coast Power” below for a discussion of the reserves recorded by West Coast Power relative to its exposure in the California power market.

Other FERC and California Investigations.    On February 13, 2002, the FERC initiated an investigation of possible manipulation of natural gas and power prices in the western United States during the period from January 2001 through the present. On May 8, 2002, in response to three memoranda discovered by the FERC

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

allegedly containing evidence of market manipulation in California, the FERC issued requests for information to all sellers in the Cal ISO and Cal PX markets during 2000 and 2001 seeking information with respect to whether those sellers engaged in trading strategies described in the three memoranda. We responded to these requests, indicating that we did not engage in the trading strategies described in the three memoranda. In August 2002, the FERC staff issued its preliminary report on its investigation into trading practices in the three memoranda. We continue to provide FERC with additional information relevant to its investigation.

On March 26, 2003, the FERC staff issued its Final Report on Price Manipulation in Western Markets, addressing a number of issues. In its report, the FERC staff indicated that it appears a majority of public utility entities, and some non-public utilities, engaged in some of the above-referenced trading strategies during the two-year review period. The FERC staff also recommended that the FERC issue orders requiring that Dynegy and 36 other market participants be required to “show cause” why their activities did not violate the Cal ISO and Cal PX tariffs. Potential penalties for violation of the tariff could include disgorgement of unjust profits from activities found to be in violation of the tariff. Many of these allegations have already been raised and were answered in large part in our FERC filing of March 20, 2003. We intend to defend against them vigorously.

On April 30, 2003, the FERC issued an order adopting recommendations in its staff’s March 26, 2003 report that Dynegy and ten other companies be required to submit information with respect to internal processes for reporting trading data to publications that publish energy indices—specifically, that the employees involved in manipulations, or attempted manipulations, of the published indices have been disciplined; that the company has a clear code of conduct in place for reporting price information; that all trade data reporting is done by an entity within the company that does not have a financial interest in the published indices (preferably the chief risk officer); and that the company is cooperating fully with any government agency investigating its past reporting practices. We have complied and intend to continue complying with these requirements. Pursuant to the April 30, 2003 order, we filed, on June 16, 2003, a written response indicating that we have ceased supplying price data to trade publications and are otherwise complying with the order.

On May 21, 2002, the FERC issued requests for information to all sellers of wholesale electricity or ancillary services in the WECC and, on May 22, 2002, the FERC issued requests for information to all sellers of natural gas in the WECC or Texas, seeking information with respect to whether those sellers engaged in “wash,” “round-trip” or “sale/buyback” transactions during 2000-2001. We responded to each of these requests. Based on our investigation to date, we believe that our trading practices are consistent with applicable law and tariffs. We will continue to cooperate fully with these investigations. See “—SEC Settlement” below for a discussion of our settlement with the SEC regarding, among other things, our previous round-trip energy trades with CMS Energy.

On August 13, 2002, the FERC staff issued its preliminary report on its investigation into “wash,” “roundtrip” or “sale/buyback” transactions. In the FERC staff’s March 26, 2003 Final Report on Price Manipulation in Western Markets, it recommended that the FERC establish specific rules banning any form of prearranged wash trading activities, but made no recommendations regarding “wash” transactions specifically with respect to us.

Requests for similar information regarding the above-referenced trading strategies and wash trades with respect to electric power trading activities within the ERCOT were received from the PUCT in June 2002. We responded to each of these requests. Based on our investigation to date, we believe that our trading practices are consistent with applicable law and tariffs. The PUCT has not issued findings on its investigation and we cannot predict with certainty how the investigation will be resolved.

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For the Interim Periods Ended June 30, 2003 and 2002

On September 17, 2002, California Public Utilities Commission President Loretta Lynch released a report indicating that Dynegy and five other energy firms did not produce all available power on days in which the State of California experienced power service interruptions between November 1, 2000 and May 31, 2001. No mention is made of prosecuting the named firms in the report. However, the SEC and FERC have requested additional information and comment with respect to the report. On March 26, 2003, the FERC staff issued its analysis of the report and found that it was incomplete and overstated the amount of power withheld. The FERC staff’s analysis further stated that there was no evidence that we withheld any material amounts of power or that we were responsible for any service interruptions. The FERC subsequently asked for, and we submitted, data to demonstrate that we did not physically withhold power to influence prices.

Western Long-Term Contract Complaints.    On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints with the FERC asking that it void or reform power supply contracts between the CDWR and, among others, Dynegy Power Marketing Inc. The complaints allege that prices under the contracts exceed just and reasonable prices permitted under the FPA. The FERC set these complaints for evidentiary hearing. On January 10, 2003, the FERC granted a motion by Dynegy and other defendants for the administrative law judge to issue a partial initial decision on certain threshold legal issues, and for the FERC itself to resolve the issues on the basis of the record developed at the hearing. On January 16, 2003, the administrative law judge issued a decision adopting our view on the threshold legal issue. The complainants have appealed that decision to the FERC. Both sides of the case also have filed briefs before the FERC and the case is awaiting decision. Additionally, on March 3, 2003, the complainants filed supplemental testimony requesting that the FERC void or reform the power supply contracts at issue based on the allegations of market manipulation submitted by the California Parties. On March 20, 2003, Dynegy and the other defendants filed responses to this submission. On June 25, 2003 the FERC ruled that long-term contracts with the CDWR, including Dynegy Power Marketing Inc., were valid and would be upheld. However, that decision is subject to rehearing and appeal.

In a related complaint, Kroger filed a complaint with the FERC in August 2002 asking that the four wholesale contracts between DPM and AES New Energy, Inc., which provides retail service to Kroger be declared void for their remaining terms, and that the FERC set just and reasonable rates for prior periods. Alternatively, Kroger asked that the FERC allow for an annual review procedure to reset the contract prices. The complaint alleges that but for the dysfunctional California electricity markets, it would not have entered into the contracts for delivery of energy through December 2006. On March 14, 2003, the FERC issued an order setting Kroger’s complaint for hearing, establishing hearing procedures and holding the hearing in abeyance pending proceedings before a FERC settlement judge. On July 3, 2003, Kroger and DPM reached a tentative settlement, subject to FERC approval, and filed an Explanation In Support of Offer Of Settlement with the FERC. On July 23, 2003, the FERC approved the settlement. As a result of this settlement, we recorded a $30 million pre-tax, non-cash charge in our customer risk management segment in the second quarter 2003, and we expect to receive a $110 million cash payment during the third quarter 2003 representing an accelerated payment under the terminated and restructured contracts.

West Coast Power.    Through our interest in West Coast Power, we have credit exposure for past transactions to the Cal ISO and Cal PX, which primarily relied on cash payments from California utilities to in turn pay their bills. West Coast Power currently sells directly to the CDWR pursuant to a long-term sales agreement.

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(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

At June 30, 2003, our portion of the receivables owed to West Coast Power by the Cal ISO and CAL PX approximated $204 million. Management is continually assessing our exposure, as well as our exposure through West Coast Power, relative to our California receivables and establishes and maintains reserves as necessary. During the three-month periods ended June 30, 2003 and 2002, our pre-tax share of reserves taken by West Coast Power totaled $0.4 million and $(0.3) million, respectively. During the six-month periods ended June 30, 2003 and 2002, our pre-tax share of reserves taken by West Coast Power totaled $0.4 million and $(0.1) million, respectively. Our share of the total reserve at June 30, 2003 and December 31, 2002 was $201.2 million and $200.8 million, respectively.

Enron Merger Termination Litigation.    Dynegy and DHI were sued on December 2, 2001 by Enron and Enron Transportation Services Co. in the United States Bankruptcy Court for the Southern District of New York, Adversary Proceeding No. 01-03626 (AJG). Enron claimed that Dynegy materially breached the Merger Agreement dated November 9, 2001 between Enron and Dynegy and related entities by wrongfully terminating that Agreement on November 28, 2001. Enron also claimed that we wrongfully exercised our option to take ownership of Northern Natural under an Option Agreement dated November 9, 2001. Enron sought damages in excess of $10 billion and declaratory relief against Dynegy for breach of the Merger Agreement. Enron also sought unspecified damages against Dynegy and DHI for breach of the Option Agreement. Dynegy and DHI filed an answer on February 4, 2002, denying all material allegations. On April 12, 2002, the Bankruptcy Court granted our motion to transfer venue in the proceeding to the United States District Court for the Southern District of Texas (Houston Division).

On August 15, 2002, we entered into an agreement with Enron to settle this lawsuit. Under the terms of the settlement agreement, we agreed to pay Enron $25 million, $10 million of which was paid to Enron upon approval of the settlement agreement by the Bankruptcy Court, with the remaining $15 million escrowed until approval of the settlement becomes final. In addition, we agreed with Enron to exchange mutual releases of any and all claims related to the terminated merger and to dismiss the related litigation. We also agreed not to pursue any claims for working capital adjustments relating to the acquisition of Northern Natural. The terms of the settlement were approved by the Bankruptcy Court on August 29, 2002. On September 6, 2002, an appeal of the Bankruptcy Court’s approval was filed by the plaintiffs who had filed the class action lawsuits described below.

On February 6, 2003, the District Court affirmed Judge Gonzalez’s order approving the settlement agreement. On April 7, 2003, following the expiration of the time period during which these plaintiffs could have filed a further appeal, we and Enron filed with the United States District Court for the Southern District of Texas (Houston Division) a joint motion for dismissal of Enron’s claims with prejudice. The court subsequently approved the settlement, and the case has been dismissed.

Ann C. Pearl and Joel Getzler filed a suit against Dynegy and DHI in the United States District Court for the Southern District of New York. Plaintiffs filed the lawsuit as a purported class action on behalf of all persons or entities that owned Enron common stock as of November 28, 2001. A similar suit was filed by Bernard D. Shapiro and Peter Strub in the 129th Judicial District Court for Harris County, Texas. Plaintiffs in each case alleged that they are intended third-party beneficiaries of the Merger Agreement dated November 9, 2001 among Enron, Dynegy and related entities. Plaintiffs claimed that we materially breached the Merger Agreement by, among other things, wrongfully terminating that agreement. Plaintiffs also claimed that we breached the implied covenant of good faith and fair dealing. Plaintiffs sought unspecified damages and other relief. Enron moved for an order from the Bankruptcy Court in the Southern District of New York directing that the Pearl and Shapiro plaintiffs be enjoined from prosecuting their actions and that their actions be immediately dismissed. The

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(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Bankruptcy Court held that the claims asserted by the Pearl and Shapiro plaintiffs were the exclusive property of the Enron bankruptcy estate and that the plaintiffs lacked standing to sue as third-party beneficiaries of the Merger Agreement. Accordingly, by an order entered on April 19, 2002, the Bankruptcy Court granted Enron’s motion, enjoined the prosecution of both actions and directed that they be dismissed. The Pearl and Shapiro plaintiffs thereafter complied with that order, but filed an appeal to the United States District Court for the Southern District of New York. On October 22, 2002, the District Court reversed the Bankruptcy Court’s determination, holding that the Pearl and Shapiro plaintiffs do have standing to sue as third-party beneficiaries, and that their claims are not the exclusive property of the bankruptcy estate. Shortly after this ruling, certain Enron shareholders filed an action against Dynegy for wrongful termination of the Merger Agreement in the United States District Court for the Southern District of New York.

On October 28, 2002, Dynegy and DHI filed a declaratory action in Harris County Judicial District Court relating to the Shapiro action. The action seeks to reinstate the Shapiro action in the 129th Judicial District Court that is no longer stayed. The action also seeks affirmative declarations to the effect that Dynegy did not wrongfully terminate the Merger Agreement, that the termination did not breach any duty owed to the Shapiro plaintiffs or to Enron’s shareholders generally and that neither the Shapiro plaintiffs nor Enron’s shareholders generally have a right to enforce or to make claims under the Merger Agreement.

On April 9, 2003, we executed a settlement agreement with the former Enron shareholder plaintiffs relating to the purported class action lawsuits described above. Pursuant to the settlement agreement, which is subject to court approval, we agreed to pay $6 million to settle the claims asserted on behalf of the class of all Enron shareholders who held Enron stock at the time the merger was terminated. We have a unilateral right to terminate the settlement agreement if any class members opt out of the settlement class or if the court fails to approve any material provision of the settlement agreement. A hearing to obtain the court’s approval is scheduled for September 2003.

We believe that we have meritorious defenses against these claims and, subject to the finalization of the settlement described above, intend to defend against them vigorously. An adverse result in any of these proceedings, however, could have a material adverse effect on our financial position, results of operations and cash flows.

Enron Trade Credit Litigation.    As a result of Enron’s bankruptcy filing, we recognized in our fourth quarter 2001 financial statements a pre-tax charge related to our net exposure for commercial transactions with Enron. As of December 31, 2002 our net exposure to Enron, inclusive of certain liquidated damages and other amounts relating to the termination of the transactions, was approximately $84 million and was calculated by setting off approximately $230 million owed from various Dynegy entities to various Enron entities against approximately $314 million owed from various Enron entities to various Dynegy entities. The master netting agreement between us and Enron and the valuation of the commercial transactions covered by the agreement, which valuation is based principally on the parties’ assessment of market prices for such period, remain subject to dispute by Enron with respect to which there have been negotiations between the parties. These negotiations have focused on the scope of the transactions covered by the master netting agreement and the parties’ valuations of those transactions. If any disputes cannot be resolved by the parties, the agreements call for arbitration. We have instituted arbitration proceedings against those Enron parties not in bankruptcy and have filed a motion with the Bankruptcy Court requesting that we be allowed to proceed to arbitration against those Enron parties that are in bankruptcy. The Enron parties have responded by opposing our request to enforce the arbitration requirement and filing an adversary proceeding against us. Both the opposition to the arbitration request and the adversary proceeding allege that the master netting agreement should not be enforced and that the Enron companies should

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(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

recover approximately $230 million from us. We have disputed such allegations and are vigorously defending our position regarding the setoff rights provided for in the master netting agreement. No ruling has been made by the Bankruptcy Court, and the Court has referred the disputes to non-binding mediation, currently scheduled to take place on September 10 and 11, 2003. If the setoff rights were modified or disallowed, either by agreement or otherwise, the amount available for Dynegy entities to set off against sums that might be due Enron entities could be reduced materially.

Telstra Litigation.    On January 25, 2002, Telstra Corporation, Ltd. and Telstra Wholesale Inc., which we collectively refer to as Telstra, filed suit in Delaware Chancery Court against DynegyConnect, L.P., a limited partnership in which Dynegy acquired a combined 80% interest, as well as some of our other affiliates. DynegyConnect is a vehicle established by us to participate in the U.S. telecommunications business. Telstra Wholesale originally acquired the remaining 20% interest in DynegyConnect pursuant to a limited partnership agreement that was executed in October 2000 and details the partners’ rights and obligations. Under the agreement, Telstra Wholesale was granted a put option permitting it to require Dynegy or its designee, at any time on or before September 20, 2002, to purchase its 20% partnership interest for a purchase price equal to the value of Telstra Wholesale’s capital account in DynegyConnect, subject to certain adjustments. The plaintiffs brought this action in connection with Telstra Wholesale’s attempted exercise of this put option. The plaintiffs alleged breach of contract and bad faith, among other things, in connection with the valuation of Telstra Wholesale’s capital account and, as a result, the put option purchase price, as well as the administration of the partnership. The plaintiffs sought approximately $50 million plus interest in damages together with fees and other litigation expenses. Previously, Minority Interest on our condensed consolidated balance sheets included amounts relating to Telstra Wholesale’s investment in DynegyConnect, which amounts equaled the fair value of Telstra Wholesale’s put option. During the fourth quarter 2002, based on the status of the litigation, this Minority Interest liability was reclassified to a current liability, which reclassification had no impact on net income, and we accrued an additional $15 million reserve.

Telstra filed a motion for summary judgment on December 6, 2002, and the court partially granted Telstra’s motion on March 4, 2003. The court ruled against Dynegy on Telstra’s breach of contract claim and in favor of Dynegy on Telstra’s bad faith claim and set a trial date on the issue of damages. On March 14, 2003, the parties agreed to settle this lawsuit. Pursuant to the terms of the settlement agreement, we agreed to acquire Telstra Wholesale’s minority interest in DynegyConnect effective as of September 19, 2001 in exchange for $45 million in cash, $10 million of which was paid on March 14, 2003 and the remaining $35 million of which was paid in April 2003.

Severance Arbitrations.    Dynegy Inc.’s former CEO, Chuck Watson, former President, Steve Bergstrom, and former CFO, Rob Doty, have each filed for arbitration pursuant to the terms of their employment/severance agreements. In each case, the parties disagree as to the amounts that may be owed pursuant to their respective agreements. These former officers have made arbitration claims that seek payments of up to approximately $28.7 million, $10.4 million and $3.4 million, respectively. These agreements are subject to interpretation and Dynegy maintains that the amounts owed are substantially lower than the amounts sought. In particular, the severance agreement with Mr. Bergstrom provides that the amounts identified in the agreement are not due him if material financial restatements have occurred or allegations of wrongdoing are made against him by a state or federal law enforcement agency. However, we cannot predict with any degree of certainty the amounts that may be determined to be owed as a result of the pending arbitration proceedings, and have, therefore, recorded reserves in the event these arbitrations are decided adversely to Dynegy. At present, these arbitrations are scheduled to commence in November 2003 (Doty), February 2004 (Watson) and March 2004 (Bergstrom).

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(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Modesto Litigation.    On August 3, 1998, the Modesto Irrigation District filed a lawsuit against PG&E and Destec Energy, Inc. (now known as Dynegy Power Corp.), which was previously acquired by Dynegy, in federal court for the Northern District of California, San Francisco division. The lawsuit alleges violations of federal and state antitrust laws and state law tort and breach of contract claims against Destec relating to a power sale and purchase arrangement with the plaintiff in the City of Pittsburg, California. While the plaintiff’s pleadings indicate that it cannot measure its alleged damages with specificity, it has indicated that the actual damages sought from PG&E and Destec may exceed $25 million. Plaintiff also seeks a trebling of any portion of damages related to its antitrust claims. After the District Court dismissed the plaintiff’s antitrust claims on August 20, 1999 and refused to assert pendent jurisdiction over the state law claims, the plaintiff filed an appeal with the Ninth Circuit Court of Appeals and re-filed its state claims in state court. Plaintiff then agreed to execute a tolling agreement on the state law claims and to dismiss the state court case until the federal appeal was decided. Plaintiff subsequently filed in the state court a request for dismissal, which the court granted on October 25, 2000.

Although PG&E filed a Chapter 11 bankruptcy proceeding on April 6, 2001, the automatic stay applicable in the proceeding was lifted to permit the Ninth Circuit to decide the pending appeal. On December 6, 2002, the Ninth Circuit reversed the District Court’s order dismissing the plaintiff’s antitrust claims. The District Court set a Case Management Conference for July 2, 2003, which conference was continued until September 3, 2003, to provide the parties an opportunity to negotiate a schedule for the expeditious resolution of potentially dispositive issues in the case. We believe that we have meritorious defenses to these claims and we intend to defend against them vigorously. However, if the plaintiff were to prosecute its claims successfully, we could be required to fund a judgment in excess of $25 million.

Farnsworth Litigation.    On August 2, 2002, Bradley Farnsworth filed a lawsuit against us in Texas state district court claiming breach of contract and that he was demoted and ultimately fired from the position of Controller for refusing to participate in illegal activities. On April 18, 2003, Mr. Farnsworth filed a First Amended Complaint in this matter. Specifically, Mr. Farnsworth alleges, in the words of his amended complaint, that certain of our former executive officers requested that he “shave or reduce for accounting purposes” the forward price curves associated with the natural gas business in the United Kingdom for the period of October 1, 2000 through March 31, 2001, in order to indicate a reduction in our mark-to-market losses. He also claims that Project Alpha and the round-trip trades provide evidence to support his theory that these same former executive officers were engaged in a conspiracy to manipulate Dynegy’s financial results and statements. Mr. Farnsworth, who seeks unspecified actual and exemplary damages and other compensation, also alleges that he is entitled to a termination payment under his employment agreement equal to 2.99 times the greater of his average base salary and incentive compensation for the highest three calendar years preceding termination or his base salary and target bonus amount for the year of termination (currently estimated at a range of approximately $700,000 to $1,200,000). The parties have commenced discovery in this lawsuit and Dynegy has taken the plaintiff’s deposition. We believe that we have meritorious defenses against these claims and intend to defend against them vigorously. Although we have recorded a reserve with respect to this litigation, we do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations and cash flows.

Apache Litigation.    In May 2002, Apache Corporation filed suit in Harris County, Texas district court against Versado as purchaser and processor of Apache’s gas, and against DMS as operator of the Versado assets in New Mexico. The suit, which followed an Apache audit of Versado’s books and records relating to the parties’

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(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

commercial transactions, originally sought approximately $3.9 million in damages. Under an agreed court order, Versado analyzed the results of the Apache audit and voluntarily paid approximately $1.35 million to Apache in the third quarter of 2002. Apache has since amended its petition to allege Versado still owes it a total of more than $9 million. These new claims include allegations that Versado engages in “sham” transactions with affiliates, which result in Versado not receiving fair market value when it sells gas and liquids. They also allege, among other things, that the formula for calculating the amount Versado receives from its buyers of gas and liquids is flawed since it is based on gas price indexes that these same affiliates are alleged to have manipulated by providing false price information to the index publisher. Versado intends to defend against these claims vigorously and believes it has meritorious defenses. In May 2003, we filed a motion for partial summary judgment relating to lost gas and related matters, which has not yet been heard. Mediation is scheduled for August 14 and 15, 2003, and trial in this matter is scheduled for September 2003. Although we have recorded a reserve with respect to this litigation, we do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations and cash flows.

Sierra Pacific Litigation.    In April 2003, Sierra Pacific Resources and Nevada Power Company filed suit against various sellers of natural gas, including some of Dynegy’s subsidiaries, in the United States District Court for the District of Nevada and, on July 3, 2003, filed an amended petition in the action. In the suit, plaintiffs claim that they purchased natural gas from us to produce electricity for their customers at artificially high prices based on published index prices at the California-Arizona border market. Plaintiffs claim that we were part of a conspiracy to restrict natural gas transmission capacity on the El Paso pipeline system, which in turn raised the California border price. Plaintiffs allege, although without specificity, that Dynegy withheld capacity from the market in concert with El Paso and that there was an “illicit” agreement between the other defendants, El Paso and us to decrease output and raise prices in violation of the Nevada Unfair Trade Practices Act. Plaintiffs seek an award of unspecified treble damages with respect to these claims based on the alleged excess natural gas costs they incurred.

Plaintiffs further allege that we intentionally misrepresented natural gas prices and volumes to trade publications that compile and report index prices in an effort to induce plaintiffs to enter into contracts for the purchase of natural gas at artificially high prices, as well as associated hedging transactions, and that Nevada Power did in fact rely on the misinformation suffering damage as a result of such reliance. Plaintiffs further claim that we conspired with El Paso to provide this false information, and that our misconduct constitutes fraud and violates Nevada’s Racketeering Influenced Corrupt Organizations Act. Plaintiffs seek an award of unspecified treble damages with respect to these claims.

On July 3, 2003 plaintiffs served their amended complaint on Dynegy Power Marketing and Trade and on the El Paso and Sempra defendants named in the prior version of the complaint. Plaintiffs have also now named Reliant Energy Services and Sempra Energy Trading Corporation. Defendants, including Dynegy, have until September 12, 2003 to answer and/or file appropriate motions attacking the pleadings. We are analyzing these claims, and intend to defend against them vigorously. It is not possible to predict with certainty whether we will incur any liability or to estimate the range of possible loss, if any, that we might incur in connection with this lawsuit. However, we do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.

Other Index Pricing Litigation.    In addition to the Sierra Pacific suit described above, we and DMT were named as defendants in April 2003 in a third-party complaint in a lawsuit originally initiated by Nelson Brothers,

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(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

LLC against Cherokee Nitrogen in Alabama state court. The underlying suit relates to an agreement between Cherokee and Nelson Brothers pursuant to which Cherokee allegedly agreed to supply ammonium nitrate to Nelson Brothers and to use its commercially reasonable efforts to reduce its supply costs. When Nelson Brothers sued Cherokee under their agreement, Cherokee filed a third-party complaint alleging that it purchased natural gas from DMT based on index pricing and, citing the December 2002 settlement with the CFTC, that the index prices used were artificially inflated by DMT due to “fraudulent and inaccurate reporting” to index services, which resulted in higher costs that it passed on to Nelson Brothers. Cherokee claims that DMT is liable to it for alleged overcharges and seeks actual and punitive damages in unspecified amounts. Dynegy has filed a motion to remand this litigation to state court and to dismiss Dynegy Inc. for lack of jurisdiction. We are currently awaiting a ruling on these motions. We intend to defend against these claims vigorously. It is not possible to predict with certainty whether we will incur any liability or to estimate the range of possible loss, if any, that we might incur in connection with this lawsuit. However, we do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, or results of operations.

Triad Energy Litigation.    On March 18, 2003, Triad Energy Resources Corp. and five other alleged representatives of two plaintiffs’ classes filed a putative antitrust class action against NiSource Inc. and other defendants, including Dynegy, in the United States District Court for the District of Columbia. The plaintiffs purport to represent classes of purchasers, marketers, wholesalers, managers, sellers and shippers of natural gas that allegedly were damaged by an illegal gas scheme devised by three federally regulated interstate pipeline systems: Columbia Gas Transmission Corporation, Columbia Gulf Transmission Company, and The Cove Point LNG Limited Partnership—all of which now are owned by NiSource, and certain shippers on these pipelines.

The complaint alleges violations of the federal antitrust laws and common law tortious interference with contractual and business relations. It alleges that the interstate pipelines provided preferential storage and transportation services to their own unregulated marketing affiliate in violation of FERC regulations and, in return, received percentages of the profits reaped by the marketing affiliate. The complaint also alleges that certain shippers, including us, having learned of the Columbia arrangements, demanded and received similar preferential storage and transportation services that were not available to all shippers.

Although this alleged scheme was the subject of a FERC order issued on October 25, 2000, which order required the Columbia companies to pay $27.5 million to certain customers of Columbia Gas and Columbia Gulf, plaintiffs claim that the FERC order did not remedy the competitive injury to plaintiffs caused by the scheme. The complaint seeks aggregate damages of approximately $1.716 billion (divided approximately $1.034 billion and $682 million between two plaintiffs’ classes). Under the federal antitrust laws, damages are subject to trebling. We are analyzing these claims, and intend to defend against them vigorously. At present, the litigation is stayed pending the outcome of a motion to dismiss in a companion case in which we are not a defendant. It is not possible to predict with certainty whether we will incur any liability or to estimate the damages, if any, that we might incur in connection with this lawsuit.

Maxus Litigation.    In June of 2002, DMS as successor to Natural Gas Clearinghouse, the defendant in the trial below, argued its appeal in the case ofNatural Gas Clearinghouse v. Midgard Energy, formerly known as Maxus Exploration Co. This appeal to the Seventh District Court of Appeals in Amarillo, Texas was taken by us in response to an adverse judgment received in the District Court of Potter County, Texas in April of 2001. In the lower court, DMS was found liable for failing to deliver processable “wet” gas to a processing plant in Oklahoma owned by Maxus and DMS’s third party action against Transok Inc. for causing it to breach the processing

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For the Interim Periods Ended June 30, 2003 and 2002

contract was decided adversely to us. The judgment was appealed from and, in May 2003, was upheld in part. We thereafter filed an expedited writ with the Texas Supreme Court seeking further review. We have established a reserve in connection with this matter, although we do not believe that any liability we might incur would have a material adverse effect on our financial condition, results of operations and cash flows.

Alleged Marketing Contract Defaults.    We have posted collateral to support a substantial portion of our obligations in our customer risk management business, including our obligations under some of our power tolling arrangements. While we have been working with various counterparties to provide mutually acceptable collateral or other adequate assurance under these contracts, we have not reached agreement with Sithe Independence and Sterlington/Quachita Power LLC regarding a mutually acceptable amount of collateral in support of our obligations under our power tolling arrangements with either of these two parties. Although we are current on all contract payments to these counterparties, we have received a notice of default from each such party with regard to collateral and are continuing to negotiate the issue. Our average annual capacity payments under these two arrangements approximate $75 million and $63 million, respectively, and the contracts extend through 2014 and 2012, respectively. If these two parties were to successfully pursue claims that we defaulted on these contracts, they could declare a termination of their respective contracts, which provide for termination payments based on the agreed mark-to-market value of the contracts. Because of the effects of changes in commodity prices on the mark-to-market value of these contracts, as well as the likelihood that we would differ with our counterparties as to the estimated value of these contracts, we cannot predict with any degree of certainty the amounts of termination payments that could be required under these two contracts. Disputes relating to these two contracts, if resolved against us, could materially adversely affect our financial condition, results of operations and cash flows.

In addition, we are involved in litigation with some of our former counterparties relating to contract terminations with respect to which we were unable to agree on mutually acceptable collateral or other adequate assurance. We intend to defend against these claims vigorously and do not expect that any liability we might incur in connection with these contract terminations will materially adversely affect our financial condition, results of operations or cash flows.

U.S. Attorney Investigations.    The U.S. Attorney’s office in Houston has commenced an investigation of our actions relating to Project Alpha, round-trip trades with CMS Energy and our gas trade reporting practices. We have produced documents and witnesses for interviews in connection with this investigation. Six of our natural gas traders were dismissed in October 2002 for violating our Code of Business Conduct after an ongoing internal investigation conducted by our Audit and Compliance Committee in collaboration with independent counsel discovered that inaccurate information regarding natural gas trades had been reported to various energy industry publications. On January 27, 2003, one of our former natural gas traders was indicted in Houston on three counts of knowingly causing the transmission of false trade reports used to calculate the index price of natural gas and four counts of wire fraud. On June 10, 2003, three former Dynegy employees were indicted on charges of conspiracy, securities fraud, mail and wire fraud related to the Project Alpha transaction. Subsequently, two of such former employees pleaded guilty to conspiracy to commit securities fraud. Trial on the indictment against the third employee is scheduled for November 3, 2003. We are cooperating fully with the U.S. Attorney’s office in its continuing investigation of both of these matters and cannot predict the ultimate outcome of these investigations.

Additionally, the United States Attorney’s office in the Northern District of California has issued a Grand Jury subpoena requesting information related to our activities in the California energy markets in November 2002. We have been, and intend to continue, cooperating fully with the U.S. Attorney’s office in its investigation

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(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

of these matters, including production of substantial documents responsive to the subpoena and other requests for information. We cannot predict the ultimate outcome of this investigation.

SEC Settlement.    On September 24, 2002, we announced a settlement with the SEC of allegations made in connection with the previously disclosed investigation relating to Project Alpha and round-trip electricity trades with CMS Energy. In the settlement, the SEC found that we engaged in securities fraud in connection with our disclosures and accounting for Project Alpha, and negligently included materially misleading information about the round-trip energy trades with CMS Energy in two press releases we issued in early 2002. In settlement of the SEC’s enforcement action, Dynegy, without admitting or denying the SEC’s findings, agreed to the entry of a cease-and-desist order and to pay a $3 million penalty in a related civil suit filed in the United States District Court in Houston, Texas. We are continuing to cooperate with the SEC’s ongoing investigation of other parties related to Project Alpha. On June 11, 2003, the SEC instituted civil proceedings against three former Dynegy employees for conduct related to the Project Alpha transaction.

Nicor Energy Investigations.    We own a 50% interest in Nicor Energy, a joint venture with Nicor Inc. that markets retail gas and electricity in the Midwest. During the first quarter 2003, substantially all of the operations of Nicor Energy were sold, and we substantially liquidated the company in the second quarter 2003. We have historically provided gas and electricity to Nicor Energy for resale to its retail customers; however, we ceased to provide gas to Nicor Energy effective March 31, 2003 in connection with our exit from third-party marketing and trading and will cease to provide electricity to Nicor Energy in connection with its assignment of our wholesale electricity contracts to the purchasers of its retail electricity business. On March 10, 2003, Nicor Inc. publicly announced that it expects the SEC to bring civil charges against Nicor Energy based on alleged violations of standard financial reporting relating to unbilled revenues and unrecorded liabilities, including fraud and maintaining false books and records. The U.S. Attorney for the Northern District of Illinois has also notified Nicor Energy that it is conducting an inquiry on these same matters, and that a grand jury is also reviewing these matters. We intend to cooperate with these investigations and cannot predict their ultimate outcomes.

Nicor Inc. previously revealed irregularities in accounting at Nicor Energy. We have reflected a $5.6 million pre-tax charge in the fourth quarter 2001 relating to our investment in Nicor Energy as a result of these matters.

Department of Labor Investigation.    In August 2002, the U.S. Department of Labor commenced an official investigation pursuant to Section 504 of ERISA with respect to the benefit plans maintained by Dynegy Inc. and its ERISA affiliates. We have cooperated with the Department of Labor throughout this investigation, which remains ongoing. As of this date, the investigation has focused on a review of plan documentation, plan reporting and disclosure, plan recordkeeping, plan investments and investment options, plan fiduciaries and third-party service providers, plan contributions and other operational aspects of the plans. We have not yet received the Department of Labor’s definitive findings resulting from its investigation.

Note 10—Regulatory Issues

We are subject to regulation by various federal, state, local and foreign agencies, including extensive rules and regulations governing transportation, transmission and sale of energy commodities as well as the discharge of materials into the environment or otherwise relating to environmental protection. Compliance with these regulations requires general and administrative, capital and operating expenditures including those related to monitoring, pollution control equipment, emission fees and permitting at various operating facilities and remediation obligations. In addition, the United States Congress has before it a number of bills that could impact

40

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

regulations or impose new regulations applicable to us and our subsidiaries. We cannot predict the outcome of these bills or other regulatory developments or the effects that they might have on our business. Please refer to “Item 1. Business—Regulation” in the Form 10-K/A beginning on page 23 for a more detailed description of regulatory issues affecting our business.

Note 11—Segment Information

As reflected in this report, we have changed our reportable segments. In 2002, we reported results for the following four business segments:

• Wholesale Energy Network, or WEN;

• Dynegy Midstream Services, or DMS;

• Transmission and Distribution, or T&D; and

• Dynegy Global Communications, or DGC.

Beginning January 1, 2003, we are reporting our operations in the following segments:

• Power generation, or GEN;

• Natural gas liquids, or NGL;

• Regulated energy delivery, or REG; and

• Customer risk management, or CRM.

Prior to January 1, 2003, the GEN and CRM segments were operated together as an asset-based third-party marketing, trading and risk-management business, then referred to as the WEN segment. Most, but not all, of the WEN third-party purchase and sale contracts were held by a subsidiary which is currently included within the CRM segment. Under this business model, the net fair value of most of GEN’s generation capacity, forward sales and related trading positions were sold to the CRM segment monthly at an internally determined transfer price. The internal transfer price was primarily comprised of the option value of generation capacity and executed forward sales contracts based on then-current forward prices of power and fuel. GEN intersegment revenues for the three- and six-month periods ended June 30, 2002 reflect this internal transfer price and do not represent amounts actually received by GEN for power sold to third parties. As such, the GEN intersegment revenues for the three- and six-month periods ended June 30, 2002 do not include the effect of intra-month market price volatility. The CRM segment recorded net unaffiliated revenue from these third-party contracts, together with all of its other third-party marketing and trading positions unrelated to the GEN segment.

In connection with our exit from the third-party marketing and trading business, individual contracts within the former WEN segment were identified on January 1, 2003 as either GEN contracts, as they were determined to be a part of our continuing operations, or CRM contracts. Under this new business segment model, CRM continues to transact with third parties on behalf of GEN for contracts which were identified as GEN contracts, as well as new transactions executed on behalf of GEN but for which CRM is the legal party to the third-party purchase and sale contract. CRM continues to record net unaffiliated revenue from these third-party contracts, together with all of its other third-party marketing and trading positions unrelated to the GEN segment. However, rather than purchasing such capacity, forward sales and related trading positions from GEN at an internally determined transfer price, pricing between CRM and GEN is set at the actual amount received or paid for the

41

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

purchases and sales to the third parties. Therefore, GEN intersegment revenues for the three- and six-month periods ended June 30, 2003 include the effects of intra-month market price volatility. Additionally, procurement of fuel and power from third parties by CRM on behalf of GEN are recorded by GEN as cost of sales rather than a reduction of revenue. These differences should be considered when attempting to compare the results for the three- and six-month periods ended June 30, 2003 and 2002.

Revenues from third-party sales in which GEN is the legal party to the third-party sales contracts are presented gross in GEN unaffiliated revenues for the three-month periods ended June 30, 2003 and 2002.

Pursuant to EITF Issue 02-03, all gains and losses on third-party energy-trading contracts in the CRM segment, whether realized or unrealized, are presented net in the condensed consolidated statements of operations. For the purpose of the segment data presented below, intersegment transactions between CRM and our other segments are presented net in CRM intersegment revenues but are presented gross in the intersegment revenues of our other segments, as the activities of our other segments are not subject to the net presentation requirements contained in EITF Issue 02-03. If transactions between CRM and our other segments result in a net intersegment purchase by CRM, the net intersegment purchases and sales are presented as negative revenues in CRM intersegment revenues.

42

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Prior to January 1, 2003, our natural gas liquids operations comprised our Dynegy Midstream Services segment. Beginning January 1, 2003, these operations comprise the NGL segment. Additionally, prior to January 1, 2003, we reported our Illinois Power utility operations and, for the first three quarters of 2002 prior to its sale, the operations of Northern Natural in our Transmission and Distribution segment. Beginning January 1, 2003, our Illinois Power utility operations comprise the REG segment. Results associated with the former DGC segment are included in discontinued operations due to the sale of our communications businesses. Reportable segment information for the three- and six-month periods ended June 30, 2003 and 2002 is presented below.

Dynegy’s Segment Data for the Quarter Ended June 30, 2003

(in millions)

	GEN			NGL			REG			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	84		$	620		$	321		$	28		$	—		$	1,053
Other		—			—			—			1			—			1
		84			620			321			29			—			1,054
Intersegment revenues		651			61			7			(132	)		(587	)		—
Total revenues	$	735		$	681		$	328		$	(103	)	$	(587	)	$	1,054
Depreciation and amortization	$	(49	)	$	(20	)	$	(30	)	$	—		$	(17	)	$	(116	)
Operating income (loss)	$	16		$	39		$	35		$	(360	)	$	(104	)	$	(374	)
Earnings (losses) from unconsolidated investments		45			2			—			(9	)		—			38
Other items, net		—			(5	)		—			(3	)		(1	)		(9	)
Interest expense																	(109	)
Loss from continuing operations before taxes																	(454	)
Income tax benefit																	168
Loss from continuing operations																	(286	)
Loss on discontinued operations, net of taxes																	(4	)
Net loss																$	(290	)
Identifiable assets:
Domestic	$	6,545		$	1,774		$	5,374		$	3,447		$	(2,409	)	$	14,731
Other		—			—			—			524			—			524
Unconsolidated investments		589			95			—			2			—			686
Capital expenditures and unconsolidated investments		(56	)		(13	)		(36	)		—			—			(105	)

43

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Dynegy’s Segment Data for the Quarter Ended June 30, 2002

(in millions)

	GEN			NGL			REG			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	97		$	578		$	332		$	(5	)	$	—		$	1,002
Other		1			361			—			—			—			362
		98			939			332			(5	)		—			1,364
Intersegment revenues		336			43			13			375			(767	)		—
Total revenues	$	434		$	982		$	345		$	370		$	(767	)	$	1,364
Depreciation and amortization	$	(34	)	$	(22	)	$	(38	)	$	(6	)	$	—		$	(100	)
Impairment and other charges		(11	)		(5	)		(7	)		(19	)		—			(42	)
Operating income (loss)	$	85		$	14		$	56		$	(298	)	$	—		$	(143	)
Earnings (losses) from unconsolidated investments		34			3			(1	)		(18	)		—			18
Other items, net		(12	)		(12	)		(2	)		1			—			(25	)
Interest expense																	(64	)
Loss from continuing operations before taxes																	(214	)
Income tax benefit																	75
Loss from continuing operations																	(139	)
Loss on discontinued operations, net of taxes																	(422	)
Net loss																$	(561	)
Identifiable assets:
Domestic	$	6,593		$	1,957		$	6,361		$	9,224		$	114		$	24,249
Canadian		—			139			—			611			—			750
European and other		132			—			—			2,762			53			2,947
Unconsolidated investments		747			146			—			25			—			918
Capital expenditures and unconsolidated investments		(148	)		(22	)		(43	)		(9	)		(23	)		(245	)

44

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Dynegy’s Segment Data for the Six Months Ended June 30, 2003

(in millions)

	GEN			NGL			REG			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	190		$	1,598		$	776		$	226		$	—		$	2,790
Other		—			—			—			9			—			9
		190			1,598			776			235			—			2,799
Intersegment revenues		1,439			134			15			(290	)		(1,298	)		—
Total revenues	$	1,629		$	1,732		$	791		$	(55	)	$	(1,298	)	$	2,799
Depreciation and amortization	$	(91	)	$	(40	)	$	(60	)	$	(1	)	$	(39	)	$	(231	)
Operating income (loss)	$	99		$	90		$	94		$	(322	)	$	(148	)	$	(187	)
Earnings from unconsolidated investments		84			5			—			2			—			91
Other items, net		3			(10	)		—			23			(4	)		12
Interest expense																	(219	)
Loss from continuing operations before taxes																	(303	)
Income tax benefit																	112
Loss from continuing operations																	(191	)
Loss on discontinued operations, net of taxes																	(7	)
Cumulative effect of a change in accounting principles, net of taxes																	55
Net loss																$	(143	)
Identifiable assets:
Domestic	$	6,545		$	1,774		$	5,374		$	3,447		$	(2,409	)	$	14,731
Other		—			—			—			524			—			524
Unconsolidated investments		589			95			—			2			—			686
Capital expenditures and unconsolidated investments		(93	)		(25	)		(68	)		—			(3	)		(189	)

45

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2003 and 2002

Dynegy’s Segment Data for the Six Months Ended June 30, 2002

(in millions)

	GEN			NGL			REG			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	108		$	1,227		$	717		$	155		$	—		$	2,207
Other		4			592			—			—			—			596
		112			1,819			717			155			—			2,803
Intersegment revenues		622			76			21			602			(1,321	)		—
Total revenues	$	734		$	1,895		$	738		$	757		$	(1,321	)	$	2,803
Depreciation and amortization	$	(70	)	$	(41	)	$	(74	)	$	(8	)	$	—		$	(193	)
Impairment and other charges		(11	)		(5	)		(7	)		(19	)					(42	)
Operating income (loss)	$	119		$	54		$	96		$	(327	)	$	—		$	(58	)
Earnings (losses) from unconsolidated investments		62			7			(1	)		(15	)		—			53
Other items, net		(15	)		(11	)		—			(13	)		—			(39	)
Interest expense																	(130	)
Loss from continuing operations before taxes																	(174	)
Income tax benefit																	82
Loss from continuing operations																	(92	)
Loss on discontinued operations, net of taxes																	(482	)
Cumulative effect of a change in accounting principle, net of taxes																	(234	)
Net loss																$	(808	)
Identifiable assets:
Domestic	$	6,593		$	1,957		$	6,361		$	9,224		$	114		$	24,249
Canadian		—			139			—			611			—			750
European and other		132			—			—			2,762			53			2,947
Unconsolidated investments		747			146			—			25			—			918
Capital expenditures and unconsolidated investments		(410	)		(53	)		(72	)		(18	)		(90	)		(643	)

Note 12—Subsequent Events

Please see Note 2—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Kroger Company Settlement and Note 9—Commitments and Contingencies—Western Long-Term Contract Complaints for a discussion of the recent agreement with Kroger related to four power supply contracts.

Please see Note 6—Debt—Amended Credit Facility for a discussion of our recently completed debt issuances.

Please see Note 6—Debt—ChevronTexaco Series B Preferred Stock Restructuring for a discussion of our recently completed restructuring of the previously outstanding Series B Mandatorily Convertible Redeemable Preferred Stock.

46

DYNEGY INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2003 and 2002

Item 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read together with the unaudited condensed consolidated financial statements included in this report and with the audited consolidated financial statements and the notes thereto included in the Form 10-K/A.

We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our three operating energy businesses are engaged in power generation, natural gas liquids and regulated energy delivery. Our power generation business owns or leases 13,167 MW of net generating capacity, including 838 MW which began commercial operation in the second quarter 2003. Our power generation fleet is diversified by facility type (base load, intermediate and peaking), fuel source and geographic location. Our natural gas liquids business owns natural gas gathering and processing assets located in key producing areas of Louisiana, New Mexico and Texas. This business also owns integrated assets used to fractionate, store, terminal, transport, distribute and market natural gas liquids. These assets are generally connected to and supplied by our and third parties’ natural gas gathering and processing assets and are located in Mont Belvieu, Texas, the hub of the U.S. natural gas liquids business, and West Louisiana. Our regulated energy delivery business is comprised of our Illinois Power Company subsidiary. Illinois Power serves more than 590,000 electricity customers and nearly 415,000 natural gas customers in Illinois.

We are restructuring our company around our asset-based energy businesses. In carrying out our restructuring, we have disposed of our communications business. We also have made significant progress in our planned exit from the customer risk management, or CRM, business. The remaining portion of our North American CRM business, which includes the five power tolling arrangements and some remaining gas and power contracts to which we remain a party, comprises our CRM segment.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Since the filing of our first quarter 2003 Form 10-Q on May 15, 2003, we have continued our efforts to restructure our company and to improve our liquidity position. We recently consummated a long-term refinancing and restructuring plan designed to eliminate a substantial portion of our 2005 and 2006 debt maturities and to address the $1.5 billion of Series B Mandatorily Convertible Redeemable Preferred Stock held by a subsidiary of ChevronTexaco. The plan consisted of the following:

• a $1.45 billion private placement offering of second priority senior secured notes by DHI;

• a $175 million private placement offering of convertible subordinated debentures by Dynegy:

• a tender offer and consent solicitation for up to $650 million of DHI public senior notes due in 2005 and 2006 and a prepayment of approximately $1.0 billion of bank debt; and

• a restructuring of the Series B preferred stock, which involved the exchange of such stock by a ChevronTexaco subsidiary in return for $225 million in cash and $625 million in newly issued Dynegy securities.

The successful consummation of these refinancing and restructuring transactions, which are described in more detail below, resolves the uncertainty relating to the Series B preferred stock, which provided for a

47

mandatory redemption in November 2003, and significantly reduces our debt maturities for the next several years. Specifically, we used the net proceeds from these transactions, together with cash on hand, primarily to prepay approximately $315 million of outstanding indebtedness under our restructured credit facility, to repurchase approximately $612 million of 2005-2006 public senior notes, to prepay the $696 million Black Thunder secured financing and to make a $225 million cash payment to ChevronTexaco pursuant to the Series B Exchange. As a result, our debt maturities through 2005 are as follows: $272 million (last six months of 2003), $345 million (2004) and $675 million (2005). We will, however, incur additional interest expense in connection with these transactions, and our future results of operations will be impacted by this added expense as well as the restrictive covenants contained in the related agreements.

We also have continued our exit from the CRM business. As a result, we have further reduced our collateral obligations relating to this business. Please read “—Collateral Obligations” below for further details.

Refinancing and Restructuring Transactions

In August 2003, we consummated a series of refinancing transactions, which we refer to as the Refinancing, comprised of the following:

• Issuance by DHI of $1.45 billion of second priority senior secured notes in a private placement transaction, which notes are secured on a second priority basis by substantially the same collateral that secures the obligations under DHI’s credit facility, which consists of a substantial portion of the available assets and stock of our direct and indirect subsidiaries, excluding Illinois Power;

• Issuance by Dynegy of $175 million of convertible subordinated debentures in a private placement transaction, which debentures are convertible into Dynegy’s Class A common stock and guaranteed on a senior unsecured basis by DHI; and

• A cash tender offer and related consent solicitation for all of DHI’s outstanding 8.125% Senior Notes due 2005, 6 ³/4% Senior Notes due 2005 and 7.450% Senior Notes due 2006.

Pursuant to the cash tender offer, which expired on August 8, 2003, we purchased approximately $282 million in principal amount of the 8.125% Senior Notes due 2005, approximately $150 million in principal amount of the 6 ³/4% Senior Notes due 2005 and approximately $180 million in principal amount of the 7.450% Senior Notes due 2006. We paid approximately $5 million above par value of these notes in connection with the purchase of these notes and the consent fee paid in connection with the related solicitation of the consents to eliminate several of the restrictive covenants and certain other provisions previously contained in the indentures governing these notes. As a result of obtaining the required consents, DHI executed and delivered supplemental indentures setting forth amendments to the applicable indentures, which govern the notes remaining outstanding following the expiration of the tender offer.

DHI Second Priority Senior Secured Notes.    In connection with the Refinancing, in August 2003 DHI issued $1.45 billion in second priority senior secured notes, comprised of $225 million in floating rate notes due 2008 which accrue interest at a rate of LIBOR plus 650 basis points (reset on a quarterly basis), $525 million in 9.875% notes due 2010 with a yield to maturity of 10.00% and $700 million in 10.125% notes due 2013 with a yield to maturity of 10.25%. Each of DHI’s existing and future wholly owned domestic subsidiaries that guarantee DHI’s obligations under its existing credit facility guarantee the obligations under the notes on a senior secured basis. In addition, Dynegy and its other subsidiaries that guarantee DHI’s existing credit facility guarantee the obligations under the notes on a senior secured basis. The notes and guarantees are senior obligations secured by a second-priority lien on, subject to certain exceptions and permitted liens, all of DHI’s and its guarantors’ existing and future property and assets that secure DHI’s obligations under its credit facility.

48

The indenture governing the notes contains restrictive covenants that limit the ability of DHI and its subsidiaries that guarantee the notes to, among other things:

• pay dividends or distributions on, or redeem or repurchase, capital stock;

• make investments;

• incur or guarantee additional indebtedness;

• create certain liens;

• engage in sale and leaseback transactions;

• make restricted payments;

• consolidate, merge or transfer all or substantially all of its assets; or

• engage in certain transactions with affiliates.

These covenants are set forth in the indenture governing the notes, which is filed as an exhibit to this Form 10-Q.

These covenants, together with the restrictions contained in the amended credit facility, will limit our ability to receive payments from DHI, for the purpose of paying dividends on our Class A common stock and otherwise, and to take certain other actions. Specifically, DHI’s ability to incur additional indebtedness for other than refinancing purposes is limited by certain prepayment provisions contained in the amended credit facility, the Secured Debt/EBITDA ratio contained in the amended credit facility and the fixed charge coverage ratio contained in the notes indenture. The notes indenture and the amended credit facility, together with the indenture relating to the junior notes issued to ChevronTexaco in connection with the Series B Exchange, also require that a significant portion of proceeds from specified asset sales be used to pay down outstanding indebtedness.

Dynegy Convertible Subordinated Debentures.    Concurrently with the issuance of DHI’s second priority senior secured notes, Dynegy issued $175 million in 4.75% convertible subordinated debentures due 2023. We have also granted the initial purchasers of the debentures a 30-day option to purchase up to $50 million of additional debentures on these same terms. The debentures are convertible into shares of our Class A common stock at any time at a conversion price of $4.1210 per share, subject to specified adjustments for dividend payment and other actions. The debentures are subordinated to Dynegy’s existing and future senior indebtedness and effectively subordinated to all indebtedness and liabilities of Dynegy’s non-guarantor subsidiaries. The debentures are guaranteed on a senior unsecured basis by DHI. We have agreed to file a registration statement covering resale of the debentures and the Class A common stock issuable upon conversion of the debentures, subject to the requirement to pay additional interest if such registration statement does not become effective within 360 days from August 11, 2003.

The terms of the debentures are set forth in the indenture governing the debentures, which is filed as an exhibit to this Form 10-Q.

Use of Proceeds.     The net proceeds from the Refinancing transaction, along with cash on hand, were utilized to make the cash payment required under the Series B Exchange, as described below, and to prepay certain of our indebtedness including:

• Prepay in full the $200 million Term A Loan outstanding under the DHI credit facility;

• Prepay approximately $115 million of the $360 million Term B Loan outstanding under the DHI credit facility;

• Repurchase approximately $612 million of DHI’s outstanding 8.125% Senior Notes due 2005, 6 ³/4% Senior Notes due 2005 and 7.45% Senior Notes due 2006; and

• Prepay $696 million of debt outstanding under the Black Thunder secured financing.

The pre-payment of the debt above will result in accelerated charges during the third quarter 2003 of approximately $20 million, pre-tax, of unamortized financing costs and the settlement value of the associated

49

interest-rate hedge instruments. We incurred upfront fees aggregating approximately $60 million in connection with the Refinancing. Such amounts have been capitalized and will be amortized over the term of the Refinancing.

ChevronTexaco Series B Preferred Stock Restructuring.    Also in August 2003, we consummated a restructuring of the $1.5 billion in Series B Mandatorily Convertible Redeemable Preferred Stock previously held by a subsidiary of ChevronTexaco. Pursuant to the restructuring, this ChevronTexaco subsidiary exchanged its Series B preferred stock for the following:

• a $225 million cash payment;

• $225 million principal amount of Junior Unsecured Subordinated Notes due 2016 issued by Dynegy; and

• 8 million shares of Dynegy’s Series C Convertible Preferred Stock due 2033 (liquidation preference $50 per share).

The junior notes bear interest at a rate of 9.00% per annum during the first two years and a rate of 13.75% per annum thereafter, in each case, compounded semi-annually and, at our option, payable in kind by issuance of additional junior notes. The junior notes contain mandatory and optional prepayment provisions as further described in Note 6—Debt.

With respect to the Series C preferred stock, dividends are payable at a rate of 5.5% per annum in cash semi-annually. At our election, we may defer dividend payments for up to ten consecutive semi-annual dividend payment periods. Upon termination of any deferral period, all accrued and unpaid amounts are due in cash. We may not pay dividends on our common stock during any deferral period. Additionally, if we fail to obtain shareholder approval for conversion of the Series C preferred stock into shares of our Class B common stock within one year, the dividend rate on the Series C preferred stock will increase to 10% until such time as we obtain such approval or it is determined that such approval is not required under NYSE rules and other applicable laws and regulations. Following the receipt of such approval, the shares of Series C preferred stock generally are convertible, at the option of the holder, at a price of $5.78 per share. The Series C preferred stock contains restrictions on conversion and transfer as further described in Note 6—Debt.

As part of the Series B Exchange, we also renegotiated certain prepayment arrangements with ChevronTexaco such that ChevronTexaco returned to us approximately $40 million in pre-payments relating to our commodity purchase obligations and converted our prepayment obligation from thirty days to seven days.

For a complete description of the junior notes and the Series C preferred stock, please read the agreements between us and ChevronTexaco entered into in connection with the Series B Exchange that are filed as exhibits to this Form 10-Q.

Restructured Bank Credit Facilities.    On April 2, 2003, DHI entered into a $1.66 billion credit facility consisting of:

• a $1.1 billion DHI secured revolving credit facility, which matures on February 15, 2005;

• a $200 million DHI secured Term A Loan, which was scheduled to mature on February 15, 2005; and

• a $360 million DHI secured Term B Loan, which matures on December 15, 2005.

We recently entered into an amendment to DHI’s credit facility to, among other things, permit the Refinancing and the Series B Exchange. The amendment became effective on August 11, 2003 upon closing of DHI’s private placement offering of $1.45 billion in second priority senior secured notes and Dynegy’s offering of $175 million in convertible subordinated debentures.

The amended credit facility consists of:

• a $1.1 billion secured revolving credit facility that matures on February 15, 2005; and

• a secured Term B Loan that matures on December 15, 2005 in an aggregate principal amount of approximately $245 million.

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The amended credit facility contains mandatory commitment reductions and prepayment events relating to asset sales, debt and equity issuances and dividend payments and restrictions on our ability to repurchase certain of our outstanding securities, subject to specified exceptions. The amended credit facility also prohibits us from pre-paying, redeeming or repurchasing outstanding debt or preferred stock prior to maturity, subject to specified exceptions. Please read Note 6—Debt for further discussion of the amended credit facility.

Our ability to address our substantial leverage could be affected by these restrictions. For example, we intend to use any excess cash flows to pay down outstanding indebtedness. If we are unable to satisfy the conditions to prepayment or redemption contained in the amended credit facility, we will need lender approval to effect such a pay down.

Liquidity Sources

The following table summarizes our consolidated credit capacity and liquidity position at December 31, 2002, June 30, 2003 and August 11, 2003 (in millions):

	December 31, 2002			June 30, 2003			August 11, 2003
Total Credit Capacity	$	1,400		$	1,100	(2)	$	1,100	(2)
Outstanding Loans		(228	)		—			—
Outstanding Letters of Credit Under Revolving Credit Facility		(872	)		(282	)		(408	)
Unused Borrowing Capacity		300			818			692
Cash		757			801			644	(3)
Liquid Inventory (1)		258			—			—
Total Available Liquidity	$	1,315		$	1,619		$	1,336

(1) Amounts reflected for 2003 periods do not include liquid inventory, as we have sold the natural gas inventories that comprised that item and converted them to cash.

(2) Reflects the conversion of $200 million of credit capacity under the former DHI revolving credit facilities into the Term A Loan in connection with the April 2003 restructuring of such facilities, as well as the May 2003 payment of the final $100 million then outstanding under Illinois Power’s termed out revolving credit facility.

(3) Reflects the use of approximately $260 million of cash on hand on August 11, 2003, in addition to the proceeds from the refinancing and restructuring transactions consummated on such date, for the prepayment of certain outstanding indebtedness as further described in “—Use of Proceeds” above.

Liquidity Uses

During the first six months of 2003, significant uses of liquidity included the following:

• Funding of $200 million in payments under the Renaissance and Rolling Hills interim financing;

• Funding of $41 million in payments under the Black Thunder financing;

• Funding of $43 million in payments on Illinois Power’s transitional funding trust notes;

• Funding of $36 million in payments under the ABG Gas Supply financing;

• Purchase of $5 million of Illinova senior notes on the open market; and

• Funding of a $100 million payment on Illinois Power’s term loan.

Since June 30, 2003, significant uses of liquidity have included the following:

• Funding of a $22 million payment under the Black Thunder financing;

• Funding of a $6 million payment under the ABG Gas Supply financing; and

• Funding of a $100 million Illinois Power mortgage bond maturity.

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We also used the approximately $1.5 billion in net proceeds we received from the Refinancing, together with cash on hand, to repay in full the $200 million Term A Loan and approximately $115 million of the $360 million Term B Loan outstanding under the credit facility, to purchase approximately $612 million of DHI’s previously outstanding 2005/2006 public notes and to pay consent fees in connection with the previously announced tender offer and consent solicitation for such notes, to prepay the $696 million outstanding under the Black Thunder financing, to make a $225 million cash payment to ChevronTexaco under the Series B Exchange and to pay related fees and expenses.

Collateral Obligations

During the first six months of 2003, we reduced the collateral obligations associated with our CRM business by $557 million. The following table summarizes our consolidated collateral postings by operating division at December 31, 2002, June 30, 2003 and August 11, 2003 (in millions):

	December 31, 2002		June 30, 2003		August 11, 2003
GEN	$	168	$	286	$	252
CRM		806		249		205
NGL		166		238		217
REG		28		15		15
Other		48		42		43
Total	$	1,216	$	830	$	732

The collateral requirements for our GEN and NGL businesses have increased since the end of 2002. This increase primarily was caused by a significant increase in power and natural gas prices during this period. Collateral requirements for these businesses will continue to reflect this sensitivity to commodity prices.

As described in Note 6—Debt—Revolvers and Commercial Paper above, we incur a 0.15% fronting fee upon the issuance of letters of credit under our restructured credit facility. A letter of credit fee is also payable on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 4.75% of such undrawn amount. To the extent practicable, we intend to use cash on hand, as opposed to letters of credit, to satisfy our future collateral obligations.

Disclosure of Financial Obligations and Contingent Financial Commitments

We have incurred various financial obligations and commitments in the normal course of our operations and financing activities. Financial obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. Financial commitments represent contingent obligations, which become payable only if certain pre-defined events occur, such as financial guarantees.

Our financial obligations and commitments have changed since December 31, 2002, with respect to which information is included in the Form 10-K/A. The following summarizes the most significant changes.

Long-term Debt.    As discussed more fully in Note 6—Debt, on April 2, 2003, we restructured our principal credit facility. Subsequently, we amended our principal credit facility, issued more than $1.6 billion in second priority senior secured notes and convertible subordinated debentures and used a portion of the proceeds to pay down certain obligations due in 2005 and 2006.

Series B Preferred Stock.    As discussed more fully in Note 7—Related Party Transactions, on July 28, 2003, we entered into an agreement with ChevronTexaco to exchange the $1.5 billion of Series B Mandatorily

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Convertible Redeemable Preferred Stock held by a ChevronTexaco subsidiary for $225 million in cash, $225 million of newly issued Dynegy Junior Unsecured Subordinated Notes due 2016 and $400 million of newly issued Dynegy Series C Convertible Preferred Stock.

Capacity Payments.    As discussed in Note 2—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Southern Power Tolling Arrangements, in May 2003 we paid $155 million to terminate our three power tolling arrangements with Southern Power, which terminations are effective as to two such arrangements in May 2003 and as to the third such arrangement in October 2003. As a result of these terminations, we have eliminated our obligation to make $1.7 billion in capacity payments over the next 30 years. As part of the Series B Exchange, we also renegotiated certain prepayment arrangements with ChevronTexaco such that ChevronTexaco returned to us approximately $40 million in pre-payments relating to our commodity purchase obligations and converted our prepayment obligation from thirty days to seven days.

Dividends on Preferred and Common Stock

Beginning with the third quarter 2002, our Board of Directors elected to cease payment of a dividend on our common stock. Payments of dividends for subsequent periods will be at the discretion of the Board of Directors, but we do not foresee reinstating the dividend in the near term. We have, however, continued to make the required dividend payments on our outstanding trust preferred securities. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Bank Restructuring” beginning on page 42 of the Form 10-K/A and “—DHI Second Priority Senior Secured Notes” above for a discussion of the dividend limitations contained in our restructured credit facility and second priority senior secured notes indenture.

There was no cash dividend required to be paid on the Series B preferred stock issued to ChevronTexaco in November 2001. Because of ChevronTexaco’s discounted conversion option, we accreted an implied preferred stock dividend over the redemption period, as required by GAAP. Please read “Item 8, Financial Statements and Supplementary Data, Note 13— Redeemable Preferred Securities” beginning on page F-61 of the Form 10-K/A for further discussion of this non-cash implied dividend. As more fully described in Note 7—Related Party Transactions, we have restructured the Series B preferred stock. In conjunction with the restructuring, we will recognize a gain of approximately $1.2 billion as a preferred stock dividend in the third quarter 2003.

Illinois Power Liquidity

Illinois Power has a significant amount of leverage, with near-term maturities including a $90 million mortgage bond maturity due in September 2003 and quarterly payments of approximately $22 million due on its transitional funding trust notes. Illinois Power is required to make these quarterly payments on its transitional funding trust notes through 2008 and has a payment of up to $81 million due on its Tilton lease financing in the third quarter 2004. Because Illinois Power has no revolving credit facility and no access to the commercial paper markets, it relies on cash on hand, cash from asset sales or other liquidity initiatives and cash flows from operations, including interest payments under its $2.3 billion intercompany note receivable from Illinova, to satisfy its debt obligations and to otherwise operate its business. In December 2002, Illinois Power closed on a private offering of $550 million of mortgage bonds, $150 million of which were issued in January 2003 following approval from the Illinois Commerce Commission. A portion of the proceeds were used to repay Illinois Power’s $300 million term loan (including the final payment of $100 million on May 2, 2003) and to replenish liquidity used to pay a $96 million mortgage bond maturity in July 2002. The remaining proceeds from this offering, together with the below-described interest payment on the intercompany note receivable, have been and will be used to fund Illinois Power’s August and September 2003 mortgage bond maturities.

On July 31, 2003, Dynegy made an interest payment of approximately $100 million on its $2.3 billion intercompany note receivable to Illinova, which in turn made an interest payment of approximately $100 million on its $2.3 billion intercompany note receivable to Illinois Power. The intercompany notes receivable contains identical interest payment provisions pursuant to which semi-annual interest payments of approximately $86 million are due on April 1 and October 1 of each year. The amount paid on July 31 represents accrued interest

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on the notes for the months of April-July and prepaid interest for the months of August-October. Illinois Power has used and will use these funds, together with the remaining proceeds from the December 2002 mortgage bond offering, to pay its August and September 2003 mortgage bond maturities. For the near term, Illinois Power will continue to rely on a support commitment by Dynegy in order to satisfy its obligations. Our restructured credit agreement, which matures in February 2005, permits prepayments of principal on the intercompany note receivable up to $200 million, but does not restrict the prepayment of interest thereon. Additionally, the indenture governing DHI’s second priority senior secured notes permits payments of principal on the intercompany note receivable up to $450 million or to the extent that a fixed change coverage ratio of 2:1 is satisfied. The indenture also permits the prepayment of interest thereon up to twelve months at any one time. Our long-term plan is for Illinois Power to sustain itself financially through cash flow from operations and proceeds from liquidity initiatives that could include, among other things, a revolving bank credit facility or additional debt issuances.

Conclusion

In August 2003, we completed a long-term refinancing and restructuring plan that included private placement offerings of more than $1.6 billion in DHI second priority senior secured notes and Dynegy convertible subordinated debentures and the use of proceeds from such offerings, together with cash on hand, to repay nearly $1.7 billion in 2005 and 2006 debt maturities. We also made a $225 million cash payment to ChevronTexaco as part of the Series B Exchange. By consummating the Series B Exchange, we believe that we have eliminated the uncertainty surrounding our former obligations under the Series B preferred stock, thereby creating the potential for future equity issuances, the proceeds of which would be used to reduce outstanding indebtedness in furtherance of our efforts to develop a capital structure that is more closely aligned with the cash- generating potential of our asset-based businesses.

By effectively extending the maturity dates of these obligations, together with the prior restructuring of our credit facilities that were scheduled to expire in April and May 2003, we believe that we have provided our company with sufficient capital resources to meet our debt obligations and provide collateral support for our ongoing asset businesses and our continued exit from third-party marketing and trading through at least 2004. Thereafter, our $1.1 billion revolving credit facility is scheduled to mature in February 2005, and our ability to address that maturity is critical to our future financial success. Our success and future financial condition will also depend on our ability to execute the remainder of our exit from the CRM business successfully and to produce adequate operating cash flows from our continuing asset-based businesses to meet our debt and commercial obligations, including a substantial increase in interest expense. Please read “Factors Affecting Future Results of Operations” and “Uncertainty of Forward-Looking Statements and Information” for additional factors that could impact our future operating results and financial condition.

FACTORS AFFECTING FUTURE RESULTS OF OPERATIONS

Our results of operations during the remainder of 2003 and beyond may be significantly affected by the following factors, among others:

• the level of earnings and cash flows from our asset-based businesses, which are subject to the effect of changes in commodity prices, particularly for power, natural gas, natural gas liquids and other fuels and, to a lesser extent, the spark spread between power and natural gas prices and the fractionation spread between natural gas and natural gas liquids prices;

• the effects of competition on the results of operations from our asset-based businesses;

• the effects of milder weather on our sales of power and natural gas liquids;

• our ability to complete our exit from the CRM business and the costs associated with this exit;

• our ability to operate our asset-based businesses with a reduced work force and within the confines of the increased borrowing rates and more restrictive covenants contained in our restructured credit agreement and the DHI second priority senior secured notes indenture;

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• our ability to address our substantial leverage, including our remaining 2005 debt maturities;

• our ability to fund or obtain financing for working capital, capital expenditures and general corporate purposes and to otherwise respond to economic downturns, competition and other market pressures, given the various restrictions contained in our amended credit facility and second priority senior secured notes indenture;

• increased interest expense and the other effects of our restructured credit agreement, second priority senior secured notes and convertible subordinated debentures; and

• the effects of ongoing litigation relating to, among other things, the western power and natural gas markets and shareholder claims, as well as the ongoing regulatory investigations primarily relating to Project Alpha and our past trading practices.

Additionally, as further discussed in Note 1 to the unaudited condensed consolidated financial statements, new accounting pronouncements have impacted our results of operations and will continue to do so in the future. Please read “Uncertainty of Forward-Looking Statements and Information” for additional factors that could impact our future operating results.

RESULTS OF OPERATIONS

In this section, we discuss our results of operations, both on a consolidated basis and by segment, for the three- and six-month periods ended June 30, 2003 and 2002.

As reflected in this report, we have changed our reporting segments. In 2002, we reported results for the following four business segments:

• Wholesale Energy Network, or WEN;

• Dynegy Midstream Services, or DMS;

• Transmission and Distribution, or T&D; and

• Dynegy Global Communications, or DGC.

Beginning January 1, 2003, we are reporting our operations in the following segments:

• Power generation, or GEN;

• Natural gas liquids, or NGL;

• Regulated energy delivery, or REG; and

• Customer risk management, or CRM.

Other reported results include corporate overhead and our discontinued communications operations. All corporate overhead included in other reported results was allocated to the four operating segments prior to January 1, 2003.

As described in Note 11 to the unaudited condensed consolidated financial statements included in this report, prior to January 1, 2003, the GEN and CRM segments were operated together as an asset-based third-party marketing, trading and risk-management business, then referred to as the WEN segment. Most, but not all, of the WEN third-party purchase and sale contracts were held by a subsidiary which is currently included within the CRM segment. Under this business model, the net fair value of most of GEN’s generation capacity, forward sales and related trading positions were sold to the CRM segment monthly at an internally determined transfer price. The internal transfer price was primarily comprised of the option value of generation capacity and executed forward sales contracts based on then-current forward prices of power and fuel. GEN results for the three- and six-month periods ended June 30, 2002 reflect this internal transfer price and do not represent amounts

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actually received by GEN for power sold to third parties. As such, the GEN results for the three- and six-month periods ended June 30, 2002 do not include the effect of intra-month market price volatility. The CRM segment recorded results from these third-party contracts, together with all of its other third-party marketing and trading positions unrelated to the GEN segment.

In connection with our exit from the third-party marketing and trading business, individual contracts within the former WEN segment were identified on January 1, 2003 as either GEN contracts, as they were determined to be a part of our continuing operations, or CRM contracts. Under this new business segment model, CRM continues to transact with third parties on behalf of GEN for contracts which were identified as GEN contracts, as well as new transactions executed on behalf of GEN but for which CRM is the legal party to the third-party purchase and sale contract. CRM continues to record results from these third-party contracts, together with all of its other third-party marketing and trading positions unrelated to the GEN segment. However, rather than purchasing such capacity, forward sales and related trading positions from GEN at an internally determined transfer price, pricing between CRM and GEN is set at the actual amount received or paid for the purchases and sales to the third parties. Therefore, GEN results for the three- and six-month periods ended June 30, 2003 include the effects of intra-month market price volatility. These differences should be considered when attempting to compare the results for the three- and six-month periods ended June 30, 2003 and 2002.

Recent accounting pronouncements have affected our financial results, particularly those of our CRM business, so as to further reduce the comparability of some of our historical financial data. For example, the rescission of EITF Issue 98-10, effective January 1, 2003, has reduced the number of contracts accounted for on a mark-to-market basis in the 2003 period as compared to the 2002 period. Please read “—Cumulative Effect of Change in Accounting Principle” below for further discussion.

For segment reporting purposes, all direct general and administrative expenses incurred by Dynegy on behalf of its subsidiaries are charged to the applicable subsidiary as incurred. Other income (expense) items incurred by us on behalf of our subsidiaries are allocated directly to the four segments.

Three and Six Months Ended June 30, 2003 and 2002

The following table provides summary financial data regarding our unaudited condensed consolidated results of operations for the three- and six-month periods ended June 30, 2003 and 2002, respectively (in millions):

Results of Operations

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
Operating Loss	$	(374	)	$	(143	)	$	(187	)	$	(58	)
Earnings from Unconsolidated Investments		38			18			91			53
Interest Expense		(109	)		(64	)		(219	)		(130	)
Other Items, Net		(9	)		(25	)		12			(39	)
Income Tax Benefit		168			75			112			82
Income from Continuing Operations		(286	)		(139	)		(191	)		(92	)
Loss on Discontinued Operations, Net of Taxes		(4	)		(422	)		(7	)		(482	)
Cumulative Effect of Change in Accounting Principle, Net of Taxes		—			—			55			(234	)
Net Loss	$	(290	)	$	(561	)	$	(143	)	$	(808	)

Three Months Ended June 30, 2003 and 2002

Net Loss.    For the quarter ended June 30, 2003, we recorded a net loss of $290 million, compared with a second quarter 2002 net loss of $561 million. After taking into consideration the $82 million preferred stock implied dividend, diluted loss per share for the quarter ended June 30, 2003 was $1.00 compared to a diluted loss per share of $1.76 for the quarter ended June 30, 2002.

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The operating loss of $374 million primarily reflects charges incurred in our CRM segment, as well as a $50 million incremental litigation reserve. These charges, together with generally lower volumes period-over-period, were offset by favorable commodity prices, which positively impacted our GEN and NGL segments. REG’s operating income was negatively affected period-over-period by lower weather-driven demand. Operating loss also reflects increased depreciation and amortization expense primarily associated with the expansion of our depreciable asset base period-over-period, including the completion of three generation facilities that were under construction during the second quarter 2002. General and administrative expenses were higher period-to-period principally as a result of the $50 million litigation reserve and higher professional fees, offset by significantly lower compensation costs in the 2003 period.

Earnings from Unconsolidated Investments.    Our earnings from unconsolidated investments were approximately $38 million in the 2003 period compared to $18 million in 2002. The increase period-to-period primarily reflects higher realized margins by West Coast Power, a 50-50 joint venture through which we own our California power generation facilities, resulting from forward hedges put in place in connection with the execution of the West Coast Power-CDWR contract. Please read “—Segment Disclosures—Power Generation” below for further discussion.

Interest Expense.    Interest expense totaled $109 million for the three-month period ended June 30, 2003, compared to $64 million for the 2002 period. The significant increase period-to-period is attributable to higher average principal balances in the 2003 period compared to the 2002 period, higher average interest rates on borrowings, increased amortization of debt issuance costs and higher letter of credit fees. In addition, 2002 interest expense does not include interest expense allocated to our discontinued businesses. The increase in principal balances primarily resulted from substantially higher collateral postings in the second and third quarters of 2002, which, despite subsequent reductions, remained at levels above those outstanding during the second quarter 2002. Please read “—Liquidity and Capital Resources—Collateral Obligations” above for a discussion of the significant reductions in collateral postings, particularly with respect to our CRM business, since the end of the third quarter 2002. The higher interest rates and letter of credit fees resulted from the restructuring of our credit facility in April 2003, with respect to which such rates and fees are higher than those contained in our previous facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Bank Restructuring” beginning on page 42 of the Form 10-K/A for further discussion.

As described elsewhere in this quarterly report, we expect that the Refinancing and the Series B Exchange will cause us to incur additional interest expense in the future.

Other Items, Net.    Other items, net consists of other income and expense items, net, minority interest income (expense) and accumulated distributions associated with trust preferred securities in the unaudited condensed consolidated statements of operations. Other items, net totaled $9 million and $25 million in expense for the three-month periods ended June 30, 2003 and 2002, respectively.

Income Tax Benefit.    We reported an income tax benefit of $168 million for the quarter ended June 30, 2003, compared to an income tax benefit of $75 million for the 2002 period. The 2003 effective rate of 37 percent was increased from statutory rates primarily as a result of state income taxes. The tax benefit in the 2002 period resulted from the combination of book income and losses in jurisdictions with varying tax rates and the realization of permanent differences.

Discontinued Operations.    Discontinued operations primarily include Northern Natural, our global liquids business, our U.K. natural gas storage assets, our U.K. CRM business and our communications business. The second quarter 2003 loss of $4 million is comprised of $4 million in after-tax losses on the communications business and $1 million in after-tax losses from global liquids offset by $1 million in after-tax income associated with U.K. CRM. The second quarter 2002 loss of $422 million is comprised of $424 million in after-tax losses from the communications business, $5 million in after-tax losses from Northern Natural and $3 million in after-tax losses from global liquids offset by $2 million in after-tax income associated with U.K. CRM and $8 million in after-tax income from the U.K. natural gas storage assets.

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Significant Items.    The following table sets forth significant pre-tax items affecting net loss for the three months ended June 30, 2003 and 2002 (in millions).

	Three Months Ended June 30, 2003
	GEN			NGL			REG			CRM			Other			Total
Southern Power settlement (1)	$	—		$	—		$	—		$	(133	)	$	—		$	(133	)
Kroger settlement (2)		—			—			—			(30	)		—			(30	)
Sithe power tolling contract (3)		—			—			—			(132	)		—			(132	)
Legal reserve (4)		—			—			—			—			(50	)		(50	)
Gain on sale of Hackberry LNG (5)		—			10			—			2			—			12
Discontinued operations (6)		—			(1	)		—			4			(6	)		(3	)
Total	$	—		$	9		$	—		$	(289	)	$	(56	)	$	(336	)
	Three Months Ended June 30, 2002
	GEN			NGL			REG			CRM			Other			Total
Discontinued operations (7)	$	—		$	(4	)	$	(8	)	$	18		$	(664	)	$	(658	)
Restructuring costs (8)		(4	)		(4	)		(6	)		(17	)		—			(31	)
Impairment of technology investments (9)		(4	)		(3	)		(1	)		(11	)		—			(19	)
Other (10)		(7	)		(1	)		(1	)		(2	)		—			(11	)
Total	$	(15	)	$	(12	)	$	(16	)	$	(12	)	$	(664	)	$	(719	)

(1) We recognized a pre-tax charge of approximately $133 million ($84 million after-tax) related to the settlement of three power tolling arrangements with Southern Power for $155 million. This charge is included in Cost of sales.

(2) We recognized a pre-tax charge of approximately $30 million ($19 million after-tax) for a settlement agreement reached with Kroger related to four power supply agreements. The charge is included in Cost of sales.

(3) We recognized a pre-tax charge of approximately $132 million ($83 million after-tax) related to a mark-to-market loss incurred during the quarter on contracts associated with the Sithe Independence power tolling arrangement. This charge is included in Cost of sales.

(4) We recognized a pre-tax charge of approximately $50 million ($32 million after-tax) for legal reserves. This charge is included in General and administrative expenses.

(5) We recognized a pre-tax gain of approximately $12 million ($8 million after-tax) on the sale of our interest in Hackberry LNG Terminal LLC.

(6) We recognized a pre-tax loss of approximately $3 million ($4 million after-tax) related to discontinued operations.

(7) We recognized a pre-tax loss of approximately $658 million ($422 million after-tax) related to discontinued operations. Included in the loss on discontinued operations is $611 million in charges related to the impairment of communications assets.

(8) We recognized a pre-tax charge of approximately $31 million ($20 million after-tax) for severance benefits for approximately 325 employees, including our former Chief Executive Officer and Chief Financial Officer. This charge, which was allocated to our reporting segments in accordance with our usual accounting methods, is included in Impairment and other charges.

(9) We recognized a pre-tax charge of approximately $19 million ($12 million after-tax) for the impairment of certain technology investments. These charges, which were allocated to our reporting segments in accordance with our usual accounting methods, are included in Earnings from unconsolidated investments.

(10) We recognized a pre-tax charge of approximately $5 million ($3 million after-tax) related to information technology equipment write-offs. This charge is included in Impairment and other charges. Additionally, we incurred approximately $6 million of pre-tax ($4 million after-tax) charges associated with fees related to a voluntary action that we took that altered the accounting for certain lease obligations. This amount is included in Impairment and other charges.

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Six Months Ended June 30, 2003 and 2002

Net Loss.    For the six-month period ended June 30, 2003, we recorded a net loss of $143 million, compared with a net loss of $808 million for the six-month period ended June 30, 2002. After taking into consideration the $165 million preferred stock implied dividend, diluted loss per share for the six-month period ended June 30, 2003 was $0.83 compared to a diluted loss per share of $2.67 for the six-month period ended June 30, 2002.

The operating loss of $187 million primarily reflects charges incurred in our CRM segment, as well as a $50 million incremental litigation reserve. These items were offset by higher period-over-period commodity prices, which positively impacted our GEN and NGL segments, as well as weather-driven demand resulting in greater volumes produced and sold by GEN. REG’s operating income was negatively impacted period-over-period by lower spring-weather driven sales, partially offset by higher winter-weather driven sales. Operating loss also reflects increased depreciation and amortization expense primarily associated with the expansion of our depreciable asset base period-over-period, including the completion of three generation facilities that were under construction during the first six months of 2002. General and administrative expenses were higher period-to-period principally as a result of the $50 million litigation reserve and higher professional fees, offset by significantly lower compensation costs in the 2003 period.

Earnings from Unconsolidated Investments.    Our earnings from unconsolidated investments were approximately $91 million in the 2003 period compared to $53 million in 2002. The increase period-to-period primarily reflects higher realized margins by West Coast Power, resulting from forward hedges put in place in connection with the execution of the West Coast Power-CDWR contract. Please read “—Segment Disclosures—Power Generation” below for further discussion.

Interest Expense.    Interest expense totaled $219 million for the six-month period ended June 30, 2003, compared to $130 million for the 2002 period. The significant increase period-to-period primarily is attributable to higher average principal balances in the 2003 period compared to the 2002 period, higher average interest rates on borrowings, increased amortization of debt issuance costs and higher letter of credit fees. In addition, 2002 interest expense does not include interest expense which was allocated to our discontinued businesses. The increase in principal balances primarily resulted from substantially higher collateral postings in the second and third quarters of 2002, which, despite subsequent reductions, remained at levels above those outstanding during the first half of 2002. Please read “—Liquidity and Capital Resources—Collateral Obligations” above for a discussion of the significant reductions in collateral postings, particularly with respect to our CRM business, since the end of the third quarter 2002. The higher interest rates and letter of credit fees resulted from the restructuring of our credit facility in April 2003, with respect to which such rates and fees are higher than those contained in our previous facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Bank Restructuring” beginning on page 42 of the Form 10-K/A for further discussion.

While these collateral reductions are expected to reduce our 2003 principal balances, higher commodity prices compared to 2002 and a related increase in collateral postings associated with our CRM, GEN and NGL businesses may offset some of the impact. In addition, our interest expense during the remainder of 2003 and thereafter will reflect our increased costs of borrowing. Interest expense for the remainder of 2003 will also reflect higher costs from Illinois Power’s December 2002 and January 2003 issuances of mortgage bonds totaling $550 million, which bonds were issued at a 12% effective interest rate compared to Illinois Power’s average 2002 mortgage bond interest rate of 5.81%. Significantly, we expect that the Refinancing and the Series B Exchange will result in higher interest costs for the remainder of the year and thereafter, primarily as a result of higher average interest rates. Interest expense in the third quarter 2003 will also include approximately $20 million of pre-tax charges associated with accelerated amortization of previously incurred financing costs, as described above.

Other Items, Net.    Other items, net consists of other income and expense items, net, minority interest income (expense) and accumulated distributions associated with trust preferred securities in the unaudited

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condensed consolidated statements of operations. Other items, net totaled $12 million in income and $39 million in expense for the six-month periods ended June 30, 2003 and 2002, respectively. The change in these amounts primarily represents increases in minority interest income in the 2003 period.

Income Tax Benefit.    We reported an income tax benefit of $112 million for the six-month period ended June 30, 2003, compared to an income tax benefit of $82 million for the 2002 period. The 2003 effective rate of 37 percent was increased from statutory rates primarily as a result of state income taxes. The tax benefit in the 2002 period resulted from the combination of book income and losses in jurisdictions with varying tax rates and the realization of permanent differences.

Discontinued Operations.    Discontinued operations primarily include Northern Natural, our global liquids business, our U.K. natural gas storage assets, our U.K. CRM business and our communications business. The loss of $7 million for the six-month period ended June 30, 2003 is comprised of $9 million in after-tax losses on operations of U.K. CRM and $1 million in after-tax losses from global liquids, offset by $3 million in after-tax income associated with the communications business. The 2002 loss of $482 million is comprised of $506 million in after-tax losses from the communications business, $8 million in after-tax losses associated with U.K. CRM and $3 million in after-tax losses from global liquids offset by $22 million in after-tax income from Northern Natural, and $13 million in after-tax income from the U.K. natural gas storage assets.

Cumulative Effect of Change in Accounting Principle.    As described in Note 1 to the unaudited condensed consolidated financial statements,we reflected the rescission of EITF Issue 98-10 effective January 1, 2003 as a cumulative effect of change in accounting principle. The net impact was an after-tax benefit of $21 million. We also adopted SFAS No. 143 effective January 1, 2003 and recognized an after-tax benefit of $34 million associated with its implementation. As described in Note 3 to the unaudited condensed consolidated financial statements, we adopted SFAS No. 142 effective January 1, 2002. In connection with its adoption, we realized a cumulative effect loss of approximately $234 million associated with a write-down of goodwill in our discontinued communications business.

Significant Items.    The following table sets forth significant pre-tax items affecting net loss for the six-months ended June 30, 2003 and 2002 (in millions).

	Six Months Ended June 30, 2003
	GEN			NGL			REG			CRM			Other			Total
Southern Power settlement (1)	$	—		$	—		$	—		$	(133	)	$	—		$	(133	)
Kroger settlement (2)		—			—			—			(30	)		—			(30	)
Sithe power tolling contract (3)		—			—			—			(132	)		—			(132	)
Legal reserve (4)		—			—			—			—			(50	)		(50	)
Gain on sale of Hackberry LNG (5)		—			10			—			2			—			12
Discontinued operations (6)		—			(1	)		—			(11	)		(4	)		(16	)
Cumulative effect of change in accounting principles (7)		47			—			(3	)		43			—			87
Total	$	47		$	9		$	(3	)	$	(261	)	$	(54	)	$	(262	)
	Six Months Ended June 30, 2002
	GEN			NGL			REG			CRM			Other			Total
Discontinued operations (8)	$	—		$	(5	)	$	37		$	11		$	(773	)	$	(730	)
Restructuring costs (9)		(4	)		(4	)		(6	)		(17	)		—			(31	)
Impairment of technology investments (10)		(4	)		(3	)		(1	)		(11	)		—			(19	)
Other (11)		(7	)		(1	)		(1	)		(2	)		—			(11	)
Cumulative effect of change in accounting principle (12)		—			—			—			—			(234	)		(234	)
Total	$	(15	)	$	(13	)	$	29		$	(19	)	$	(1,007	)	$	(1,025	)

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(1) We recognized a pre-tax charge of approximately $133 million ($84 million after-tax) related to the settlement of three power tolling arrangements with Southern Power for $155 million. This charge is included in Cost of sales.

(2) We recognized a pre-tax charge of approximately $30 million ($19 million after-tax) for a settlement agreement reached with Kroger related to four power supply agreements. The charge is included in Cost of sales.

(3) We recognized a pre-tax charge of approximately $132 million ($83 million after-tax) related to a mark-to-market loss incurred during the six months on contracts associated with the Sithe Independence power tolling arrangement. This charge is included in Cost of sales.

(4) We recognized a pre-tax charge of approximately $50 million ($32 million after-tax) for legal reserves. This charge is included in General and administrative expenses.

(5) We recognized a pre-tax gain of approximately $12 million ($8 million after-tax) on the sale of our interest in Hackberry LNG Terminal LLC.

(6) We recognized a pre-tax loss of approximately $16 million ($7 million after-tax) related to discontinued operations.

(7) As described in Note 1 to the unaudited condensed consolidated financial statements, we reflected the rescission of EITF Issue 98-10 effective January 1, 2003 as a cumulative effect of change in accounting principle. The net impact was a pre-tax benefit of $33 million ($21 million after-tax). We also adopted SFAS No. 143 effective January 1, 2003 and recognized a pre-tax benefit of $54 million ($34 million after-tax) associated with its implementation.

(8) We recognized a pre-tax loss of approximately $730 million ($482 million after-tax) related to discontinued operations. Included in the loss on discontinued operations is $631 million in charges related to the impairment of communications assets and $49 million in charges related to the impairment of technology investments.

(9) We recognized a pre-tax charge of approximately $31 million ($20 million after-tax) for severance benefits for approximately 325 employees, including our former Chief Executive Officer and Chief Financial Officer. This charge, which was allocated to our reporting segments in accordance with our usual accounting methods, is included in Impairment and other charges.

(10) We recognized a pre-tax charge of approximately $19 million ($12 million after-tax) for the impairment of certain technology investments. These charges, which were allocated to our reporting segments in accordance with our usual accounting methods, are included in Earnings from unconsolidated investments.

(11) We recognized a pre-tax charge of approximately $5 million ($3 million after-tax) related to information technology equipment write-offs. This charge is included in Impairment and other charges. Additionally, we incurred approximately $6 million of pre-tax ($4 million after-tax) charges associated with fees related to a voluntary action that we took that altered the accounting for certain lease obligations. This amount is included in Impairment and other charges.

(12) We adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” effective January 1, 2002, and, accordingly, tested for impairment all amounts recorded as goodwill. We determined that goodwill associated with our communications business was impaired and recognized a charge of $234 million for this impairment in the first quarter 2002.

Segment Disclosures

Non-GAAP Financial Measures.    Management uses Earnings Before Interest and Taxes, or “EBIT,” as one measure of financial performance of our business segments. EBIT is a non-GAAP financial measure and consists of operating income, earnings from unconsolidated investments, other income and expenses, net, minority interest income (expense), accumulated distributions associated with trust preferred securities, discontinued operations and cumulative effect of change in accounting principles. EBIT does not include interest expense or income taxes, each of which is evaluated on a consolidated level. Because we do not allocate interest expense and income taxes by segment, we believe that EBIT is a useful measurement of our segment performance for investors. EBIT should not be considered an alternative to, or more meaningful than, net income

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or cash flows from operations as determined in accordance with GAAP. Our segment EBIT may not be comparable to similarly titled measures used by other companies.

Power Generation

	Three Months Ended June 30,					Six Months Ended June 30,
	2003		2002			2003		2002
	(in millions, except operating statistics)
Total Operating Income	$	16	$	85		$	99	$	119
Earnings from Unconsolidated Investments		45		34			84		62
Other Items, Net		—		(12	)		3		(15	)
Cumulative Effect of Change in Accounting Principle		—		—			47		—
Earnings Before Interest and Taxes	$	61	$	107		$	233	$	166
Operating Statistics:
Million Megawatt Hours Generated—Gross		8.7		9.6			18.6		18.1
Million Megawatt Hours Generated—Net		8.3		9.0			17.7		17.0
Average Natural Gas Price—Henry Hub ($/MMbtu)	$	5.63	$	3.38		$	6.00	$	2.96
Average On-Peak Market Power Prices ($/MW hour)
Cinergy	$	32.53	$	26.06		$	41.59	$	24.00
Commonwealth Edison		32.85		26.08			40.40		23.92
Southern		39.57		30.67			44.19		26.46
New York—Zone G		57.95		45.39			66.92		38.82
ERCOT		55.02		34.51			55.57		28.14

Three-Month Periods Ended June 30, 2003 and 2002

GEN reported EBIT of $61 million for the three-month period ended June 30, 2003 compared to $107 million for the same period in 2002. EBIT consists of the following amounts reported by GEN for the periods presented: operating income of $16 million and $85 million, respectively; earnings from unconsolidated investments of $45 million and $34 million, respectively; and other items, net of zero and $(12) million, respectively. This segment’s results for the second quarter 2003 reflected higher power prices and limited excess generation capacity in selected markets we serve. Second quarter 2003 results also include a pre-tax charge of $15 million associated with a payment for the early termination of an out-of-the-money sales contract that was scheduled to expire on December 31, 2003.

GEN’s reported operating income for the second quarter 2003 also includes approximately $6 million of losses related to forward purchases and sales transactions that are recorded on a mark-to-market basis, as these transactions did not meet the criteria for hedge accounting under SFAS No. 133. GEN’s second quarter 2002 results include approximately $24 million of mark-to-market income related to derivative contracts which did not qualify as hedges. Additionally, we recognized earnings of $36 million in the second quarter 2003 related to our equity investment in West Coast Power. West Coast Power’s earnings increased 64 percent from the second quarter 2002 due to higher realized margins resulting from forward hedges put in place in connection with the execution of the West Coast Power-CDWR contract. Please read “Item 1. Business—Segment Discussion—Power Generation” beginning on page 4 of the Form 10-K/A for further discussion of the West Coast Power-CDWR contract and the legal challenges relating thereto.

Operating income for the three-month period ended June 30, 2002 reflects the sale to our CRM segment of the fair value of GEN’s generation capacity, forward sales and related trading positions at an internally determined transfer price. For the three-month period ended June 30, 2003, operating income for the GEN segment reflects the sale of power to third parties at market prices. Please take into account these differences

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when attempting to compare the second quarter results for 2002 and 2003. Please see Note 11 to the accompanying unaudited condensed consolidated financial statements for further discussion regarding our change in reporting segments beginning January 1, 2003 and the comparability of these results.

Net electric power produced and sold was 8.3 million MW hours for the second quarter 2003, which represented an 8 percent decrease over 2002, primarily as a result of the deferral of scheduled maintenance of some units from the first to the second quarter and decreased spark spreads.

Six-Month Periods Ended June 30, 2003 and 2002

GEN reported EBIT of $233 million for the six-month period ended June 30, 2003 compared to $166 million for the same period in 2002. EBIT consists of the following amounts reported by GEN for the periods presented: operating income of $99 million and $119 million, respectively; earnings from unconsolidated investments of $84 million and $62 million, respectively; other items, net of $3 million and $(15) million, respectively; and cumulative effect of change in accounting principle of $47 million and zero, respectively. This segment’s results for the first six months of 2003 reflected higher power prices as demand for power was higher in the Midwest and Northeast regions given colder than expected weather conditions and less capacity due to periodic outages at other generation facilities during the second quarter 2003. Net MW hours generated were 10.2 million and 2.5 million in the first six months of 2003 versus 9.1 million and 1.6 million in the first six months of 2002 in the Midwest and Northeast, respectively. Due to the increase in demand period-to-period, average on-peak prices increased 69 percent and 72 percent in the Midwest and Northeast, respectively. Results for 2003 also included a pre-tax charge of $15 million associated with a payment for the early termination of an out-of-the-money power sales contract that was scheduled to expire on December 31, 2003.

GEN’s reported operating income for the 2003 period also includes approximately $8 million of income related to forward purchases and sales transactions which are recorded on a mark-to-market basis, as these transactions did not meet the criteria for hedge accounting under SFAS No. 133. GEN’s results for the 2002 period include approximately $37 million of mark-to-market income related to derivative contracts which did not qualify as hedges. Additionally, we recognized earnings of $65 million in the first half of 2003 related to our equity investment in West Coast Power. West Coast Power’s earnings increased 77 percent from the first half of 2002 due to higher realized margins resulting from forward hedges put in place in connection with the execution of the West Coast Power-CDWR contract. Please read “Item 1. Business—Segment Discussion—Power Generation” beginning on page 4 of the Form 10-K/A for further discussion of the West Coast Power-CDWR contract and the legal challenges relating thereto.

Operating income for the six-month period ended June 30, 2002 reflects the sale to our CRM segment of the fair value of GEN’s generation capacity, forward sales and related trading positions at an internally determined transfer price. For the six-month period ended June 30, 2003, operating income for the GEN segment reflects the sale of power to third parties at market prices. Please take into account these differences when attempting to compare the results for 2002 and 2003. Please see Note 11 to the accompanying unaudited condensed consolidated financial statements for further discussion regarding our change in reporting segments beginning January 1, 2003 and the comparability of these results.

Net electric power produced and sold was 17.7 million MW hours for the first half of 2003, which represented a 4 percent increase over 2002, primarily as a result of favorable weather conditions.

Power Generation Outlook

We expect that this segment’s future financial results will continue to reflect a sensitivity to power prices, weather and other factors affecting generation demand, natural gas and other fuel prices (including, to a lesser extent, the “spark spread,” or price differential between natural gas and power), and terms of contracts. We believe that our generation fleet’s fuel diversity will help mitigate the extent to which this segment’s future

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results are affected by changes in the spark spread. We also expect that this business will continue its efforts to manage its price risk through the optimization of fuel procurement and the marketing of power generated from its assets. As part of our strategy of optimizing our assets, including agency and energy management agreements to which we are a party, we enter into financial and other transactions, including forward hedge activities, relating to our generating capacity. This segment’s sensitivity to prices and our ability to manage this sensitivity is subject to a number of factors, including general market liquidity, particularly in forward years, our ability to provide necessary collateral support and the willingness of counterparties to transact business with us given our non-investment grade credit ratings. Other factors that could affect the prices at which transactions can be consummated and this segment’s results of operations include transmission constraints, or the lack thereof, and governmental actions, excess generation capacity or supply shortages in the markets we serve. Please see “Item 1. Business—Segment Discussion—Power Generation” beginning on page 4 of the Form 10-K/A for a discussion of the effects of competition on this segment’s future results of operations.

Any events that negatively impact this segment’s significant long-term power sales agreements could likewise affect its future results of operations. For example, equity earnings from West Coast Power are primarily derived from West Coast Power’s long-term power sales contract with the CDWR. That contract, which runs through December 31, 2004, is the subject of various legal challenges. The success of any such challenges could negatively impact this segment’s equity earnings from West Coast Power and, accordingly, results of operations for the periods affected.

We also are pursuing sales of our ownership interests in a number of domestic and international generating projects that we consider non-strategic to this business. We generally hold ownership interests in these projects of 50% or less, which translates to less than 1,000 MW of net generating capacity. We do not expect that the sale of any or all of our ownership interests in these projects would have a material impact on this segment’s results of operations or cash flows.

Natural Gas Liquids

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
	(in millions, except operating statistics)
Operating Income:
Upstream	$	26		$	6		$	55		$	19
Downstream		13			8			35			35
Total Operating Income		39			14			90			54
Earnings from Unconsolidated Investments		2			3			5			7
Other Items, Net		(5	)		(12	)		(10	)		(11	)
Discontinued Operations		(1	)		(4	)		(1	)		(5	)
Earnings Before Interest and Taxes	$	35		$	1		$	84		$	45
Operating Statistics:
Natural Gas Processing Volumes (MBbls/d):
Field Plants		60.0			52.7			58.1			54.3
Straddle Plants		26.4			37.9			26.6			37.1
Total Natural Gas Processing Volumes		86.4			90.6			84.7			91.4
Fractionation Volumes (MBbls/d)		188.2			241.6			181.9			223.2
Natural Gas Liquids Sold (MBbls/d)		275.6			468.8			319.7			538.7
Average Commodity Prices:
Crude Oil—WTI ($/Bbl)	$	29.31		$	25.32		$	31.86		$	22.95
Natural Gas Liquids ($/Gal)	$	0.51		$	0.39		$	0.56		$	0.36
Fractionation Spread ($/MMBtu)	$	0.46		$	1.02		$	0.42		$	1.16

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Three-Month Periods Ended June 30, 2003 and 2002

NGL reported EBIT of $35 million for the three-month period ended June 30, 2003 compared to $1 million for the same period in 2002. EBIT consists of the following amounts reported by NGL for the periods presented: operating income of $39 million and $14 million, respectively; earnings from unconsolidated investments of $2 million and $3 million, respectively; other items, net of $(5) million and $(12) million, respectively; and discontinued operations of $(1) million and $(4) million, respectively. Upstream operating income increased period-over-period primarily as a result of higher natural gas and natural gas liquids prices, which caused significantly increased processing plant margins at our field plants. Total volumes of liquids produced at our field plants increased 13 percent period-over-period primarily due to increased production in the highly active drilling area in North Texas. Our straddle plant volumes were much lower period-to-period because of the low fractionation spread, which resulted in our decision to by-pass unprofitable gas or to shut-down plants that are subject to fractionation spread risk.

In our downstream business, volumes fractionated declined 22 percent period-to-period as a direct result of the reduced liquids recovery from both our own and from third-party gas processing plants resulting from the low fractionation spread. Additional factors adversely affecting the volumes fractionated include the willingness of some of our competitors to reduce fractionation fees below levels acceptable to us, expiration of some long-term fractionation agreements and customer concerns relating to our liquidity and non-investment grade credit status. In our wholesale marketing operations, profits were slightly higher due to the impact of higher liquids prices on our percentage of netback contracts in our refinery services business. Natural gas liquids marketing results declined from prior period levels as a result of reduced overall market liquidity and customer concerns relating to our liquidity and non-investment grade credit status. Downstream operating income for the three months ended June 30, 2003 includes a pre-tax gain of approximately $10 million on the sale of our investment in the Hackberry LNG project. Downstream operating income for the three months ended June 30, 2002 also includes income of approximately $4 million related to our Canadian crude business, which was sold in August 2002. Our total marketed volumes declined period-over-period from approximately 469,000 barrels per day to approximately 276,000 barrels per day due to reduced domestic marketing opportunities and the divestiture of our global liquids business, effective January 1, 2003. The global liquids business sold an average of 107,000 barrels per day in the second quarter of 2002.

Six-Month Periods Ended June 30, 2003 and 2002

NGL reported EBIT of $84 million for the six-month period ended June 30, 2003 compared to $45 million for the same period in 2002. EBIT consists of the following amounts reported by NGL for the periods presented: operating income of $90 million and $54 million, respectively; earnings from unconsolidated investments of $5 million and $7 million, respectively; other items, net of $(10) million and $(11) million, respectively; and discontinued operations of $(1) million and $(5) million, respectively. Upstream operating income increased period-over-period primarily as a result of higher natural gas and natural gas liquids prices, which caused increased processing plant margins at our field plants. Total volumes of liquids produced at our field plants increased six percent period-over-period primarily due to increased production in the highly active drilling area in North Texas. Our straddle plant volumes were much lower period-to-period because of the low fractionation spread, which resulted in our decision to by-pass unprofitable gas or to shut-down plants that are subject to fractionation spread risk.

In our downstream business, volumes available for fractionation declined 19 percent period-to-period as a direct result of the reduced liquids recovery from both our own and from third-party gas processing plants. Additional factors adversely affecting the volumes fractionated include the willingness of some of our competitors to reduce fractionation fees below levels acceptable to us, expiration of some long-term fractionation agreements and customer concerns relating to our liquidity and non-investment grade credit status. In our wholesale marketing operations, profits were higher due to margin increases resulting from the impact of higher commodity prices on our percentage of netback contracts with our refinery services customers. Natural gas liquids marketing results declined from prior period levels as a result of reduced overall market liquidity and

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customer concerns relating to our liquidity and non-investment grade credit status. Downstream operating income for the six months ended June 30, 2003 includes a pre-tax gain of approximately $10 million on the sale of our investment in the Hackberry LNG project. Downstream operating income for the six months ended June 30, 2002 also includes income of approximately $10 million related to our Canadian crude business, which was sold in August 2002. Our marketed volumes declined period-over-period from approximately 539,000 barrels per day to approximately 320,000 barrels per day due to reduced domestic marketing opportunities and the divestiture of our global liquids business, effective January 1, 2003. The global liquids business sold an average of 109,000 barrels per day in the first half of 2002.

NGL Outlook

Recent crude prices have averaged, and are expected to continue to average, near $30 per barrel. Domestic natural gas prices continue to be higher than historic levels, averaging approximately $5.00 per MMBtu. Our upstream volumes under percentage of proceeds and percentage of liquids contracts will continue to benefit from these relatively higher prices. However, liquids production from both our own and third-party natural gas processing plants that are exposed to keep whole contracts will continue to be exposed to depressed fractionation spreads, even at these relatively high commodity prices. As a result, we expect a continued reduction in the natural gas liquids that supply our fractionation, storage and distribution infrastructure. Industry-wide propane inventories remain at historically low levels. We expect that these factors, together with reduced natural gas liquids production and low industry-wide propane inventories, should support propane prices to attract sufficient imports and/or increased domestic liquids production to meet petrochemical feedstock demand and the required accumulation of propane inventory for the 2003-2004 winter heating season.

Drilling rig rates for natural gas throughout our core processing areas in New Mexico, West Texas, North Texas and offshore Louisiana continue to increase, consistent with natural gas prices that have been in the $5.00-6.00 per MMBtu range.

Despite operational challenges caused by our non-investment grade credit ratings status and a lack of market liquidity, NGL was able to meet its contractual obligations in its wholesale marketing business during the first half of 2003. Despite significant competition, customers generally are choosing to renew contracts with us as they reach their current term. While we have not experienced significant turnover in customer contracts as a result of our non-investment grade credit ratings, we have been required to provide collateral or other adequate assurance of our obligations under the renewed contracts.

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Regulated Energy Delivery

	Three Months Ended June 30,					Six Months Ended June 30,
	2003		2002			2003			2002
	(in millions, except operating statistics)
Operating Income	$	35	$	56		$	94		$	96
Earnings from Unconsolidated Investments		—		(1	)		—			(1	)
Other Items, Net		—		(2	)		—			—
Discontinued Operations		—		(8	)		—			37
Cumulative Effect of a Change in Accounting Principle		—		—			(3	)		—
Earnings Before Interest and Taxes	$	35	$	45		$	91		$	132
Operating Statistics:
Electric Sales in kWh
Residential		998		1,206			2,431			2,510
Commercial		1,052		1,081			2,110			2,103
Industrial		1,648		1,676			3,053			3,052
Transportation of Customer-Owned Electricity		601		593			1,150			1,301
Other		88		92			187			185
Total Electric Sales		4,387		4,648			8,931			9,151
Gas Sales in Therms
Residential		35		43			220			196
Commercial		16		17			88			79
Industrial		18		19			41			37
Transportation of Customer-Owned Gas		57		61			122			133
Total Gas Delivered		126		140			471			445
Heating Degree Days—Actual (1)		469		498			3,404			2,995
Heating Degree Days—10 Year Rolling Average		431		431			3,018			3,054
Cooling Degree Days – Actual (2)		198		426			198			426
Cooling Degree Days – 10 Year Rolling Average		364		386			364			386

(1) A Heating Degree Day (“HDD”) represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit. The HDDs for a period of time are computed by adding the HDDs for each day during the period.

(2) A Cooling Degree Day (“CDD”) represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit. The CDDs for a period of time are computed by adding the CDDs for each day during the period.

Three-Month Periods Ended June 30, 2003 and 2002

EBIT for the REG segment was $35 million for the three-month period ended June 30, 2003 compared to $45 million for the same period in 2002. EBIT consists of the following amounts reported by REG for the periods presented: operating income of $35 million and $56 million, respectively; earnings from unconsolidated investments of zero and $(1) million, respectively; other items, net of zero and $(2) million, respectively; and discontinued operations of zero and $(8) million, respectively. Results were negatively impacted in 2003 by cooler than normal spring weather throughout REG’s service territory, which caused decreases in residential and commercial electricity sales volumes. In addition, a favorable resolution of a contingent liability for a billing dispute with a large wholesale electric customer resulted in higher revenues for 2002. Operating expenses for 2003 included lower regulatory asset amortization resulting from the additional regulatory asset amortization that was recorded in late 2002. EBIT for the three months ended June 30, 2002 also includes a loss from discontinued operations of approximately $8 million related to Northern Natural, which was sold in August 2002.

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Six-Month Periods Ended June 30, 2003 and 2002

EBIT for the REG segment was $91 million for the six-month period ended June 30, 2003 compared to $132 million for the same period in 2002. EBIT consists of the following amounts reported by REG for the periods presented: operating income of $94 million and $96 million, respectively; earnings from unconsolidated investments of zero and $(1) million, respectively; other items, net of zero and zero, respectively; discontinued operations of zero and $37 million, respectively; and cumulative effect of change in accounting principle of $(3) million and zero, respectively. Results were negatively impacted in 2003 by cooler than normal spring weather partially offset by colder than normal winter weather, which caused net decreases in residential and commercial electricity sales volumes and increases in residential and commercial gas sales volumes. In 2002, revenues from the sale of electricity were positively affected by the reversal of a contingent liability related to a billing dispute with a large wholesale electric customer. In addition, 2003 revenues attributable to the sale of electricity to residential customers were negatively impacted by a five percent rate reduction effective May 1, 2002. Operating expenses were lower in 2003 due to continued operating efficiency gains, partially offset by increased insurance and general claims expense. In addition, lower regulatory asset amortization in 2003 resulted from the additional regulatory asset amortization that was recorded in late 2002. EBIT for the six months ended June 30, 2002 also includes income from discontinued operations of approximately $37 million related to Northern Natural, which was sold in August 2002.

REG Outlook

Future results of operations for the REG segment may be affected, either positively or negatively, by regulatory actions, general economic conditions, weather, overall economic growth, the demand for power and natural gas in its service area, utilization of competitive alternate service providers by its customers and financing costs. We previously announced an agreement to sell our electric transmission system, conditioned on several matters, including the receipt of required approvals from the SEC under the PUHCA, the Federal Trade Commission, the ICC and the FERC. On February 20, 2003, the FERC voted to defer approval of the transaction and ordered a hearing to establish the allowable transmission rates for Trans-Elect. Under the sale agreement, if the transaction did not close on or before July 7, 2003, either party could terminate the agreement. On July 8, 2003, we exercised our right to terminate the agreement with Trans-Elect. The decision was made to defer for now the consideration of the sale of our transmission assets to allow us to more fully assess developing federal and state transmission policy and to review the value of the sale of these assets consistent with an updated review of other Dynegy corporate initiatives and objectives, including the Refinancing more fully described above. Please read “Liquidity and Capital Resources—Illinois Power Liquidity” for discussion of Illinois Power’s significant leverage and its liquidity position.

Customer Risk Management

	Three Months Ended June 30,							Six Months Ended June 30,
	2003			2002				2003			2002
	(in millions)
Operating Loss	$	(360	)	$	(298	)		$	(322	)	$	(327	)
Earnings (Losses) from Unconsolidated Investments		(9	)		(18	)			2			(15	)
Other Items, Net		(3	)		1				23			(13	)
Discontinued Operations		4			18				(11	)		11
Cumulative Effect of a Change in Accounting Principle		—			—				43			—
Loss Before Interest and Taxes	$	(368	)	$	(297	)	��	$	(265	)	$	(344	)

Three-Month Periods Ended June 30, 2003 and 2002

CRM reported EBIT of $(368) million for the three-month period ended June 30, 2003 compared to $(297) million for the same period in 2002. EBIT consists of the following amounts reported by CRM for the periods

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presented: operating loss of $(360) million and $(298) million, respectively; earnings (losses) from unconsolidated investments of $(9) million and $(18) million, respectively; other items, net, of $(3) million and $1 million, respectively; and discontinued operations of $4 million and $18 million, respectively.

Results in the second quarter of 2003 were adversely affected by the following pre-tax losses: $133 million associated with the settlement of power tolling arrangements with Southern Power; $30 million associated with the settlement of power supply agreements with Kroger; and a $132 million non-cash mark-to-market loss on contracts associated with the Sithe Independence power tolling arrangement. In addition, results include losses associated with capacity payments on remaining tolling arrangements and other costs associated with the on-going exit from the CRM business.

During the three-month period ended June 30, 2002, the CRM segment was actively managed as part of our ongoing strategy and its results included, in part, settlement with third parties of physical power and other trading positions purchased from our GEN segment at an internally determined transfer price. Please see Note 11 to the accompanying unaudited condensed consolidated financial statements for further discussion.

Six-Month Periods Ended June 30, 2003 and 2002

CRM reported EBIT of $(265) million for the six-month period ended June 30, 2003 compared to $(344) million for the same period in 2002. EBIT consists of the following amounts reported by CRM for the periods presented: operating loss of $(322) million and $(327) million respectively; earnings (losses) from unconsolidated investments of $2 million and $(15) million, respectively; other items, net, of $23 million and losses of $(13) million, respectively; discontinued operations of $(11) million and $11 million, respectively; and cumulative effect of change in accounting principle of $43 million and zero, respectively. Results associated with this business benefited primarily from sales of natural gas in storage which had previously been recorded at fair value (see Note 1 to the unaudited condensed consolidated financial statements for additional details) more than offset by the following pre-tax losses: $133 million associated with the settlement of power tolling arrangements with Southern Power; $30 million associated with the settlement of power supply agreements with Kroger; and a $132 million mark-to-market loss on contracts associated with the Sithe Independence power tolling arrangement. In addition, results include losses associated with capacity payments on remaining tolling arrangements and other costs associated with the on-going exit from the CRM business.

During the six-month period ended June 30, 2002, the CRM segment was actively managed as part of our ongoing strategy and its results included, in part, settlement with third parties of physical power and other trading positions purchased from our GEN segment at an internally determined transfer price. Please see Note 11 to the accompanying unaudited condensed consolidated financial statements for further discussion.

CRM Outlook

Our CRM business’ future results of operations will be significantly impacted by our ability to execute our exit strategy. We continue to pursue opportunities to assign or renegotiate the terms of many of our contractual obligations related to this business, including some of our power tolling arrangements. In April 2003, we reached an agreement in principle with Southern Power to terminate three power tolling arrangements among Dynegy, Southern Power and our respective affiliates covering an aggregate of 1,100 MW. Under the terms of the agreement, we paid Southern Power $155 million to terminate two of these arrangements effective May 30, 2003 and the third such arrangement effective October 31, 2003. The terminations resulted in approximately $89 million of collateral being returned to us and eliminated our obligation to make $1.7 billion in payments due to Southern Power over the next 30 years.

If we do not renegotiate or terminate the remaining five power tolling arrangements to which we remain a party, we will be required to pay an aggregate amount of approximately $1.9 billion in capacity payments under the related agreements through 2014. After applying a LIBOR-based discount rate, the total of these capacity

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payments approximates $1.6 billion. Our capacity payments for the remainder of 2003 are $105 million. Even if we do renegotiate or terminate some of these arrangements, we could incur significant expenses relating to any such renegotiation or termination.

In addition, we have posted collateral to support a substantial portion of our obligations in this business, including $32 million at June 30, 2003 posted in connection with our power tolling arrangements. While we have been working with various counterparties to provide mutually acceptable collateral or other adequate assurance under these contracts, we have not reached agreement with Sithe Independence and Sterlington/Quachita Power LLC regarding a mutually acceptable amount of collateral. Although we are current on all contract payments to these counterparties, we have received a notice of default from each such counterparty with regard to collateral. We are continuing to negotiate with both parties. Our average annual capacity payments under these two arrangements approximate $75 million and $63 million, respectively, and the contracts extend through 2014 and 2012, respectively. If these counterparties were successful in pursuit of claims that we defaulted on these contracts, they could declare a termination of these contracts, which would provide for termination payments based on the mark-to-market value of the contracts.

We generally have been successful in satisfying customer collateral requirements and have had few terminations or disputes relating to contracts in this segment. However, we are involved in litigation with some of our former counterparties relating to contract terminations with respect to which we were unable to agree on mutually acceptable collateral or other adequate assurance. There is a risk that we may be unable to agree with other counterparties on mutually acceptable forms and amounts of adequate assurance or other collateral, resulting in additional litigation and related expenses. Our ability to address these and other issues relating to collateral posted for ongoing CRM contracts could affect this business’ future results of operations.

We intend to manage actively our exit from the CRM business with the objective of maximizing the ultimate net cash proceeds received and completing our exit plan in a timely and cost-effective manner. However, our failure to manage this exit successfully would negatively impact the CRM segment’s results of operations.

Cash Flow Disclosures

The following table includes data from the operating section of the unaudited condensed consolidated statements of cash flows and includes cash flows from our discontinued operations, which are disclosed on a net basis in loss on discontinued operations, net of tax, in the unaudited condensed consolidated statements of operations (in millions):

	For the Six Months Ended June 30, 2003
	GEN			NGL			REG		CRM			Other & Eliminations			Consolidated
Operating Cash Flows Before Changes in Working Capital	$	185		$	116		$	85	$	(15	)	$	(155	)	$	216
Changes in Working Capital		(44	)		(78	)		2		387			(43	)		224
Net Cash Provided by (Used in) Operating Activities	$	141		$	38		$	87	$	372		$	(198	)	$	440

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Operating Cash Flow.    Cash flow from operating activities totaled $440 million for the six-month period ended June 30, 2003 compared to $328 million reported in the same 2002 period. Adjustments to net income were greater in the 2002 period, primarily due to a $234 million impairment of goodwill for the communications business related to the adoption of SFAS No. 142 in the first quarter 2002 as previously disclosed, as well as $670 million of impairment and other charges in the first half of 2002. Additional adjustments from the 2002 to 2003 period included the following:

• The deduction for earnings from unconsolidated investments, net of cash distributions, increased by approximately $65 million. The increase results from higher earnings in 2003 versus 2002, as described above, which results in a deduction from operating cash flows;

• Deferred income taxes are a $122 million benefit position for the six months ended June 30, 2003, compared to a benefit of $338 million in the same 2002 period, producing a $216 million decreased adjustment; and

• Risk-management activities produced a $290 million adjustment, compared to an adjustment of $399 million in the 2002 period. Adjustments in 2003 primarily represent mark-to-market losses in excess of net cash realized for settled contracts. Adjustments in 2002 primarily represent net cash realized for settled contracts in excess of mark-to-market gains and losses recognized currently in income.

Changes in working capital had a positive impact on cash flow from operations for the six-month period ended June 30, 2003. The receipt of a $110 million tax refund in March 2003, proceeds of approximately $120 million related to the sale of natural gas inventory in the first quarter 2003 and receivable settlements in our CRM segment due to the continued wind-down of this business contributed to working capital sources for the six-month period ended June 30, 2003. These sources were offset by increased receivable accruals, largely driven by price and volume increases in the GEN segment from period to period, and an increase in prepayments in the NGL segment.

Capital Expenditures and Investing Activities.    Cash used in investing activities during the six-month period ended June 30, 2003 totaled $156 million. Capital spending of $189 million was primarily comprised of $93 million, $68 million and $25 million in the GEN, REG and NGL segments, respectively, primarily representing improvements to the existing asset base. The capital spending for the GEN segment includes approximately $31 million spent on the construction of the Rolling Hills generating facility, with respect to which commercial operation began in June 2003. Proceeds from asset sales primarily include $20 million in proceeds from the sale of SouthStar and $20 million in proceeds from the sale of Hackberry LNG Terminal LLC, offset by $10 million in cash outflows associated with the sale of our European communications business.

Funds used in investing activities in the first six months of 2002 totaled $653 million. Capital expenditures and investments in unconsolidated affiliates of $643 million primarily relate to the construction and improvement of power generation assets and investments associated with technology infrastructure. The business acquisitions cash outflows of $20 million relate to the acquisition of Northern Natural, net of cash acquired. These cash outflows were offset by $10 million in proceeds from asset sales.

Financing Activities.    Cash used in financing activities during the six-month period ended June 30, 2003 totaled $247 million. During the six months ended June 30, 2003, we repaid $128 million, net, under our revolving credit facilities. Long-term debt proceeds, net of issuance costs, for the six months ended June 30, 2003 consisted of $142 million from the delayed issuance of $150 million in Illinois Power 11.5% Mortgage Bonds due 2010 and $159 million from the Term A Loan drawn in connection with the April 2, 2003 credit facility restructuring. Repayments of long-term debt totaled $425 million for the six months ended June 30, 2003. Please read “—Liquidity and Capital Resources—Liquidity Uses” for further discussion.

Net cash provided by financing activities was $519 million during the first six months of 2002. We received $205 million in cash proceeds related to ChevronTexaco’s January 2002 purchase of approximately 10.4 million

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shares of Class B common stock pursuant to its preemptive rights under our shareholder agreement. Capital stock proceeds also include $21 million of cash inflows associated with cash received from senior management associated with a December 2001 private placement of shares of our Class A common stock. During the six-month period ended June 30, 2002, dividends of $40 million were paid to the holders of Class A common stock and $15 million was paid to the holder of Class B common stock. In March 2002, Illinova consummated a tender offer pursuant to which it paid $28 million in cash for approximately 73 percent of the then-outstanding shares of Illinois Power’s preferred stock. Net long-term debt proceeds consisted primarily of the February 2002 issuance by DHI of 8.75% senior notes due February 2012 and proceeds from borrowings incurred by ABG Gas Supply. Repayments of long-term borrowings consisted of $44 million in transitional funding notes relating to Illinois Power, $90 million relating to the April 2002 purchase of Northern Natural’s senior unsecured notes due 2005, $54 million in June 2002 principal payments related to the restructuring of Black Thunder from Minority Interest to Long-Term Debt and $28 million in repayments by ABG Gas Supply. Net proceeds from short-term financing consisted of a $245 million cash advance for the anticipated sale of certain U.K. gas storage assets. Finally, we repaid commercial paper and borrowings under revolving credit lines for DHI and Illinois Power of $293 million and borrowed $60 million under IP’s term loan.

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RISK-MANAGEMENT DISCLOSURES

The following table provides a reconciliation of the risk-management data on the unaudited condensed consolidated balance sheets, statements of operations and statements of cash flows (in millions):

	As of and for the Six Months Ended June 30, 2003
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2003	$	363
Risk-management losses recognized through the income statement in the period, net		(217	)
Cash received related to risk-management contracts settled in the period, net (1)		(101	)
Changes in fair value as a result of a change in valuation technique (2)		—
Non-cash adjustments and other (3)		(66	)
Fair value of portfolio at June 30, 2003	$	(21	)
Income Statement Reconciliation
Risk-management losses recognized through the income statement in the period, net	$	(217	)
Physical business recognized through the income statement in the period, net		82
Non-cash adjustments and other (4)		3
Net recognized operating loss (5)	$	(132	)
Cash Flow Statement
Cash received related to risk-management contracts settled in the period, net (1)	$	101
Estimated cash received related to physical business settled in the period, net		82
Timing and other, net (6)		(25	)
Cash received during the period	$	158
Risk-Management cash flow adjustment for the six-month period ended June 30, 2003 (7)	$	290

(1) This amount includes cash settlements of hedging instruments, emission allowances and other non-trading amounts in addition to the cash settlement of trading contracts.

(2) Our modeling methodology has been consistently applied.

(3) This amount primarily consists of approximately $97 million of risk-management assets that were removed from the risk-management accounts at January 1, 2003 in conjunction with the adoption of certain provisions of EITF Issue 02-03. This amount also includes changes in value and cash settlements associated with foreign currency and interest rate hedges.

(4) This amount consists primarily of changes in value of interest rate hedges.

(5) This amount consists primarily of GEN and CRM operating income before the deduction of Depreciation and Amortization and General and Administrative Expenses.

(6) This amount represents cash received for the settlement of fuel hedges and cash payments associated with interest rate hedges.

(7) This amount is calculated as “Cash received during the period” less “Net recognized operating loss.”

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Risk-Management Asset and Liability Disclosures.    The following tables depict the mark-to-market value and cash flow components of our net risk-management assets and liabilities at June 30, 2003 and December 31, 2002:

Mark-to-Market Value of Net Risk-Management Assets (1)

	Total			2003(2)			2004			2005			2006			2007			Thereafter
	(in millions)
June 30, 2003	$	(63	)	$	96		$	(12	)	$	(22	)	$	(34	)	$	(35	)	$	(56	)
December 31, 2002		363			250			24			52			27			(24	)		34
Increase (Decrease)	$	(426	)	$	(154	)	$	(36	)	$	(74	)	$	(61	)	$	(11	)	$	(90	)

(1) The table reflects the fair value of our risk-management asset position, which considers time value, credit, price and other reserves necessary to determine fair value. These amounts exclude the fair value associated with certain derivative instruments designated as hedges. The net risk-management liabilities at June 30, 2003 of $21 million on the unaudited condensed consolidated balance sheets include the $63 million herein as well as hedging instruments. Cash flows have been segregated between periods based on the delivery date required in the individual contracts.

(2) Amounts represent July 1 to December 31, 2003 values in the June 30, 2003 row and January 1 to December 31, 2003 values in the December 31, 2002 row.

The decreases in the Net Risk-Management Assets and Liabilities were impacted most significantly by the adoption of EITF Issue 02-03 (which resulted in a decrease of approximately $97 million), the settlement of the U.K. marketing and trading portfolio (which resulted in a decrease of approximately $94 million) and the mark-to-market loss on contracts associated with the Sithe Independence power tolling arrangement (which resulted in a decrease of approximately $132 million).

Cash Flow Components of Net Risk-Management Asset

	Six Months Ended June 30, 2003		Six Months Ended December 31, 2003		Total 2003			2004			2005			2006			2007			Thereafter
	(in millions)
June 30, 2003 (1)	$	101	$	101	$	202		$	(8	)	$	(22	)	$	(36	)	$	(40	)	$	(66	)
December 31, 2002						259			43			57			36			(15	)		599
Increase (Decrease)					$	(57	)(3)	$	(51	)	$	(79	)	$	(72	)	$	(25	)	$	(665	)(2)

(1) The cash flow values for 2003 reflect realized cash flows for the six months ended June 30, 2003 and anticipated undiscounted cash inflows and outflows by contract based on the tenor of individual contract position for the remaining periods. These anticipated undiscounted cash flows have not been adjusted for counterparty credit or other reserves. These amounts exclude the cash flows associated with certain derivative instruments designated as hedges.

(2) Significant decrease is primarily the result of the implementation of EITF Issue 02-03 on January 1, 2003. This required all but one of our power tolling arrangements, some of which were previously accounted for on a mark-to-market basis, to be recorded on an accrual basis. Therefore, the cash flows associated with the power tolling arrangements which are accounted for on an accrual basis have been excluded from the amounts reported as of June 30, 2003.

(3) This amount includes approximately $97 million of risk-management assets that were removed from the risk-management accounts at January 1, 2003 in conjunction with the adoption of certain provisions of EITF Issue 02-03.

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The following table provides an assessment of net contract values by year based on our valuation methodology.

Net Fair Value of Risk-Management Portfolio

	Total			2003		2004			2005			2006			2007			Thereafter
	(in millions)
Market Quotations (1)	$	28		$	96	$	(12	)	$	(2	)	$	(26	)	$	(22	)	$	(6	)
Prices Based on Models (2)		(91	)		—		—			(20	)		(8	)		(13	)		(50	)
Total	$	(63	)	$	96	$	(12	)	$	(22	)	$	(34	)	$	(35	)	$	(56	)

(1) Prices obtained from actively traded, liquid markets for commodities other than natural gas positions. All natural gas positions for all periods are contained in this line based on available market quotations.

(2) See discussion of our use of long-term models in “Critical Accounting Policies” beginning on page 74 in the Form 10-K/A.

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

This quarterly report includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements.” All statements included or incorporated by reference in this quarterly report, other than statements of historical fact, that address activities, events or developments that we or our management expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements represent our reasonable judgment on the future based on various factors and using numerous assumptions and are subject to known and unknown risks, uncertainties and other factors that could cause our actual results and financial position to differ materially from those contemplated by the statements. Important factors that could cause a material difference in the actual results from the forward-looking statements are set forth elsewhere in this quarterly report. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “project,” “forecast,” “may,” “will,” “should,” “expect” and other words of similar meaning. In particular, these include, but are not limited to, statements relating to the following:

• projected operating or financial results;

• expectations regarding capital expenditures, debt service and other payments;

• our beliefs and assumptions relating to our liquidity position, including our ability to satisfy or refinance our significant debt maturities and other obligations as they come due;

• our ability to address our substantial leverage;

• our ability to compete effectively for market share with industry participants;

• beliefs about the outcome of legal and administrative proceedings, including matters involving the western power and natural gas markets, shareholder claims and environmental matters as well as the investigations primarily relating to Project Alpha and our past trading practices; and

• our ability to complete our exit from the CRM business and the costs associated with this exit.

Any or all of our forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors including, among others:

• the timing and extent of changes in commodity prices for energy, particularly power, natural gas and the spark spread between power and natural gas prices, and natural gas liquids;

• the effects of competition in our asset-based business lines;

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• the condition of the capital markets generally, which will be affected by interest rates, foreign currency fluctuations and general economic conditions, and our financial condition, including our ability to satisfy our significant debt maturities;

• developments in the western power and natural gas markets, including, but not limited to, governmental intervention, deterioration in the financial condition of our counterparties, default on receivables due and adverse results in current or future investigations or litigation;

• the effectiveness of our risk-management policies and procedures and the ability of our counterparties to satisfy their financial commitments;

• the liquidity and competitiveness of wholesale trading markets for energy commodities, particularly natural gas, electricity and natural gas liquids;

• operational factors affecting the start up or ongoing commercial operations of our power generation, natural gas and natural gas liquids and regulated energy delivery facilities, including catastrophic weather-related damage, regulatory approvals, permit issues, unscheduled outages or repairs, unanticipated changes in fuel costs or availability of fuel emission credits, the unavailability of gas transportation and the unavailability of electric transmission service or workforce issues;

• increased interest expense and the other effects of our restructured credit facilities and our recently issued second priority senior secured notes and convertible subordinated debentures, including the security arrangements and restrictive covenants contained therein;

• counterparties’ collateral demands and other factors affecting our liquidity position and financial condition;

• our ability to manage capital expenditures and costs (including general and administrative expenses) tightly and to generate sustainable earnings and cash flow from our assets and businesses;

• the direct or indirect effects on our business of any further downgrades in our credit ratings (or actions we may take in response to changing credit ratings criteria), including refusal by counterparties to enter into transactions with us and our inability to obtain credit or capital in amounts or on terms that are considered favorable;

• the costs and other effects of legal and administrative proceedings, settlements, investigations and claims, including legal proceedings related to the western power and natural gas markets, shareholder claims, claims arising out of the CRM business and environmental liabilities that may not be covered by indemnity or insurance, as well as the FERC, U.S. Attorney and other similar investigations primarily surrounding Project Alpha and our past trading practices;

• other North American regulatory or legislative developments that affect the regulation of the electric utility industry, the demand and pricing for energy generally, increase in the environmental compliance cost for our facilities or that impose liabilities on the owners of such facilities; and

• general political conditions and developments in the United States and in foreign countries whose affairs affect our lines of business, particularly commodity prices, including any extended period of war or conflict.

In addition, there may be other factors that could cause our actual results to be materially different from the results referenced in the forward-looking statements. Many of these factors will be important in determining our actual future results. Consequently, no forward-looking statement can be guaranteed. Our actual future results may vary materially from those expressed or implied in any forward-looking statements.

All forward-looking statements contained in this quarterly report are qualified in their entirety by this cautionary statement. Forward-looking statements speak only as of the date they are made, and we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this quarterly report except as otherwise required by applicable law.

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RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1 to the unaudited condensed consolidated financial statements for a discussion of recently issued accounting pronouncements affecting us. Specifically, we adopted the net presentation provisions of EITF Issue 02-03 in the third quarter 2002, and we adopted the provision within EITF Issue 02-03 that rescinds EITF Issue 98-10 effective January 1, 2003. We also adopted SFAS No. 143 effective January 1, 2003.

CRITICAL ACCOUNTING POLICIES

Please read “Critical Accounting Policies” beginning on page 74 of the Form 10-K/A for a complete description of our critical accounting policies, with respect to which there have been no material changes since the filing of the Form 10-K/A.

Item 3—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Value at Risk (“VaR”).    The following table sets forth the aggregate daily VaR of the mark-to-market portion of Dynegy’s risk-management portfolio primarily associated with the GEN and CRM segments.

Daily and Average VaR for Risk-Management Portfolio

	June 30, 2003		December 31, 2002
	(in millions)
One Day VaR—95% Confidence Level	$	6	$	8
One Day VaR—99% Confidence Level	$	9	$	11
Average VaR for the Year-to-Date Period—95% Confidence Level (1)	$	7		N/A

(1) Average VaR is not available for 2002 due to the restatement of historical results.

Credit Risk.    The following table represents our credit exposure at June 30, 2003 associated with the mark-to-market portion of our risk-management portfolio, as well as our remaining power tolling arrangements, netted by counterparty (in millions):

Credit Exposure Summary

	Investment Grade Quality		Non-Investment Grade Quality		Total
Type of Business:
Financial Institutions	$	194	$	—	$	194
Commercial/Industrial/End Users		98		109		207
Utility and Power Generators		35		—		35
Oil and Gas Producers		64		3		67
Other		1		—		1
Total	$	392	$	112	$	504

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Interest Rate Risk.    The following table sets forth the daily and average VaR associated with the interest rate component of the risk-management portfolio. We seek to manage our interest rate exposure through application of various hedging strategies. Hedging instruments executed to mitigate such interest rate exposure in the risk-management portfolio are included in the VaR as of June 30, 2003 and December 31, 2002 and are reflected in the table below.

Daily and Average VaR on Interest Component of Risk-Management Portfolio

	June 30, 2003		December 31, 2002
	(in millions)
One Day VaR—95% Confidence Level	$	0.7	$	2.5
Average VaR for the Year-to-Date Period—95% Confidence Level (1)	$	1.8		N/A

(1) Average VaR is not available for 2002 due to the restatement of historical results.

The decrease in One Day VaR is due to the wind down of the CRM business and the resulting decrease in the size of our risk-management portfolio.

In addition to the risk-management portfolio, we are exposed to fluctuating interest rates related to other variable rate financial obligations. Based on sensitivity analysis as of June 30, 2003, it is estimated that a one percentage point interest rate movement in the average market interest rates (either higher or (lower)) over the twelve months ended June 30, 2004 would (decrease) increase income before taxes by approximately $16 million. Hedging instruments executed to mitigate such interest rate exposure are included in the sensitivity analysis. The sensitivity analysis does not include any impact related to our recent long-term refinancing and restructuring plan described elsewhere in this report.

Foreign Currency Exchange Rate Risk.    The following table sets forth the daily and average foreign currency exchange VaR. Hedging instruments executed to mitigate such foreign currency exchange exposure are included in the VaR as of June 30, 2003 and December 31, 2002 and are reflected in the table below.

Daily and Average Foreign Currency Exchange VaR

	June 30, 2003		December 31, 2002
	(in millions)
One Day VaR—95% Confidence Level	$	0.2	$	0.4
Average VaR for the Year-to-Date Period—95% Confidence Level	$	0.4	$	2.9

The decrease in One Day and Average VaR is due to the significant reduction in foreign activities in the first half of 2003.

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Derivative Contracts.    The absolute notional financial contract amounts associated with our commodity risk-management, interest rate and foreign currency exchange contracts were as follows at June 30, 2003 and December 31, 2002, respectively:

Absolute Notional Contract Amounts

	June 30, 2003		December 31, 2002
Natural Gas (Trillion Cubic Feet)		4.196		7.910
Electricity (Million Megawatt Hours)		12.751		64.563
Natural Gas Liquids (Million Barrels)		0.195		0.265
Fair Value Hedge Interest Rate Swaps (In Millions of U.S. Dollars)	$	25	$	601
Fixed Interest Rate Received on Swaps (Percent)		5.706		5.616
Cash Flow Hedge Interest Rate Swaps (In Millions of U.S. Dollars)	$	500	$	1,566
Fixed Interest Rate Paid on Swaps (Percent)		3.458		2.824
Interest Rate Risk-Management Contract (In Millions of U.S. Dollars)	$	259	$	1,001
Fixed Interest Rate Paid (Percent)		6.690		5.530
U.K. Pound Sterling (In Millions of U.S. Dollars)	$	—	$	198
Average U.K. Pound Sterling Contract Rate (In U.S. Dollars)	$	—	$	1.574
Euro Dollars (In Millions of U.S. Dollars)	$	—	$	5
Average Euro Contract Rate (In U.S. Dollars)	$	—	$	1.212
Canadian Dollar (In Millions of U.S. Dollars)	$	—	$	523
Average Canadian Dollar Contract Rate (In U.S. Dollars)	$	—	$	0.7140

Item 4—CONTROLS AND PROCEDURES

Effective as of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). This evaluation included consideration of our establishment of a disclosure committee and the various processes that were carried out under the direction of this committee in an effort to ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified by the SEC. This evaluation also included consideration of our internal controls and procedures for the preparation of our consolidated financial statements. While we have previously identified internal control weaknesses, which are discussed below, our evaluation indicated that these weaknesses did not impair the effectiveness of our overall disclosure controls and procedures.

Reference is made to “Item 14. Controls and Procedures” beginning on page 84 of the Form 10-K/A. In that section, we indicated that in evaluating our internal controls in connection with the preparation of the Form 10-K/A we identified two reportable conditions that were considered to be “material weaknesses” under applicable accounting standards. The first such condition related to the fact that inappropriate persons within our organization had access to record or revise entries in our accounting software system. The second such condition related to the process whereby accrued estimates of volumes bought, sold, transported and stored in our natural gas marketing business were reconciled to the actual volumes. We also identified the measures we had taken toward remedying these conditions, as well as other initiatives being implemented with respect to our system of internal controls generally.

During our most recent evaluation undertaken in connection with the preparation of this quarterly report, we did not discover any additional reportable conditions with respect to our internal controls. Regarding the previously identified access condition, we are continuing to develop a technical solution to ensure that such access is limited to appropriate personnel, and we began the implementation of this solution in the second quarter 2003. In the interim, in addition to the strengthening of our monitoring policy as described in the Form 10-K/A, we have modified the security settings where appropriate in an effort to ensure that unauthorized individuals are prohibited from recording or revising entries.

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DYNEGY INC.

PART II. OTHER INFORMATION

Item 1—LEGAL PROCEEDINGS

See Note 9 to the accompanying unaudited condensed consolidated financial statements for discussion of the material legal proceedings to which we are a party.

Item 4—SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The 2003 annual meeting of Dynegy’s shareholders was held on June 5, 2003. The purpose of the annual meeting was to consider and vote upon the following proposals:

1. To elect ten Class A common stock directors and two Class B common stock directors to serve until the 2004 annual meeting of shareholders;

2. To ratify the appointment of PricewaterhouseCoopers LLP as Dynegy’s independent auditors for the fiscal year ending December 31, 2003; and

3. To consider and act upon the two shareholder proposals described below.

At the annual meeting, each of the following individuals was re-elected to serve as a director of Dynegy: Daniel L. Dienstbier, Charles E. Bayless, David W. Biegler, Linda Walker Bynoe, Barry J. Galt, Patricia A. Hammick, Robert C. Oelkers, Joe J. Stewart, William L. Trubeck, Bruce A. Williamson, Raymond I. Wilcox and John S. Watson. The votes cast for each nominee and the votes withheld were as follows:

Class A Directors

		FOR	WITHHELD
1.	Daniel L. Dienstbier	244,929,498	8,107,978
2.	Charles E. Bayless	243,280,783	9,827,505
3.	David W. Biegler	244,781,124	8,229,902
4.	Linda Walker Bynoe	242,701,854	10,323,534
5.	Barry J. Galt	242,683,761	10,334,788
6.	Patricia A. Hammick	243,453,858	9,596,667
7.	Robert C. Oelkers	242,842,427	10,177,282
8.	Joe J. Stewart	245,010,591	7,999,651
9.	William L. Trubeck	243,449,128	9,563,281
10.	Bruce A. Williamson	244,934,628	8,084,989
Class B Directors
		FOR	WITHHELD
1.	Raymond I. Wilcox	96,891,014	-0-
2.	John S. Watson	96,891,014	-0-

The following votes were cast with respect to the ratification of the selection of PricewaterhouseCoopers LLP as independent auditors of the Company for the fiscal year ended December 31, 2003. There were no broker non-votes.

FOR	AGAINST	ABSTAIN
341,606,744	5,787,292	2,528,301

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The following votes were cast with respect to the shareholder proposal that our Board of Directors adopt a policy stating that the public accounting firm retained by Dynegy to provide audit services, or any affiliated company, should not also be retained to provide any management consulting services to Dynegy. There were 151,728,717 broker non-votes.

FOR	AGAINST	ABSTAIN
25,023,540	183,915,970	4,218,887

The following votes were cast with respect to the shareholder proposal that the Board of Directors adopt an executive compensation policy providing that all future stock option grants to senior executives be performance-based. There were 151,728,706 broker non-votes.

FOR	AGAINST	ABSTAIN
25,212,263	183,638,473	4,307,672

Item 6—EXHIBITS AND REPORTS ON FORM 8-K

(a)    The following documents are included as exhibits to this Form 10-Q:

4.1	Statement of Resolution Establishing Series of Series C Convertible Preferred Stock of Dynegy Inc.
4.2	Exchange and Registration Rights Agreement (Preferred Stock) dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc.
4.3	Exchange and Registration Rights Agreement (Notes) dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc.
4.4	Amended and Restated Registration Rights Agreement (Common Stock) dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc.
4.5	Amended and Restated Shareholder Agreement dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc.
4.6	Indenture dated August 11, 2003 between Dynegy Inc. and Wilmington Trust Company, as trustee.
4.7	Junior Unsecured Subordinated Note due 2016 in the principal amount of $225,000,000 issued on August 11, 2003 by Dynegy Inc. to Chevron U.S.A. Inc.
4.8	Indenture dated as of August 11, 2003 among Dynegy Holdings Inc., the guarantors named therein, Wilmington Trust Company, as trustee, and Wells Fargo Bank Minnesota, N.A., as collateral trustee, including the form of promissory note for each series of notes issuable pursuant to the Indenture.
4.9	Indenture dated August 11, 2003 between Dynegy Inc., Dynegy Holdings Inc. and Wilmington Trust Company, as trustee, including the form of debenture issuable pursuant to the Indenture.
4.10	Registration Rights Agreement dated August 11, 2003 among Dynegy Inc., Dynegy Holdings Inc. and the initial purchasers named therein.
4.11	First Supplemental Indenture dated July 25, 2003 between Dynegy Holdings Inc. and Wilmington Trust Company, as trustee (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on July 28, 2003, File No. 1-15659).
4.12	Eight Supplemental Indenture dated July 25, 2003 between Dynegy Holdings Inc. and Wilmington Trust Company, as trustee (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Dynegy Inc. filed on July 28, 2003, File No. 1-15659).
10.1	Dynegy Inc. Deferred Compensation Plan for Certain Directors.

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10.2	Credit Agreement, dated as of April 1, 2003, among Dynegy Holdings Inc., as borrower, Dynegy Inc., as parent guarantor, various subsidiary guarantors and the lenders party thereto (incorporated by reference to Exhibit 10.31 to Amendment No. 1 to the Annual Report on Form 10-K for the Year Ended December 31, 2002 of Dynegy Inc., File No. 1-15659).
10.3	Third Amendment to the Loan Documents dated as of July 15, 2003 among Dynegy Holdings Inc., as borrower, Dynegy Inc., as parent guarantor, various subsidiary guarantors and the lenders party thereto, including the Lender Consent dated August 1, 2003.
10.4	Series B Preferred Stock Exchange Agreement dated as of July 28, 2003 between Dynegy Inc. and Chevron U.S.A. Inc.
10.5	Indemnity Agreement dated August 11, 2003 among Dynegy Inc., Dynegy Holdings Inc. and Chevron U.S.A. Inc.
10.6	Intercreditor Agreement dated August 11, 2003 among Dynegy Holdings Inc., various grantors named therein, Wilmington Trust Company, as corporate trustee, John M. Beeson, Jr., as individual trustee, Bank One, NA, as collateral agent, and Wells Fargo Bank Minnesota, N.A., as collateral trustee.
10.7	Second Lien Shared Security Agreement dated August 11, 2003 among Dynegy Holdings Inc., various grantors named therein and Wells Fargo Bank Minnesota, N.A., as collateral trustee.
10.8	Second Lien Non-Shared Security Agreement dated August 11, 2003 among Dynegy Inc., various grantors named therein and Wells Fargo Bank Minnesota, N.A., as collateral trustee.
10.9	Purchase Agreement dated August 1, 2003 among Dynegy Inc., Dynegy Holdings Inc. and the initial purchasers named therein.
10.10	Purchase Agreement dated August 1, 2003 among Dynegy Holdings Inc., the guarantors named therein and the initial purchasers named therein.
31.1	Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, or otherwise subject to the liability of Section 18 of the Exchange Act and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act.

(b) Reports on Form 8-K of Dynegy Inc. filed during the second quarter 2003:

1. We filed a Current Report on Form 8-K on April 2, 2003. Items 5, 7 and 9 were reported and no financial statements were filed.

2. We filed a Current Report on Form 8-K on April 18, 2003. Items 5 and 7 were reported and no financial statements were filed.

3. We filed a Current Report on Form 8-K on April 29, 2003. Items 7 and 9 were reported and no financial statements were filed.

4. We filed a Current Report on Form 8-K on May 2, 2003. Items 5 and 7 were reported and no financial statements were filed.

5. We filed a Current Report on Form 8-K on May 27, 2003. Items 5 and 7 were reported and no financial statements were filed.

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DYNEGY INC.

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.

	DYNEGY INC.
Date: August 14, 2003	By:	/s/    NICK J. CARUSO
		Nick J. Caruso Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)

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