Edgar Filing: DYNEGY INC /IL/

Amendment No. 1 to Form 10-Q for the period ended 09/30/2004

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

AMENDMENT NO.1

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

For the quarterly period ended September 30, 2004

¨	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. Yes x No ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes x 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, 283,135,636 shares outstanding as of November 8, 2004; Class B common stock, no par value per share, 96,891,014 shares outstanding as of November 8, 2004.

DYNEGY INC.

TABLE OF CONTENTS


		Page
PART I. FINANCIAL INFORMATION

Item 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:

Condensed Consolidated Balance Sheets (Restated):
September 30, 2004 and December 31, 2003		4

Condensed Consolidated Statements of Operations:
For the three and nine months ended September 30, 2004 and 2003		5

Condensed Consolidated Statements of Cash Flows:
For the nine months ended September 30, 2004 and 2003		6

Condensed Consolidated Statements of Comprehensive Income (Loss):
For the three and nine months ended September 30, 2004 and 2003		7

Notes to Condensed Consolidated Financial Statements		8

Item 4. CONTROLS AND PROCEDURES		47

PART II. OTHER INFORMATION

Item 6. EXHIBITS		49

Introductory Note

Dynegy Inc. is filing this Amendment No. 1 on Form 10-Q/A (“Amendment No. 1”) to reflect the effect of a $7 million balance sheet reclassification on our historical unaudited condensed consolidated financial statements and related information, as reported in our Quarterly Report on Form 10-Q for the period ended September 30, 2004, which was originally filed on November 15, 2004 (the “Original Filing”). This item is discussed in more detail in the Introductory Note to the accompanying unaudited condensed consolidated financial statements beginning on page 8. Revised financial information for the periods presented reflecting this reclassification was previously included in our Annual Report on Form 10-K for the year December 31, 2003, which was most recently amended by Amendment No. 2 thereto filed with the SEC on January 18, 2005 (the “Form 10-K/A”). The restated financial and other information included in this Amendment No. 1 should be read together with the Form 10-K/A. The following Items of the Original Filing are amended by this Amendment No. 1:

Item

1. Condensed Consolidated Financial Statements

Item 4. Controls and Procedures

Item

6. Exhibits and Reports on Form 8-K

Unaffected items have not been repeated in this Amendment No. 1.

PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS AMENDMENT NO. 1, INCLUDING THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND THE NOTES THERETO, DOES NOT REFLECT EVENTS OCCURRING AFTER THE DATE OF THE ORIGINAL FILING. SUCH EVENTS INCLUDE, AMONG OTHERS, THE EVENTS DESCRIBED IN OUR CURRENT REPORTS ON FORM 8-K. FOR A DESCRIPTION OF THESE EVENTS, PLEASE READ OUR EXCHANGE ACT REPORTS FILED SINCE NOVEMBER 15, 2004, INCLUDING OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO.

DEFINITIONS

As used in this Form 10-Q, the abbreviations listed below have the following meanings:


ARO		Asset retirement obligation
Bbtu/d		Billions of British thermal units 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
CPUC		California Public Utilities Commission
CRM		Our customer risk management business segment
CUSA		Chevron U.S.A. Inc., a wholly owned subsidiary of ChevronTexaco
$/Bbl		Dollars per barrel
$/Gal		Dollars per gallon
DGC		Dynegy Global Communications
DHI		Dynegy Holdings Inc., our primary financing subsidiary
DMG		Dynegy Midwest Generation, Inc.
DMS		Dynegy Midstream Services
DPM		Dynegy Power Marketing Inc.
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 8-K		Our Current Report on Form 8-K filed on September 22, 2004
Form 10-K		Our Annual Report on Form 10-K for the year ended December 31, 2003, filed on February 27, 2004, as amended by Amendment No. 1 on Form 10-K/A filed on July 20, 2004
Form 10-K/A		Amendment No. 2 to our Annual Report on Form 10-K for the year ended December 31, 2003, filed on January 18, 2005
Form 10-Q/A		Amendment No. 1 to our Form 10-Q for the quarter ended September 30, 2004
GAAP		Accounting principles generally accepted in the United States of America
GEN		Our power generation business segment
ICC		Illinois Commerce Commission
KWH		Kilowatt hours
kW-yr		Kilowatts per year
LIBOR		The London Interbank Offered Rate
LNG		Liquefied natural gas
MBbls/d		Thousands of barrels per day
MISO		Midwest Independent Transmission System Operator, Inc.
MMBtu		Millions of British thermal units
MMCFD		Million cubic feet per day
MW		Megawatt
MWh		Megawatt hour
NGL		Our natural gas liquids business segment
NOV		Notice of Violation
NSPS		New Source Performance Standard
Original Filing		Our Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, filed on November 15, 2004
PGA		Purchase Gas Adjustment
PPO		Power Purchase Option
PRB		Powder River Basin
PSD		Prevention of Significant Deterioration
REG		Our regulated energy delivery business segment
RTO		Regional Transmission Organization
SEC		U.S. Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
SPE		Special Purpose Entity
VaR		Value at Risk
VIE		Variable Interest Entity
WEN		Our former wholesale energy business segment

DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)

See Explanatory Note


	September 30, 2004			December 31, 2003
	(Restated)			(Restated)
ASSETS
Current Assets
Cash and cash equivalents	$	926		$	477
Restricted cash		—			19
Accounts receivable, net of allowance for doubtful accounts of $161 and $184, respectively		698			1,010
Accounts receivable, affiliates		19			25
Inventory		260			279
Assets from risk-management activities		797			818
Prepayments and other current assets		463			402

Total Current Assets		3,163			3,030

Property, Plant and Equipment		7,774			9,867
Accumulated depreciation		(1,626	)		(1,664	)

Property, Plant and Equipment, Net		6,148			8,203
Other Assets
Unconsolidated investments		459			612
Assets from risk-management activities		634			629
Goodwill		15			15
Other long-term assets		312			472

Total Assets	$	10,731		$	12,961

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	553		$	664
Accounts payable, affiliates		84			74
Accrued liabilities and other current liabilities		510			669
Liabilities from risk-management activities		879			838
Notes payable and current portion of long-term debt		24			245
Current portion of long-term debt to affiliates		125			86

Total Current Liabilities		2,175			2,576

Long-term debt		4,151			5,124
Long-term debt to affiliates		200			769

Long-Term Debt		4,351			5,893
Other Liabilities
Liabilities from risk-management activities		718			746
Deferred income taxes		526			524
Other long-term liabilities		355			743

Total Liabilities		8,125			10,482

Minority Interest		108			121
Commitments and Contingencies (Note 9)
Redeemable Preferred Securities, redemption value of $400 at September 30, 2004 and $411 at December 31, 2003		400			411
Stockholders’ Equity
Class A Common Stock, no par value, 900,000,000 shares authorized at September 30, 2004 and December 31, 2003; 284,699,441 and 280,350,169 shares issued and outstanding at September 30, 2004 and December 31, 2003, respectively		2,858			2,848
Class B Common Stock, no par value, 360,000,000 shares authorized at September 30, 2004 and December 31, 2003; 96,891,014 shares issued and outstanding at September 30, 2004 and December 31, 2003		1,006			1,006
Additional paid-in capital		47			41
Subscriptions receivable		(8	)		(8	)
Accumulated other comprehensive loss, net of tax		(24	)		(20	)
Accumulated deficit		(1,713	)		(1,852	)
Treasury stock, at cost, 1,679,183 shares at September 30, 2004 and December 31, 2003		(68	)		(68	)

Total Stockholders’ Equity		2,098			1,947

Total Liabilities and Stockholders’ Equity	$	10,731		$	12,961

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

See Explanatory Note


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Revenues	$	1,650		$	1,385		$	4,747		$	4,331
Cost of sales, exclusive of depreciation shown separately below		(1,327	)		(1,095	)		(3,803	)		(3,822	)
Depreciation and amortization expense		(79	)		(109	)		(249	)		(340	)
Impairment and other charges		(2	)		(1	)		(83	)		6
Gain (loss) on sale of assets, net		(24	)		—			14			15
General and administrative expenses		(79	)		(79	)		(247	)		(276	)

Operating income (loss)		139			101			379			(86	)
Earnings from unconsolidated investments		102			51			194			142
Interest expense		(125	)		(145	)		(402	)		(364	)
Other income and expense, net		3			2			10			13
Minority interest income (expense)		(9	)		(2	)		(19	)		7
Accumulated distributions associated with trust preferred securities		—			—			—			(8	)

Income (loss) from continuing operations before income taxes		110			7			162			(296	)
Income tax benefit (expense) (Note 12)		(30	)		(3	)		1			109

Income (loss) from continuing operations		80			4			163			(187	)
Income (loss) from discontinued operations, net of taxes (Notes 2 and 12)		(2	)		1			(7	)		(6	)

Income (loss) before cumulative effect of change in accounting principles		78			5			156			(193	)
Cumulative effect of change in accounting principles, net of taxes (Note 1)		—			—			—			55

Net income (loss)		78			5			156			(138	)
Less: preferred stock dividends (gain)		6			(1,183	)		17			(1,018	)

Net income applicable to common stockholders	$	72		$	1,188		$	139		$	880

Earnings Per Share (Note 8):
Basic earnings per share:
Income from continuing operations	$	0.20		$	3.17		$	0.39		$	2.23
Income (loss) from discontinued operations		(0.01	)		0.00			(0.02	)		(0.02	)
Cumulative effect of change in accounting principles		—			—			—			0.15

Basic earnings per share	$	0.19		$	3.17		$	0.37		$	2.36

Diluted earnings per share:
Income from continuing operations	$	0.16		$	2.65		$	0.33		$	2.10
Income (loss) from discontinued operations		0.00			0.00			(0.01	)		(0.02	)
Cumulative effect of change in accounting principles		—			—			—			0.13

Diluted earnings per share	$	0.16		$	2.65		$	0.32		$	2.21

Basic shares outstanding		379			375			378			373
Diluted shares outstanding		504			464			503			397

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

See Explanatory Note


	Nine Months Ended September 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	156		$	(138	)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization		279			399
Impairment and other charges		83			—
Earnings from unconsolidated investments, net of cash distributions		(82	)		(26	)
Risk-management activities		(24	)		378
Gain on sale of assets, net		(14	)		(45	)
Deferred income taxes		27			(119	)
Cumulative effect of change in accounting principles (Note 1)		—			(55	)
Liability associated with gas transportation contracts (Note 2)		(148	)		—
Other		8			33
Changes in working capital:
Accounts receivable		150			1,704
Inventory		(70	)		78
Prepayments and other assets		(125	)		817
Accounts payable and accrued liabilities		(123	)		(2,043	)
Changes in non-current assets		(17	)		(22	)
Changes in non-current liabilities		20			(27	)

Net cash provided by operating activities		120			934

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(221	)		(259	)
Proceeds from asset sales, net		527			57

Net cash provided by (used in) investing activities		306			(202	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from long-term borrowings		588			1,909
Repayments of long-term borrowings		(520	)		(2,352	)
Net cash flow from commercial paper and revolving lines of credit		—			(128	)
Payment to ChevronTexaco for Series B preferred stock restructuring		—			(225	)
Proceeds from issuance of capital stock		5			6
Dividends and other distributions, net		(22	)		—
Other financing, net		(27	)		(18	)

Net cash provided by (used in) financing activities		24			(808	)

Effect of exchange rate changes on cash		(1	)		7
Net increase (decrease) in cash and cash equivalents		449			(69	)
Cash and cash equivalents, beginning of period		477			757

Cash and cash equivalents, end of period	$	926		$	688

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)

See Explanatory Note


	Three Months Ended September 30,
	2004			2003
Net income	$	78		$	5
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		(4	)		7
Reclassification of mark-to-market losses (gains) to earnings, net		4			(8	)

Changes in cash flow hedging activities, net (net of tax benefit of zero)		—			(1	)
Foreign currency translation adjustments		3			(9	)
Minimum pension liability (net of tax expense of $23 and zero, respectively)		39			—

Other comprehensive income (loss), net of tax		42			(10	)

Comprehensive income (loss)	$	120		$	(5	)


	Nine Months Ended September 30,
	2004			2003
Net income (loss)	$	156		$	(138	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		(57	)		52
Reclassification of mark-to-market losses (gains) to earnings, net		24			(29	)

Changes in cash flow hedging activities, net (net of tax benefit (expense) of $20 and $(7), respectively)		(33	)		23
Foreign currency translation adjustments		(12	)		12
Minimum pension liability (net of tax expense of $24 and zero, respectively)		41			—

Other comprehensive income (loss), net of tax		(4	)		35

Comprehensive income (loss)	$	152		$	(103	)

See the notes to condensed consolidated financial statements.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

PLEASE NOTE THAT THESE FINANCIAL STATEMENTS AND THE NOTES THERETO DO NOT REFLECT EVENTS OCCURRING AFTER NOVEMBER 15, 2004 (THE DATE OF THE ORIGINAL FILING). FOR A DESCRIPTION OF THESE EVENTS, PLEASE READ OUR EXCHANGE ACT REPORTS FILED SINCE NOVEMBER 15, 2004, INCLUDING OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO.

Explanatory Note

On September 22, 2004, we filed a Form 8-K announcing restatements of our previously issued financial statements contained in our 2003 Form 10-K and first and second quarter 2004 Form 10-Qs. The restatements relate to our previously disclosed goodwill impairment charge associated with the sale of Illinois Power and our deferred income tax accounts. The financial information in this report has been revised to reflect the effects of these items.

Impairment of Illinois Power. As more fully discussed in Note 10—Goodwill beginning on page F-38 of our Form 10-K/A, during 2003, the value of goodwill associated with Illinois Power was determined to be impaired, resulting in our recognizing a charge of $242 million. During 2004, while preparing to record the Illinois Power sale, we identified a deferred tax asset that was excluded from our 2003 impairment analysis. Our exclusion of this asset understated the net book value of the assets and, as a result, understated the impairment that had been recorded in 2003. The impact of the error resulted in an understatement of goodwill impairment of $139 million and an after-tax understatement of asset impairments of $120 million. As such, we were required to recognize an additional after-tax charge of $259 million ($0.61 per diluted share) in the fourth quarter 2003. In addition, we were required to recognize additional after-tax charges of $4 million ($0.01 per diluted share) and $2 million ($0.00 per diluted share) in the three months ended March 31 and June 30, 2004, respectively, due to changes in the value of the deferred tax asset. This correction had no impact on previously reported cash flows from operating activities, investing activities or financing activities. The financial information in this report has been revised to reflect the impact of this correction.

The table below summarizes the effects of the correction on our previously reported net income:


	Three Months Ended						Six Months Ended
	March 31, 2004			June 30, 2004			June 30, 2004
	(in millions)
Impairment and other charges as previously reported	$	(10	)	$	(44	)	$	(54	)
Adjustment		(6	)		(20	)		(26	)

Impairment and other charges as restated	$	(16	)	$	(64	)	$	(80	)

Income tax benefit (expense) as previously reported	$	27		$	(17	)	$	10
Adjustment		2			18			20

Income tax benefit (expense) as restated	$	29		$	1		$	30

Net income as previously reported	$	74		$	10		$	84
Adjustment		(4	)		(2	)		(6	)

Net income as restated	$	70		$	8		$	78

Deferred Income Tax Accounts. As discussed in the Form 8-K, and as previously disclosed in our second quarter 2004 Form 10-Q, we undertook an evaluation of our tax accounting and reconciliation controls and

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

processes, including a tax basis balance sheet review, which we have recently completed. Through this initiative, we determined that adjustments related to our deferred income tax accounts in periods prior to 2004 were required. The cumulative impact of these adjustments was a reduction to our deferred tax liability reflected on our December 31, 2003 balance sheet of $154 million.

Additionally, we determined that one of the adjustments to our deferred income tax accounts arose through the purchase accounting entries recorded at the time of our acquisition of Illinois Power. In order to properly reflect the impact of the adjustment, our previously disclosed goodwill impairment recorded in the fourth quarter 2003 will be reduced by approximately $70 million. This reduction offsets the $139 million increase discussed in “—Impairment of Illinois Power” above.

The restatement for the foregoing items had no effect on our previously reported net income for the nine months ended September 30, 2004 or 2003.

In the Original Filing, the entire $154 million adjustment to our deferred income tax accounts was applied to accumulated deficit. However, in the process of completing our allocation of the adjustment to the appropriate periods, we determined that $7 million of the adjustments should have been applied to other long-term liabilities at December 31, 2003. Our unaudited condensed consolidated financial statements have been restated to reflect this item. The table below summarizes the impact on our December 31, 2003 and September 30, 2004 balance sheets:


	September 30, 2004			December 31, 2003
	(in millions)
Deferred income taxes
As previously reported in our Original Filing	$	533		$	524
Adjustment		(7	)		—

As restated	$	526		$	524

Other long-term liabilities
As previously reported in our Original Filing	$	355		$	750
Adjustment		—			(7	)

As restated	$	355		$	743

Accumulated deficit
As previously reported in our Original Filing	$	(1,720	)	$	(1,859	)
Adjustment		7			7

As restated	$	(1,713	)	$	(1,852	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

Balance Sheet Summary. The table below summarizes the effects of both items discussed above on our December 31, 2003 balance sheet:


	December 31, 2003
	(in millions)
Total Assets
As previously reported	$	13,293
Impairment of Illinois Power		(332	)

As restated	$	12,961

Total Liabilities
As previously reported	$	10,716
Impairment of Illinois Power		(73	)
Deferred income tax accounts		(161	)

As restated	$	10,482

Stockholder’s Equity
As previously reported	$	2,045
Impairment of Illinois Power		(259	)
Deferred income tax accounts		161

As restated	$	1,947

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. The year end condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in our Form 10-K/A and the Explanatory Note above.

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. The results of operations for the interim periods presented in this Form 10-Q/A are not necessarily indicative of the results to be expected for the full year or any other interim period, however, due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures and other factors. The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect our reported financial position and results of operations. These estimates and assumptions also impact the nature and extent of disclosure, if any, of our contingent 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 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 possible impairment, (3) estimating the useful lives of our assets, (4) assessing future tax exposure and

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

the realization of tax assets, (5) determining amounts to accrue for contingencies and (6) estimating various factors used to value our pension assets. Certain estimates may also effect such items as the calculated gain (loss) on sale of assets. Actual results could differ materially from any such estimates.

We have reclassified certain amounts reported in this Form 10-Q/A from prior periods to conform to the 2004 financial statement presentation. These reclassifications had no impact on reported net income (loss).

Principles of Consolidation. The accompanying unaudited condensed consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries, and our proportionate share of assets, liabilities, revenues and expenses of undivided interests in certain gas processing facilities, after eliminating intercompany accounts and transactions.

Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.

Restricted Cash. Restricted cash represents cash that is unavailable for general purpose cash needs. Restricted cash at December 31, 2003 reflected amounts reserved for use in retiring Illinois Power’s Transitional Funding Trust Notes.

Allowance for Doubtful Accounts. We establish provisions for losses on accounts receivable if it is reasonable to assume we will not collect all or part of outstanding balances. We review collectibility and establish or adjust our allowance as necessary primarily using a percent of balance methodology. The specific identification method is also used in certain circumstances.

Investment in Unconsolidated Affiliates. Investments in affiliates over which we may exercise significant influence, generally 20% to 50% ownership interests, are accounted for using the equity method. Any excess of our investment in affiliates, as compared to our share of the underlying equity, that is not recognized as goodwill is amortized over the estimated economic service lives of the underlying assets. Other investments over which we may not exercise significant influence and that have readily determinable fair values are considered available-for-sale and are recorded at quoted market values or at the lower of cost or net realizable value, if there are no readily determinable fair values. For securities with readily determinable fair values, the change in the unrealized gain or loss, net of deferred income tax, is recorded as a separate component of other comprehensive income (loss) in the unaudited condensed consolidated statements of comprehensive income (loss). Realized gains and losses on investment transactions are determined using the specific identification method. All investments in unconsolidated affiliates are periodically assessed for other-than-temporary declines in value, with write-downs recognized in earnings (losses) from unconsolidated investments in the unaudited condensed consolidated statements of operations.

Concentration of Credit Risk. We sell our energy products and services to customers in the electric and gas distribution industries and to entities engaged in industrial and petrochemical businesses. These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, because the customer base may be similarly affected by changes in economic, industry, weather or other conditions.

Inventory. Our natural gas, natural gas liquids, coal and crude oil inventories are valued at the lower of weighted average cost or at market. Our materials and supplies inventory is carried at the lower of cost or market using the specific identification method.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

Property, Plant and Equipment. Property, plant and equipment, which has consisted principally of gas gathering, processing, fractionation, terminaling and storage facilities, natural gas transportation and electric transmission lines, pipelines and power generating facilities, is recorded at historical cost. Expenditures for major replacements, renewals and major maintenance are capitalized. We consider major maintenance to be expenditures incurred on a cyclical basis to maintain and prolong the efficient operation of our assets. Expenditures for repairs and minor renewals to maintain assets in operating condition are expensed. Depreciation is provided using the straight-line method over the estimated economic service lives of the assets, ranging from three to 40 years. Composite depreciation rates, which we refer to as composite rates, are applied to functional groups of assets having similar economic characteristics. The estimated economic service lives of our functional asset groups are as follows:


Asset Group		Range of Years
Power Generation Facilities		27 to 40
Natural Gas Gathering Systems and Processing Facilities		20
Fractionation, Terminaling and Natural Gas Liquids Storage Facilities		20 to 25
Transportation Equipment		5 to 10
Buildings and Improvements		10 to 39
Office and Miscellaneous Equipment		3 to 20

Gains and losses are not recognized for retirements of property, plant and equipment subject to composite rates until the asset group subject to the composite rate is retired. Gains and losses on sales of individual assets are reflected in gain (loss) on sale of assets in the unaudited condensed consolidated statements of operations. We review the carrying value of our long-lived assets in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” which addresses the accounting and reporting for the impairment or disposal of long-lived assets. Under this standard, we evaluate an asset for impairment when events or circumstances indicate its carrying value may not be recovered. These events include market declines, changes in the manner in which we intend to use an asset or decisions to sell an asset and adverse changes in the legal or business environment. When we decide to exit or sell a long-lived asset or group of assets, we adjust the carrying value of these assets downward, if necessary, to the estimated sales price, less costs to sell.

Other Contingencies. Environmental costs relating to current operations are expensed or capitalized, as appropriate, depending on whether they provide future economic benefit. Liabilities are recorded when environmental assessment indicate remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based on currently enacted laws and regulations, existing technology and site-specific costs. Liabilities may be recognized on a discounted basis if the amount and timing of anticipated expenditures are fixed or reliably determinable; otherwise, such liabilities are recognized on an undiscounted basis. Liabilities incurred by providing indemnification in connection with assets sold or closed are recognized upon such sale or closure to the extent they are probable, can be estimated and have not previously been reserved. In assessing liabilities, no offset is made for potential insurance recoveries. Recognition of any joint and several liability is based upon our best estimate of our final pro rata share of such liability.

Liabilities for other contingencies are recognized in accordance with SFAS No. 5, “Accounting for Contingencies,” upon identification of an exposure, which, when fully analyzed, indicates that it is both probable a liability has been incurred and the loss amount can be reasonably estimated. Non-capital costs to remedy such contingencies or other exposures are charged to a reserve, if one exists, or otherwise to current-period operations. We accrue the lesser end of the range when a range of probable loss exists.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

Goodwill and Other Intangible Assets. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” we subject goodwill to a fair value-based impairment test on at least an annual basis. The estimation of fair value is highly subjective, inherently imprecise and can change materially from period to period based on, among other things, an assessment of market conditions, projected cash flows and discount rate. We currently perform our annual impairment test in the fourth quarter after our annual budgetary process, and we may record further impairment losses in future periods as a result of such test.

Revenue Recognition. We utilize two comprehensive accounting models in reporting our consolidated financial position and results of operations as required by GAAP: an accrual model and a fair value model. We determine whether to apply one comprehensive accounting model rather than the other based on guidance provided by the FASB and the SEC.

The accrual model has historically been used to account for substantially all of the operations conducted in the GEN, NGL and REG segments. Revenues from power generation are recognized upon output, product delivery or satisfaction of specific targets, all as specified by contractual terms. Revenues for product sales, gas processing, storage and marketing and refinery services are recognized when title passes to the customer or when the service is performed. Fractionation and transportation revenues are recognized based on volumes received in accordance with contractual terms. Our transmission, distribution and retail electric and natural gas services revenues are recognized when services are provided to customers. Shipping and handling costs are included in revenue when billed to customers with the sale of products.

The fair value model is used to account for certain forward physical and financial transactions, primarily in the GEN and CRM segments, which meet criteria defined by FASB for derivative instruments. These criteria require these contracts to relate to future periods, to contain price and volume components and to have terms that require or permit net settlement of the contract in cash or its equivalent. The value of the assets and liabilities associated with these transactions is reported at estimated settlement value based on current prices and rates as of each balance sheet date. The net gains or losses resulting from the revaluation of these contracts during the period are recognized currently in our consolidated statements of operations unless such contracts qualify and are designated as cash flow hedges, in which case the same gains or losses are recorded in other comprehensive income (loss) until such time as the hedged transaction occurs. If the underlying transaction being hedged by the commodity, interest rate or foreign currency transaction is disposed of or otherwise terminated, the gain or loss associated with such contract is no longer deferred and is recognized in the period the underlying contract is eliminated. Subsequent gains and losses associated with the change in value of interest rate or foreign currency instruments are recognized in other income and expense, net, unless the instrument is redesignated as a hedge. If the hedging transaction is terminated prior to the occurrence of the underlying transaction being hedged, the gain or loss associated with the hedging transaction is deferred and recognized in income in the period in which the underlying transaction being hedged occurs. Assets and liabilities associated with these transactions are reflected on our consolidated balance sheets as risk-management assets and liabilities and classified as short- (i.e., current) or long-term pursuant to each contract’s individual length.

We estimate the fair value of our marketing portfolio using a liquidation value approach assuming that our ability to transact business in the market remains at historical levels. The estimated fair value of our portfolio is computed by multiplying all existing positions in our portfolio by estimated prices, reduced by a LIBOR-based time value of money adjustment and deduction of reserves for credit and price. The estimated prices in this valuation are based either on (1) prices obtained from market quotes or, if market quotes are unavailable, (2) prices from a proprietary model that incorporates forward energy prices derived from market quotes and values from executed transactions.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

Cash inflows and outflows associated with the settlement of risk management activities are recognized in operating cash flows.

Income Taxes. We file a consolidated U.S. federal income tax return and, for financial reporting purposes, account for income taxes using the liability method in accordance with SFAS No. 109, “Accounting for Income Taxes.” Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities caused by differences between financial statement carrying amounts and the tax basis of certain assets and liabilities. Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse. Valuation allowances are provided against deferred tax assets when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates used to recognize deferred tax assets are subject to revision, either higher or lower, in future periods based on new facts or circumstances.

Earnings Per Share. Basic earnings per share represents the amount of earnings for the period available to each share of common stock outstanding during the period. Diluted earnings per share represents the amount of earnings 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 potentially dilutive common shares outstanding during the period.

Foreign Currency. For subsidiaries whose functional currency is not the U.S. Dollar, assets and liabilities are translated at year-end rates of exchange and revenues and expenses are translated at monthly average exchange rates. Translation adjustments for the asset and liability accounts are included as a separate component of accumulated other comprehensive loss in stockholders’ equity.

Currency transaction gains and losses are recorded in other income and expense, net on our unaudited condensed consolidated statements of operations and totaled losses of $1 million for each of the three months ended September 30, 2004 and 2003, and gains of $2 million and $10 million for the nine months ended September 30, 2004 and 2003, respectively.

Regulatory Assets and Liabilities. SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” allows companies whose service obligations and prices are regulated to maintain balance sheet assets representing costs they expect to recover from customers through inclusion in future rates. Illinois Power, our former wholly owned utility subsidiary, recorded regulatory assets in accordance with SFAS No. 71. Regulatory assets as of December 31, 2003 totaled approximately $207 million and were included in other long-term assets on our unaudited condensed consolidated balance sheet. The investment tax credit related to regulatory assets is amortized over the lives of the respective assets, which gave rise to the investment tax credit.

Rate-regulated companies subject to SFAS No. 71 are permitted to accrue the estimated cost of removal and salvage associated with certain of their assets through depreciation expense. The amounts accrued in depreciation are not associated with AROs recorded in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations.” At December 31, 2003, approximately $72 million of cost of removal, net of salvage, was included in regulatory liabilities.

Minority Interest. Minority interest on our unaudited condensed consolidated balance sheets includes third-party investments in entities that we consolidate, but do not wholly own. The net pre-tax results attributed to minority interest holders in consolidated entities are included in minority interest income (expense) in the unaudited condensed consolidated statements of operations.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

Accounting Principles Adopted

EITF Issue 02-03. In October 2002, the EITF rescinded EITF Issue 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” which previously required use of mark-to-market accounting for our energy trading contracts. While the rescission of EITF Issue 98-10 reduced the number of contracts accounted for on a mark-to-market basis, it did 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,” as amended, continue to be marked-to-market in accordance with SFAS No. 133. Any earnings or losses previously recognized under EITF Issue 98-10 that would not have been recognized under SFAS No. 133 were reversed in 2003 in connection with our adoption 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 comprised the following items 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 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.

EITF Issue 03-11. In July 2003, the EITF reached consensus on Issue 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133, ‘Accounting for Derivative Instruments and Hedging Activities’, and Not ‘Held for Trading Purposes’ as Defined in EITF Issue 02-03, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.’” The consensus stated that determining whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. The consideration of the facts and circumstances, including economic substance, should be made in the context of the various activities of the entity rather than based solely on the terms of the individual contracts. We were not materially impacted by the adoption of EITF Issue 03-11.

SFAS No. 143. In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” We adopted SFAS No. 143, which provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, effective January 1, 2003. Under SFAS No. 143, an ARO is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

long- lived asset by an amount equal to the ARO. In each subsequent period, the liability is accreted towards the ultimate obligation amount and the capitalized ARO costs are depreciated over the useful life of the related asset.

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 $34 million in the first quarter 2003, which is included in cumulative effect of change in accounting principles in the unaudited condensed consolidated statements of operations. In addition to these liabilities, we also have potential retirement obligations for dismantlement of power generation facilities, power transmission assets, a fractionation facility and natural gas storage facilities. Our current intent is to maintain these facilities in a manner such that they will be operated indefinitely. As such, we cannot estimate any potential retirement obligations associated with these assets. Liabilities will be recorded in accordance with SFAS No. 143 at the time we are able to estimate any new AROs.

At January 1, 2004, our ARO liabilities were $30 million for our GEN segment, $10 million for our NGL segment and $1 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 nine-month periods ended September 30, 2004, accretion expense recognized as our ARO liabilities accreted toward their ultimate redemption values totaled approximately $1 million and $3 million, respectively. In the third quarter 2004, a land lease formerly held by our REG segment was transferred to our GEN segment. The accompanying ARO liability, which totaled approximately $1 million at September 30, 2004, was also transferred. 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 nine-month periods ended September 30, 2004. At September 30, 2004, our aggregate ARO liability was $44 million.

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, “Accounting for Stock-Based Compensation,” 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.

Under the prospective method of transition, all stock options granted after January 1, 2003 are accounted for on a fair value basis. We will incur compensation expense over the vesting period of the options in an amount equal to the fair value of the options. Options granted prior to January 1, 2003 continue to be accounted for using the intrinsic value method. Accordingly, for options granted prior to January 1, 2003, compensation expense is not reflected for employee stock options unless they were granted at an exercise price lower than market value on the grant date. We have granted in-the-money options in the past and have recognized compensation expense over the applicable vesting periods. No in-the-money stock options have been granted since 1999.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

Had compensation cost for all stock options granted prior to 2003 been determined on a fair value basis consistent with SFAS No. 123, our net income (loss) and basic and diluted earnings per share amounts would have approximated the following pro forma amounts for the three- and nine-month periods ended September 30, 2004 and 2003, respectively.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
	(in millions, except per share data)
Net income (loss) as reported	$	78		$	5		$	156		$	(138	)
Add: Stock-based employee compensation expense included in reported net income (loss), net of related tax effects		1			—			3			1
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(6	)		(13	)		(22	)		(41	)

Pro forma net income (loss)	$	73		$	(8	)	$	137		$	(178	)

Earnings per share:
Basic—as reported	$	0.19		$	3.17		$	0.37		$	2.36
Basic—pro forma	$	0.18		$	3.14		$	0.32		$	2.25
Diluted—as reported	$	0.16		$	2.65		$	0.32		$	2.21
Diluted—pro forma	$	0.15		$	2.62		$	0.28		$	2.13

SFAS No. 149. In April 2003, the FASB issued SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” which 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: (1) clarifies when a contract with an initial net investment meets the characteristics of a derivative; (2) clarifies when a derivative contains a financing component that should be recorded as a financing transaction on the balance sheet and the statement of cash flows; (3) amends the definition of an “underlying” in SFAS No. 133 to conform to the language used in FIN No. 45; and (4) clarifies 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. The adoption of SFAS No. 149 did not materially impact our financial statements.

SFAS No. 150. In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity,” which establishes how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. Instruments that 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 that 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 was effective for contracts in existence or created or modified for the first interim period beginning after June 15, 2003. Upon adoption, we reclassified approximately $200 million of Company Obligated Preferred Securities (now referred to as Subordinated Debentures), previously recorded in the mezzanine section of our balance sheet between liabilities and stockholders’ equity, to long-term liabilities. Accordingly, the interest related to this instrument is recorded as interest expense beginning July 1, 2003. Prior year amounts have not been reclassified to conform to this change. Previously, the preferred return on this instrument was reported in accumulated distributions associated with trust preferred securities in the unaudited condensed consolidated statements of operations.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

FIN No. 46R. In the fourth quarter 2003, we adopted the initial provisions of FIN No. 46R, “Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51.” FIN No. 46R was effective on December 31, 2003 for entities considered SPEs. We adopted the remaining provisions of FIN No. 46R on March 31, 2004. These provisions require that we review the structure of non-SPE legal entities in which we have an investment and other legal entities with whom we transact to determine whether such entities are VIEs, as defined by FIN No. 46R. With respect to each of the VIEs we identified, we assessed whether we are the “primary beneficiary,” as defined by FIN No. 46R. We concluded that we were not the primary beneficiary of any of these entities and, therefore, the adoption did not have an impact on our unaudited condensed consolidated financial statements.

FIN No. 46R requires additional disclosures for entities which meet the definition of a VIE in which we hold a significant variable interest but are not the primary beneficiary. We own 50% equity interests in various generation facilities in Illinois and California which are accounted for using equity method accounting and are included in Unconsolidated investments in our unaudited condensed consolidated balance sheets. We acquired or began involvement with these equity interests in 1997 and 1999. Total net generating capacity for these generating facilities ranges from 165 MW to 1,156 MW. As a result of various contractual arrangements into which these entities have entered, we have concluded that they are VIEs. As we do not absorb a majority of the expected losses or receive a majority of the expected residual returns, we are not considered the primary beneficiary of these entities. Our equity investment balance in the facilities totaled $346 million at September 30, 2004, and one of these entities has a loan outstanding to another of these entities, which totaled $20 million at September 30, 2004.

In July 2001, we entered into several agreements, including a power tolling agreement, a financial derivative instrument, an energy management agreement and a natural gas supply agreement, with Sithe Independence Power Partners, L.P., which we refer to as Sithe Independence or Sithe Independence, L.P. and which owns and operates a 1,042 MW combined cycle natural gas generation facility near Scriba, New York. We had previously been unable to assess whether the entity was a VIE, but have subsequently received the necessary financial and contractual information related to the entity. As a result of various contractual arrangements into which this entity has entered, we have concluded that it is a VIE. However, as we do not absorb a majority of the expected losses or receive a majority of expected residual returns, we are not considered the primary beneficiary of the entity. Our agreements with Sithe Independence Power Partners, L.P. are in effect through 2014. Our future obligations under these agreements are approximately $772 million, which includes the fixed capacity payments under our power tolling contract and fixed payments related to the financial derivative instrument. In November 2004, we entered into an agreement to purchase from Exelon Corporation all of the outstanding capital stock of ExRes SHC, Inc., the parent company of Sithe Energies, Inc. and Sithe Independence, L.P. Please read Note 2—Acquisitions, Dispositions, Contract Terminations and Discontinued Operations—Acquisitions—Sithe Energies below for further discussion.

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 above for a discussion of the impact of adopting these standards.

Note 2—Acquisitions, Dispositions, Contract Terminations and Discontinued Operations

Acquisitions

Sithe Energies. In November 2004, we entered into an agreement to purchase from Exelon Corporation all of the outstanding capital stock of ExRes SHC, Inc., the parent company of Sithe Energies, Inc. and Sithe Independence, L.P. Through this acquisition, we will acquire the 1,042 MW, 7,211-Btu heat rate, combined-cycle Independence power generation facility located near Scriba, NY, four natural gas-fired merchant facilities

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

in New York and four hydroelectric generation facilities in Pennsylvania. In addition, Sithe Independence, L.P. holds a 750 MW firm capacity sales agreement with Con Edison, a subsidiary of Consolidated Edison, Inc. The capacity sales agreement, which runs through 2014, provides annual cash receipts of approximately $100 million. Sithe Independence, L.P. also holds power tolling and financial swap contracts with one of our subsidiaries. The acquisition transforms the tolling and swap contracts into intercompany agreements, substantially eliminating their financial impact by retaining the net cash flows within our subsidiaries. Under the terms of its indebtedness, however, Sithe Independence would have limitations on its ability to distribute cash to us. As a result of the purchase accounting rules under GAAP, which require each contractual arrangement to be adjusted to its fair market value at closing, we expect to record a charge to earnings upon closing of the transaction.

The financial terms of the agreement include the payment of $135 million in cash and the consolidation of $919 million in face value project debt for which certain of the entities to be acquired are obligated. This project debt will be recorded at its fair value as of the closing date, which we expect to be substantially less than the face value of $919 million. The principal and interest payments related to the consolidated debt will be substantially funded through 2014 by the proceeds from the long-term capacity sales contract with Con Edison.

The transaction is subject to various closing conditions, including the receipt of approvals from various federal and state regulatory entities, including the FERC and the New York Public Service Commission, as well as Hart-Scott-Rodino review by the Federal Trade Commission. The transaction is also subject to the receipt by Sithe Independence of a waiver or amendment from its bondholders under its trust indenture.

Dispositions and Contract Terminations

Sale of Illinois Power. On September 30, 2004, we sold all of our outstanding common and preferred shares of Illinois Power Company, which formerly comprised our REG segment, owned by Illinova Corporation, our subsidiary, as well as our 20% interest in the Joppa power generation facility, to Ameren for $2.3 billion. The $2.3 billion sale price consisted of Ameren’s assumption of $1.8 billion of Illinois Power’s debt and preferred stock obligations, cash proceeds of approximately $375 million and an additional $100 million of cash placed in escrow. Under the escrow agreement, which we have filed as an exhibit to this Form 10-Q, the $100 million deposited by Ameren will be released to us on the sooner of (i) December 31, 2010, (ii) the date on which DHI’s senior unsecured debt achieves an investment grade rating from Standard & Poor’s or Moody’s Investor Services, Inc. or (iii) the occurrence of specified events relating to contingent environmental liabilities associated with Illinois Power’s former generating facilities. During the time that these funds remain in escrow, we will receive quarterly payments equivalent to the interest income earned on such funds.

Also on September 30, 2004, we entered into a two-year power purchase agreement under which Illinois Power will annually purchase from us up to 2,800 MWs of capacity and 11.3 million MWh of energy at fixed prices beginning in January 2005. We also agreed to sell an additional 300 MWs of capacity in 2005 and 150 MWs of capacity in 2006 to Illinois Power at a fixed price with an option to purchase energy at market-based prices.

In the first quarter 2004, Illinois Power met the held for sale classification requirements of SFAS No. 144, and continued to meet the requirements through the closing of the sale in September 2004. SFAS No. 144 requires that long-lived assets not be depreciated or amortized while they are classified as held for sale. As such, we discontinued depreciation and amortization of Illinois Power’s property, plant and equipment and regulatory assets, effective February 1, 2004. Depreciation and amortization expense related to Illinois Power totaled $30 million and $91 million in the three- and nine-month periods ended September 30, 2003, respectively. In addition, SFAS No. 144 requires a loss to be recognized by the amount Assets held for sale less Liabilities held

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

for sale are in excess of fair value less costs to sell. Accordingly, for the three-month periods ended March 31, 2004 and June 30, 2004, we recorded pre-tax losses on the sale of $21 million and $48 million, respectively. The first quarter 2004 charge, which was primarily associated with the expected transaction costs, is reflected in Gain (loss) on sale of assets, net and Impairment and other charges on our unaudited condensed consolidated statements of operations. The second quarter 2004 charge, an impairment of assets, is reflected in Impairment and other charges on the unaudited condensed consolidated statements of operations. Finally, in the three-month period ended September 30, 2004, we recorded a pre-tax loss on the sale of $24 million. The charge is reflected in Gain (loss) on sale of assets, net on our unaudited condensed consolidated statements of operations.

Further, pursuant to SFAS No. 144, we are not reporting the results of Illinois Power’s operations as a discontinued operation. If we were to account for Illinois Power as a discontinued operation, its results of operations would be condensed into Income (loss) from discontinued operations, net of taxes, on our unaudited condensed consolidated statements of operations, and prior periods would be required to be restated to conform to this presentation. To qualify for discontinued operations classification, SFAS No. 144 and subsequent interpretations, specifically EITF Issue 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations,” require that the seller have no significant continuing involvement with the business being sold. As noted above, we have contracted to sell capacity and energy to Illinois Power for two years subsequent to the sale. Consequently, because we will have significant continuing involvement with Illinois Power, we have reported the historical results of Illinois Power’s operations in continuing operations. Additionally, earnings from power sales to Illinois Power derived from periods following the sale will continue to be reported in the GEN segment in continuing operations.

Had the results of Illinois Power been excluded from our comparative results as though the sale had occurred at the beginning of each respective period noted below, our Revenues; Income (loss) before cumulative effect of changes in accounting principles, net of tax; and Net income applicable to common stockholders and associated basic and diluted earnings per share would have approximated the following pro forma amounts for the three- and nine-month periods ended September 30, 2004 and 2003, respectively.


	Three Months Ended September 30,					Nine Months Ended September 30,
	2004		2003			2004		2003
	(in millions, except per share data)
Revenues:
As reported	$	1,650	$	1,385		$	4,747	$	4,331
Pro forma		1,387		1,160			3,953		3,562

Income (loss) before cumulative effect of change in accounting principles, net of tax:
As reported	$	78	$	5		$	156	$	(193	)
Pro forma		48		(9	)		132		(214	)

Net income applicable to common stockholders:
As reported	$	72	$	1,188		$	139	$	880
Pro forma		42		1,174			115		859

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003


	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
	(in millions, except per share data)
Earnings per share—Income before cumulative effect of change in accounting principles, net of tax:
Basic—as reported	$	0.19	$	3.17	$	0.37	$	2.21
Basic—pro forma	$	0.11	$	3.13	$	0.30	$	2.16
Diluted—as reported	$	0.16	$	2.65	$	0.32	$	2.08
Diluted—pro forma	$	0.10	$	2.62	$	0.27	$	2.04

Earnings per share—Net income applicable to common stockholders:
Basic—as reported	$	0.19	$	3.17	$	0.37	$	2.36
Basic—pro forma	$	0.11	$	3.13	$	0.30	$	2.30
Diluted—as reported	$	0.16	$	2.65	$	0.32	$	2.21
Diluted—pro forma	$	0.10	$	2.62	$	0.27	$	2.17

Joppa. We recorded a pre-tax gain of $75 million upon closing of the sale of our 20% interest in the Joppa power generating facility. This gain is included in Earnings from unconsolidated investments on our unaudited condensed consolidated statements of operations.

Hackberry LNG Project. During the first quarter 2003, we entered into an agreement to sell our ownership 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 in April 2003, after which we received contingent payments in 2003 based upon project development milestones. In March 2004, we sold our remaining financial interest in this project, which interest included rights to receive future contingent payments under the 2003 agreement, for $17 million and recognized a pre-tax gain of $17 million on the sale. This gain is included in Gain (loss) on sale of assets, net on our unaudited condensed consolidated statements of operations.

Indian Basin. In April 2004, we sold our 16% interest in the Indian Basin Gas Processing Plant for approximately $48 million. In the second quarter 2004, we recognized a pre-tax gain on the sale of approximately $36 million. This gain is included in Gain (loss) on sales of assets, net on our unaudited condensed consolidated statements of operations.

PESA. In April 2004, we sold our interest in the Plantas Eolicas, S.A. de R.L. 20 MW wind-powered electric generation facility located in Costa Rica for approximately $11 million. We recognized a pre-tax loss of approximately $1 million on the sale. This loss is included in Gain (loss) on sale of assets, net on our unaudited condensed consolidated statements of operations.

Sherman. In November 2004, we sold our Sherman natural gas processing facility located in Sherman, Texas. This sale resulted in a pre-tax gain of approximately $16 million.

Gas Transportation Contracts. In June 2004, we agreed to exit four long-term natural gas transportation contracts whose purpose was to secure firm pipeline capacity through 2014 in support of our former third-party marketing and trading business. In exchange for exiting these obligations, we paid $20 million in June 2004 and will pay an additional $42 million in the first quarter 2005. This future payment obligation was recorded at its fair value of $40 million and will be accreted to $42 million over the period July 1, 2004 through March 31, 2005. Additionally, we reversed an aggregate liability of $148 million associated with the transportation

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

contracts that was originally established in 2001 and recognized a pre-tax gain of $88 million related to these transactions. This gain is included in Revenues on our unaudited condensed consolidated statements of operations and is included in the results of our CRM segment. This agreement will eliminate our obligation to make approximately $295 million in aggregate fixed capacity payments from April 2005 through 2014.

Discontinued Operations

As part of our restructuring plan, we sold or liquidated some of our operations during 2003, including substantial portions of our communications business and our U.K. CRM business, which have been accounted for as discontinued operations under SFAS No. 144.

The following table summarizes information related to our discontinued operations:


	U.K. Storage		U.K. CRM			DGC			Global Liquids			Total
	(in millions)
Three Months Ended September 30, 2004
Income (loss) from operations before taxes	$	—	$	(2	)	$	—		$	1		$	(1	)
Loss from operations after taxes		—		(2	)		—			—			(2	)

Three Months Ended September 30, 2003
Loss from operations before taxes	$	—	$	(7	)	$	—		$	(2	)	$	(9	)
Loss from operations after taxes		—		(4	)		—			(1	)		(5	)
Gain on sale before taxes		1		—			8			—			9
Gain on sale after taxes		1		—			5			—			6

	U.K. Storage		U.K. CRM			DGC			Global Liquids			Total
	(in millions)
Nine Months Ended September 30, 2004
Income from operations before taxes	$	—	$	17		$	3		$	1		$	21
Income (loss) from operations after taxes		—		(9	)		2			—			(7	)

Nine Months Ended September 30, 2003
Revenue	$	—	$	21		$	5		$	—		$	26
Loss from operations before taxes		—		(18	)		(29	)		(3	)		(50	)
Loss from operations after taxes		—		(13	)		(18	)		(2	)		(33	)
Gain on sale before taxes		1		—			33			—			34
Gain on sale after taxes		1		—			26			—			27

In the first quarter 2004, we recognized $17 million of pre-tax income related to translation gains on foreign currency in the U.K. Please see Note 4—Risk Management Activities and Accumulated Other Comprehensive Loss—Net investment hedges in foreign operations for further discussion. Also in the first quarter 2004, we recognized $3 million of pre-tax income associated with DGC’s receipt of $3 million from a third party in settlement of a prior contractual claim. In the second quarter 2004, we recognized a tax expense of $20 million related to charges resulting from the conclusion of prior year tax audits. Please see Note 12—Income Taxes for further discussion.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

Note 3—Restructuring Charges

In the nine months ended September 30, 2004, we recorded charges relating to the sale of our interest in Illinois Power totaling $93 million. For further discussion, please read Note 2—Acquisitions, Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Sale of Illinois Power. In addition, in the nine months ended September 30, 2004, we recorded a $5 million pre-tax charge related to the impairment of one of our midstream assets.

In October 2002, we announced a restructuring plan designed to improve operational efficiencies and performance across our lines of business. The following is a schedule of 2004 activity for the liabilities recorded in connection with this restructuring:


	Severance			Cancellation Fees and Operating Leases			Total
	(in millions)
Balance at December 31, 2003	$	23		$	30		$	53
2004 adjustments to liability		18			7			25
Cash payments		(36	)		(8	)		(44	)

Balance at September 30, 2004	$	5		$	29		$	34

The adjustment to the accrued liability during 2004 primarily reflects increases in the severance accrual due to changes in our estimate of the probable loss associated with the severance claims of our former chief executive officer and our former president. Cash payments during 2004 reflect payments made to our former chief executive officer and our former president. Please see Note 9—Commitments and Contingencies—Severance Arbitrations for further discussion regarding the status of these claims and settlement payments.

We expect the $29 million accrual associated with cancellation fees and operating leases to be paid by the end of 2007 when the leases expire.

Note 4—Risk Management Activities and Accumulated Other Comprehensive Loss

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—Risk Management Activities and Financial Instruments beginning on page F-29 of our Form 10-K/A.

Cash flow hedges. We enter into financial derivative instruments that qualify as cash flow hedges. Instruments related to our GEN, CRM and NGL businesses are entered into for purposes of hedging future fuel requirements and sales commitments and locking in future margin. Interest rate swaps are used to convert the floating interest-rate component of some obligations to fixed rates.

During the three and nine months ended September 30, 2004, we recorded a $3 million charge related to 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. During the three and nine months ended September 30, 2003, 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.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

During the three and nine months ended September 30, 2004, no material amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring. During the three and nine months ended September 30, 2003, we recorded a $4 million charge related to the reclassification of earnings in connection with forecasted transactions that were no longer considered probable of occurring.

The balance in cash flow hedging activities, net at September 30, 2004 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, after-tax losses of approximately $27 million are currently estimated to be reclassified into earnings over the 12-month period ending September 30, 2005. The actual amounts that will be reclassified to earnings over this period and beyond could vary materially from this estimated amount as a result of changes in market conditions and other factors.

Fair value hedges. 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 nine months ended September 30, 2004 and 2003, there was no ineffectiveness from changes in the fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. During the three and nine months ended September 30, 2004, no amounts were recognized in relation to firm commitments that no longer qualified as fair value hedges. During the three and nine months ended September 30, 2003, we recorded a $6 million gain related to firm commitments that no longer qualified as fair value hedges.

In July 2004, we entered into interest rate swaps with a notional value of $500 million. These swaps were designated as fair value hedges and effectively convert a portion of our non-prepayable fixed-rate debt into variable-rate debt.

Net investment hedges in foreign operations. Although we have exited a substantial amount of our foreign operations, we continue to have investments in foreign subsidiaries, the net assets of which are exposed to currency exchange-rate volatility. In the past, we used derivative financial instruments, including foreign exchange forward contracts and cross-currency interest rate swaps, to hedge this exposure. As of September 30, 2004, we had no net investment hedges in place.

During the first quarter 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,” a significant portion of 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 $16 million in the nine months ended September 30, 2003. During the first quarter 2004, we repatriated a majority of our cash from the U.K., resulting in the substantial liquidation of our investment in the U.K. As such, we recognized approximately $17 million of pre-tax translation gains in income that arose since April 1, 2003 and had accumulated in stockholders’ equity.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

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


	September 30, 2004			December 31, 2003
	(in millions)
Cash flow hedging activities, net	$	(23	)	$	10
Foreign currency translation adjustment		15			27
Minimum pension liability		(16	)		(57	)

Accumulated other comprehensive loss, net of tax	$	(24	)	$	(20	)

Note 5—Unconsolidated Investments

A summary of our unconsolidated investments is as follows:


	September 30, 2004		December 31, 2003
	(in millions)
Equity affiliates:
GEN investments	$	374	$	518
NGL investments		78		82

Total equity affiliates		452		600
Other affiliates, at cost		7		12

Total unconsolidated investments	$	459	$	612

Summarized aggregate financial information for unconsolidated equity investments and our equity share thereof was:


	Nine Months Ended September 30,
	2004				2003
	Total		Equity Share		Total		Equity Share
	(in millions)
Revenues	$	1,589	$	709	$	2,143	$	887
Operating income		367		173		406		180
Net income		339		162		337		148

Earnings from unconsolidated investments of $194 million for the nine months ended September 30, 2004 include the $162 million above, gains on the sales of our 20% interest in the Joppa facility, our equity investment in Oyster Creek and our equity investment in Hartwell of $75 million, $15 million and $2 million, respectively. These gains were partially offset by a $45 million impairment of our investment in West Coast Power and an $8 million impairment of our Michigan Power equity investment discussed below, as well as $7 million primarily due to amortization of the difference between the cost of our unconsolidated investments and our underlying equity in their net assets. Earnings from unconsolidated investments of $142 million for the nine months ended September 30, 2003 consist of the $148 million above, partially offset by $5 million in losses due to impairments of cost investments and a $1 million loss on sale of an investment.

During the first quarter 2004, we sold our interest in our power generating facility located in Jamaica. Net proceeds associated with the sale were approximately $5.5 million, and we did not recognize a gain or loss on the sale.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

In the third quarter 2004, we sold our unconsolidated investments in the Oyster Creek, Michigan Power and Hartwell generating facilities for aggregate net cash proceeds of approximately $132 million. During the third quarter 2004, we recognized gains of $15 million and $2 million related to our sales of Oyster Creek and Hartwell, but did not recognize any gain or loss on the sale of Michigan Power. However, during the nine months ended September 30, 2004, we recorded an impairment on our investment in Michigan Power totaling $8 million, to adjust our book value to the sale price.

In July 2004, we entered into an agreement to sell our unconsolidated investment in the Commonwealth generating facility. Closing of this transaction, targeted for the fourth quarter 2004, is subject to regulatory and other approvals. Under the terms of this agreement, we do not expect to recognize a material gain or loss on this sale.

Additionally, in September 2004, we recorded an impairment of $45 million on our investment in West Coast Power, primarily due to the upcoming expiration of the CDWR contract in December 2004. As the remaining value of the CDWR contract is realized throughout 2004, the fair value of our investment in West Coast Power has declined. We will continue to evaluate our investment in West Coast Power, and we anticipate that an additional impairment charge may become necessary in the fourth quarter 2004.

Note 6—Debt

Notes payable and long-term debt consisted of the following:


	September 30, 2004		December 31, 2003
	(in millions)
Dynegy Holdings Inc.	$	4,150	$	3,744
Illinova		—		95
Illinois Power		—		1,937
Dynegy Inc.		350		448

Total	$	4,500	$	6,224

Revolvers. During the three- and nine-month periods ended September 30, 2004, we reduced an aggregate of approximately $53 million and $70 million, respectively, of letters of credit under our revolving credit facilities, resulting in a total of $118 million utilized at September 30, 2004. As of September 30, 2004, there were no borrowings outstanding under our $700 million revolving credit facility. During the period from September 30, 2004 through November 8, 2004, we reduced our outstanding letters of credit under this facility by $5 million.

Effective May 28, 2004, DHI entered into a $1.3 billion credit facility consisting of:

•

a $700 million secured revolving credit facility that matures on May 28, 2007; and

•

a $600 million secured amortizing term loan that matures on May 28, 2010.

The credit facility replaced DHI’s $1.1 billion revolving credit facility, which was scheduled to mature in February 2005.

The revolving credit facility provides funding for general corporate purposes and is also available for the issuance of letters of credit. Borrowings under the revolving credit facility bear interest, at DHI’s option, at (i) a base rate plus 3.00% per annum or (ii) LIBOR plus 4.00% 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 4.00% of such undrawn amount. We also incur additional fees for issuing letters of credit. An unused commitment fee of 0.50% will be payable on the unused portion of the revolving credit facility.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

Of the $600 million in proceeds from the term loan drawn at closing, a portion was used to post cash collateral in lieu of letters of credit, while approximately $19 million was used to pay upfront fees incurred in connection with the new facility. These fees have been capitalized and are being amortized over the term of the credit facility. In August 2004, $154 million of the proceeds from the $600 million term loan were used to pre-pay all outstanding indebtedness and other amounts owed in connection with the ABG Gas Supply financing. The remaining proceeds, subject to specified restrictions in the credit facility, are available for general corporate purposes. Borrowings under the term loan bear interest, at DHI’s option, at (i) a base rate plus 3.00% per annum or (ii) LIBOR plus 4.00% per annum.

The credit facility contains mandatory prepayment events associated with specified asset sales and recovery events (i.e., certain payments in respect of insurance claims or condemnation proceedings). DHI must offer to repay the term loan or permanently reduce the revolving credit facility with 100% of the net cash proceeds of all asset sales or any proceeds from recovery events, excluding (i) proceeds from sales of designated assets, including Illinois Power and the minority GEN investments currently targeted for sale; (ii) up to $100 million of net cash proceeds from other asset sales as designated by DHI; and (iii) up to $900 million of proceeds from asset sales and recovery events that are reinvested in the business, subject to specified restrictions. Sales of assets over a specified threshold require written confirmation from both Standard & Poor’s Ratings Service and Moody’s Investors Service that the credit ratings of the credit facility will not be lowered as a result. Further, any sale of our Baldwin facility or all or substantially all of our DMS assets would require the written consent of a majority of the lenders under the new credit facility.

The credit facility provides for no amortization of principal amounts outstanding prior to the maturity dates except (i) upon the occurrence of a mandatory prepayment event and (ii) term loan amortization of 1% per annum.

The credit facility is secured by substantially the same collateral as the $1.1 billion facility it replaced, including a first priority interest in substantially all our assets and the assets of our subsidiaries and on substantially all of the equity of our subsidiaries in each case to the extent permitted by other applicable agreements. We and substantially all of our subsidiaries also guarantee this facility.

The credit facility contains affirmative and negative covenants, including negative covenants relating to the following which restrict DHI and its subsidiaries but do not restrict us: liens; investments; indebtedness; dispositions; restricted payments; burdensome agreements; amendments to organizational documents; prepayments of indebtedness; and swap contracts. The credit facility also contains the financial and capital expenditure-related covenants described below.

The credit facility generally prohibits DHI and its subsidiaries, subject to specified exceptions, from incurring additional debt. Notwithstanding this restriction, DHI may issue, to the extent permitted by the more restrictive covenants with respect to secured debt in the indenture governing the DHI second priority senior secured notes, (i) up to $700 million of additional second lien or junior secured debt or unsecured debt, provided such additional debt matures at least six months after the term loan, and (ii) permitted refinancing indebtedness.

The credit facility generally prohibits DHI and its subsidiaries from pre-paying, redeeming or repurchasing its outstanding debt or preferred stock. Notwithstanding this restriction, DHI may pre-pay, repurchase or redeem its remaining 2005 and 2006 senior notes and the Riverside facility. DHI also may pre-pay, repurchase or redeem its other senior unsecured notes and its second priority senior secured notes, subject to specified conditions.

We and our subsidiaries, excluding Illinois Power and its subsidiaries, are also prohibited from (i) permitting our Secured Debt/EBITDA Ratio (as defined in the credit facility) on and after September 30, 2004 to

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

exceed specified ratios; (ii) permitting our liquidity to be less than $200 million for a period of more than ten consecutive business days; or (iii) making capital expenditures during each four fiscal quarter period in excess of a designated amount, subject to specified exceptions.

The terms and conditions of the credit facility are described in more detail in the definitive agreements governing the credit facility, which are filed and/or incorporated by reference as exhibits to our second quarter 2004 Form 10-Q.

Repayments. For the nine months ended September 30, 2004, we repaid the $95 million aggregate principal amount of Illinova’s 7.125% Senior Notes due 2004. We also made principal repayments of $65 million related to Illinois Power’s transitional funding trust notes.

In the nine months ended September 2004, we made $97 million in pre-payments on the ChevronTexaco junior notes. Additionally, in October 2004, we used approximately $125 million of the proceeds from the sale of Illinois Power to mandatorily redeem all outstanding ChevronTexaco junior notes, as required by the indenture governing these notes.

Tilton Capital Lease. In September 1999, Illinois Power entered into an operating lease on four gas turbines located in Tilton, Illinois and a separate land lease at the Tilton site. This facility consists of peaking units totaling 176 MWs of capacity. Illinois Power sublet the turbines to DMG in October 1999.

In September 2003, we delivered notice of our intent to exercise our option in order for DMG to purchase the turbines upon the expiration of the operating lease in September 2004. Based on our intent to purchase, GAAP required that we reflect the asset and the associated debt on our balance sheets as a capital lease.

In July 2004, Illinois Power terminated its lease arrangement, and DMG purchased the turbines for $81 million. This action resulted in a reduction of debt of $78 million. The difference between the purchase price and the debt balance was recorded as an increase to property, plant and equipment of $3 million in our unaudited condensed consolidated balance sheets and represents the accretion to the end of the term of the original lease agreement.

ABG Gas Supply Credit Agreement. During 2004, we made scheduled payments of approximately $45 million related to our ABG Gas Supply financing. Additionally, in August 2004, we used $154 million in proceeds from our $600 million term loan to pre-pay all remaining indebtedness and other obligations under our ABG Gas Supply financing as required by the terms of our credit facility.

Note 7—Related Party Transactions

We engage in transactions with ChevronTexaco Corporation and its affiliates, including purchases and sales of natural gas and natural gas liquids, which we believe are executed on terms that are fair and reasonable. Please see Note 13—Related Party Transactions—Transactions with ChevronTexaco beginning on page F-48 of our Form 10-K/A for further discussion.

Series C Convertible Preferred Stock. As discussed in Note 15—Redeemable Preferred Securities—Series C Convertible Preferred Stock beginning on page F-53 of our Form 10-K/A, in August 2003 we issued 8 million shares of our Series C convertible preferred stock due 2033 to CUSA as a part of a restructuring of our Series B Preferred Stock. The restructuring resulted in a preferred stock dividend gain of $1.2 billion, reflected on the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2003.

We accrue dividends on our Series C convertible preferred stock at a rate of 5.5% per annum. We made the first semi-annual dividend payment of $11 million on February 11, 2004. On August 11, 2004, we made our second semi-annual dividend payment of $11 million.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

Note 8—Earnings Per Share

The reconciliation of basic earnings per share from continuing operations to diluted earnings per share from continuing operations is shown in the following table:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2004		2003			2004		2003
	(in millions, except per share amounts)
Income (loss) from continuing operations	$	80	$	4		$	163	$	(187	)
Less: convertible preferred stock dividends (gain)		6		(1,183	)		17		(1,018	)

Income from continuing operations for basic earnings per share		74		1,187			146		831
Effect of dilutive securities:
Interest on convertible subordinated debentures		2		1			5		1
Dividends on Series C convertible preferred stock		6		3			17		3
Dividends on Series B convertible preferred stock (1)		—		38			—		—

Income from continuing operations for diluted earnings per share	$	82	$	1,229		$	168	$	835

Basic weighted-average shares		379		375			378		373
Effect of dilutive securities:
Stock options		2		2			2		2
Convertible subordinated debentures		54		28			54		9
Series C convertible preferred stock		69		37			69		13
Series B convertible preferred stock (1)		—		22			—		—

Diluted weighted-average shares		504		464			503		397

Earnings per share from continuing operations:
Basic	$	0.20	$	3.17		$	0.39	$	2.23

Diluted	$	0.16	$	2.65		$	0.33	$	2.10

(1)

The diluted shares for the nine months ended September 30, 2003 do not include the effect of the preferential conversion to Class B common stock of the Series B Mandatorily Convertible Redeemable Preferred Stock previously held by a ChevronTexaco subsidiary, as such inclusion would be anti-dilutive.

Note 9—Commitments and Contingencies

PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS NOTE 9, WHICH WAS PRESENTED IN OUR THIRD QUARTER 2004 FORM 10-Q ORIGINALLY FILED WITH THE SEC ON NOVEMBER 15, 2004 IN ORDER TO REFLECT THE MATERIAL CHANGES IN OR UPDATES TO OUR MATERIAL LEGAL PROCEEDINGS SINCE THE ORIGINAL FILING OF OUR 2003 FORM 10-K, DOES NOT REFLECT EVENTS OCCURRING AFTER NOVEMBER 15, 2004. FOR A DESCRIPTION OF THESE EVENTS, INCLUDING MATERIAL CHANGES IN, OR UPDATES TO, OUR MATERIAL LEGAL PROCEEDINGS, PLEASE READ OUR EXCHANGE ACT REPORTS FILED SINCE NOVEMBER 15, 2004, INCLUDING OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO.

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 management’s opinion, the

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

disposition of these ordinary course matters will not materially adversely affect 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 under SFAS No. 5. During the first nine months of 2004, we recorded pre-tax legal and settlement charges of $61 million, including cash payments made in the period in excess of our then-existing accruals. The charges recorded relate to contingencies for which, during the period, either the amount of loss became probable and reasonably estimable or our previous loss estimates were adjusted.

For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Please read Note 1—Accounting Policies—Other Contingencies for further discussion of our reserve policies. Environmental reserves do not reflect management’s assessment of the insurance coverage that may be applicable to the matters at issue, whereas litigation reserves do reflect such potential coverage. We cannot make any assurances that the amount of any reserves or potential insurance coverage will be sufficient to cover the cash obligations we might incur as a result of litigation or regulatory proceedings, payment of which could be material.

With respect to some of the items listed below, management has determined that a loss is not probable or that any such loss, to the extent probable, is not reasonably estimable. In some cases, management is not able to predict with any degree of certainty the range of possible loss that could be incurred. Notwithstanding these facts, management has assessed each of these matters based on current information and made a judgment concerning its potential outcome, considering 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.

Summary of Recent Developments. As described in greater detail below, the following significant developments involving our material legal proceedings occurred since the original filing of our second quarter 2004 Form 10-Q:

•

We received the final approval from the FERC in October 2004 of the previously announced agreement on a comprehensive settlement of numerous contested FERC claims relating to western electric energy market transactions that occurred between January 2000 and June 2001. As part of the settlement, West Coast Power will forego its right to collect approximately $259 million in past-due receivables, plus interest, from the Cal ISO and the Cal PX related to the settlement period and pay $22.5 million in exchange for the dismissal of claims against Dynegy and West Coast Power related to the settlement period.

•

The judge presiding over our shareholder class action lawsuit entered an order in October 2004 dismissing a portion of the claims asserted by the plaintiff and substantially narrowing the class period to March 2001 through May 2002. Also in October 2004, the plaintiff dismissed its claim relating to a debt offering. The trial has been scheduled to begin in May 2005.

•

We reached a settlement with the plaintiff in our ERISA class action lawsuit, and the court granted preliminary approval of the settlement agreement in October 2004, scheduling a fairness hearing for December 2004. Under this proposed settlement, we would pay the plaintiff $30.75 million for a full and final release of all claims. We expect to pay this amount using insurance proceeds.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

•

Atlantigas Corporation, which recently dismissed its Maryland federal lawsuit, filed a class action lawsuit in West Virginia state court and filed an amended complaint in October 2004 naming us as a defendant. Plaintiff seeks unspecified compensatory and punitive damages resulting from allegations that, among other things, we conspired with the other defendants to receive preferential natural gas storage and transportation services at off-tariff prices.

The above summary of recent developments is qualified in its entirety by, and should be read in conjunction with, the following description of our significant legal proceedings.

Shareholder Litigation. We are defending a class action lawsuit filed on behalf of purchasers of our publicly traded securities from January 2000 to July 2002 seeking unspecified compensatory damages and other relief. The lawsuit principally asserts that we and certain of our current and former officers and directors violated the federal securities laws in connection with our disclosures, including accounting disclosures, regarding Project Alpha (a structured natural gas transaction entered into by us in April 2001), 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 our financial statements for 1999-2001. The Regents of the University of California are lead plaintiff and Lerach Coughlin Stoia & Robbins, LLP is class counsel. The plaintiff filed an amended complaint in January 2004 and, in March 2004, we filed motions to dismiss. Briefing on our motions was completed in June 2004. The judge entered an order on our motion in October 2004 dismissing all claims brought by the plaintiff under the Securities Act of 1933, except those relating to our March 2001 note offering and December 2001 common stock offering, and the Securities Exchange Act of 1934, except those dealing with Project Alpha and two alleged round-trip trades. The judge also narrowed the class period to cover purchasers of our publicly traded securities from March 2001 through May 2002 and scheduled the trial to commence in May 2005. Also in October 2004, the plaintiff voluntarily dismissed its claim under the Securities Act of 1933 relating to our March 2001 note offering. An adverse result in this litigation could have a material adverse effect on our financial condition, results of operations and cash flows. Reserves have been provided in connection with this litigation.

In addition, we are a nominal defendant in several derivative lawsuits brought by shareholders on Dynegy’s behalf against certain of our former officers and current and former directors whose claims are similar to those described above. These lawsuits have been consolidated into two groups—one pending in federal court and the other pending in state court. Our motion to dismiss the federal derivative claim is currently pending and is set for hearing in January 2005. We do not expect to incur any material liability with respect to these claims.

ERISA/401(k) Litigation. We are defending a purported class action complaint filed in federal district court on behalf of participants holding Dynegy common stock in the Dynegy 401(k) Savings Plan during the period from April 1999 to January 2003. This complaint alleges violations of ERISA in connection with our 401(k) Savings Plan, including claims that our Board and certain of our former and current officers, past and present members of our Benefit Plans Committee, former employees who served on a predecessor committee to our Benefit Plans Committee, and Vanguard Fiduciary Trust Company and CG Trust Company (trustees of the trust that held Plan assets for portions of the class period) breached their fiduciary duties to the Plan’s participants and beneficiaries in connection with the Plan’s investment in Dynegy common stock—in particular with respect to our financial statements, Project Alpha, round-trip trades and gas price index reporting. The lawsuit seeks unspecified damages for the losses to the Plan, as well as attorney’s fees and other costs. In July 2003, we filed a motion to dismiss this action. The judge entered an order on our motion in March 2004, dismissing several of the plaintiff’s claims and all of the defendants except Dynegy and the members of our Benefit Plans Committee from January 2002 to January 2003, the substantially reduced class period established by the order. In May 2004, in

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response to the plaintiff’s request, the judge ordered the parties to engage in mediation. The parties mediated for two months, and ultimately reached a settlement under which the defendants agreed to pay $30.75 million to the plaintiff for a full and final release of all claims. This amount falls within our applicable insurance limits, and we expect that the settlement will be paid by insurance proceeds. The Court granted preliminary approval of the settlement agreement in October 2004, tentatively scheduling a fairness hearing for December 2004 at which class members can participate and file any objections. We cannot predict with certainty what actions the Court may take in response to objections raised at the fairness hearings or, in the event the settlement is ultimately rejected, whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit absent the proposed settlement. In any case, 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.

Baldwin Station Litigation. Illinois Power and DMG are the subject of an NOV from the EPA and a complaint filed by the EPA and the Department of Justice in federal district court alleging violations of the Clean Air Act and related federal and Illinois regulations. Similar notices and complaints were filed against other owners of coal-fired power plants in what we refer to as the Utility Enforcement Initiative. Both the NOV and the complaint allege that certain equipment repairs, replacements and maintenance activities at our three Baldwin Station generating units constituted “major modifications” under the PSD regulations, the NSPS regulations and applicable Illinois regulations, and that we failed to obtain required operating permits under applicable Illinois regulations. When activities which are not otherwise exempt result in an increase in annual emissions that exceeds the amount deemed significant under the PSD regulations, those activities are considered “major modifications.” When activities meeting this definition occur, the Clean Air Act and related regulations generally subject those activities to PSD review and permit requirements and require that the generating facilities where the activities occur meet more stringent emissions standards, which may entail the installation of potentially costly pollution control equipment.

We have significantly reduced emissions of sulphur dioxide and nitrogen oxides at the Baldwin Station since the 1999 complaint by converting it from high to low sulfur coal and installing selective catalytic reduction equipment. However, the EPA may seek to require the installation of the “best available control technology,” or the equivalent, at the Baldwin Station, which we estimate could require us to incur capital expenditures of up to $410 million. 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.

In February 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 believe that we have meritorious defenses against the remaining claims and vigorously defended against them at trial. The trial to resolve claims of liability began in June 2003 and closing arguments occurred in September 2003. Shortly after closing arguments, several interveners were granted the right to file briefs in support of arguments they believe the United States ceased to pursue.

In October 2004, following the closing of the Illinois Power sale, Ameren caused Illinois Power to file a motion to stay the proceedings and to request a status conference in order to present its position on the claims asserted against it. These interventions, delays in post-trial briefing and the recent Illinois Power motion have postponed the issuance of the liability order, and we cannot predict with certainty when a decision will be rendered. Reserves have been provided in an aggregate amount we consider reasonable for potential penalties

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that could be imposed if the Court finds us liable and the EPA prosecutes successfully the remaining claims for penalties.

In August 2003, two significant decisions were handed down in other cases that are part of the Utility Enforcement Initiative. The court in United States v. Ohio Edison applied the EPA’s narrow interpretation of the “routine maintenance, repair and replacement” exclusion, which defines it with respect to what is routine for the specific unit where the projects occurred, while the court in United States v. Duke Energy Company rejected the EPA’s narrow interpretation, holding that the exclusion should be defined relative to what is routine for the particular industry. The Duke court also held that the hours and conditions of a unit’s operations must be held constant when measuring emissions increases. Under this rationale, an increase in maximum hourly emissions is required before activities would be considered “major modifications.” We are unable to predict the significance of these cases to our Baldwin Station litigation as they are pending in other jurisdictions and are not binding authority.

None of our other facilities are covered in the complaint and NOV, but the EPA previously requested information, which we provided, concerning activities at our Vermilion, Wood River, Hennepin, Danskammer and Roseton plants. Although the EPA could eventually commence enforcement actions based on activities at these plants, we are unable to assess the likelihood of any such additional EPA enforcement actions.

California Market Litigation. We and numerous other power generators and marketers are the subject of numerous lawsuits arising from our participation in the western power markets during the California energy crisis. Eight of these lawsuits, which primarily allege manipulation of the California wholesale power markets and seek unspecified treble damages, were consolidated before a single federal judge. That judge dismissed two of the cases in the first quarter 2003 on the grounds of FERC preemption and the filed rate doctrine. The Ninth Circuit Court of Appeals affirmed these dismissals in June 2004 and September 2004, respectively. An appeal from the Ninth Circuit’s affirmation of the September 2004 dismissal has been taken to the United States Supreme Court. Regarding the remaining six consolidated cases, we are awaiting a ruling from the Ninth Circuit, which we expect to occur prior to the end of 2004, on our appeal of a prior decision to remand those cases to state court.

In addition to the eight consolidated lawsuits discussed above, nine other putative class actions and/or representative actions were filed in state and federal court on behalf of business and residential electricity consumers against us and numerous other power generators and marketers between April and October 2002. The complaints allege unfair, unlawful and deceptive practices in violation of the California Unfair Business Practices Act and seek an injunction, restitution and unspecified damages. While some of the allegations in these lawsuits are similar to the allegations in the eight lawsuits described above, these lawsuits include additional allegations relating to, among other things, the validity of the contracts between these power generators and the CDWR. The court dismissed eight of these nine actions, although the plaintiffs have appealed, and the briefing on that appeal was completed in October 2004. A hearing on the appeal is scheduled for December 2004. The ninth case was remanded to state court, where a newly added defendant filed a motion in February 2004 to remove the case back to federal court. In September 2004, the court requested additional briefing on the remand issue, and the parties are complying with that request. Once a decision is made on this motion, we intend to file a motion to dismiss this case.

In December 2002, two additional actions were filed with similar allegations on behalf of residents of Washington and Oregon. In May 2003, the plaintiffs voluntarily dismissed these actions and refiled them in California Superior Court as a class action complaint. The complaint, which was brought on behalf of consumers

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and businesses in Oregon, Washington, Utah, Nevada, Idaho, New Mexico, Arizona and Montana that purchased energy from the California market, alleges violations of the Cartwright Act and unfair business practices. We have removed the action from state court and consolidated it with existing actions pending before the United States District Court for the Northern District of California. The hearing on plaintiffs’ appeal to remand to state court occurred in February 2004. The judge stayed his ruling on the appeal pending the Ninth Circuit’s ruling on the six consolidated cases referenced above.

In May 2004, Wah Chang, a division of TDY Industries, Inc., filed suit in Oregon federal court against several energy companies, including Dynegy Power Marketing, Inc., seeking more than $30 million in compensatory damages resulting from alleged manipulation of the California wholesale power markets. We filed a motion to dismiss this lawsuit in October 2004.

In June 2004, the City of Tacoma public utility filed a lawsuit in Washington federal court against a number of energy companies, including us, alleging it paid inflated prices for electricity due to the defendants’ manipulation of the California wholesale power markets. The Court has not yet set a schedule for this matter.

In July 2004, the County of Santa Clara and the County and City of San Francisco filed two separate actions in California state court against us and several other defendants alleging that the defendants violated California’s anti-trust and deceptive business practices statutes by manipulating the California wholesale power markets through, among other things, providing false information to gas index publications and engaging in multiple transactions in a short period of time to artificially inflate gas prices. In September 2004, these cases were consolidated into the In re Western States Wholesale Natural Gas Anti-Trust Litigation. Please read “—Gas Index Pricing Litigation” below for further discussion.

In September 2004, Dan Older, a retail consumer of natural gas, filed a purported class action against us and several other energy company defendants and utilities alleging that plaintiff paid artificially inflated prices as a result of the defendants’ illegal conduct. The plaintiff’s complaint raises allegations similar to those described in the preceding paragraph. Plaintiff seeks unspecified compensatory damages, as well as treble damages. In September 2004, this case was consolidated into the In re Western States Wholesale Natural Gas Anti-Trust Litigation. Please read “—Gas Index Pricing Litigation” below for further discussion.

In October 2004, Preferred Energy Services, an independent electric services provider in California, filed suit against us and several other defendants alleging that the defendants, in violation of the California anti-trust and unfair business practices statutes, engaged in unfair, unlawful and deceptive practices in the California wholesale energy market from May 2000 through December 2001. Plaintiff, which formerly sold electricity generated from renewable sources in the California market, claims to have been forced out of business by the defendants’ conduct and is seeking $5 million in compensatory damages, as well as treble damages. We have not yet been served with this lawsuit.

We believe that we have meritorious defenses to these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or estimate the range of possible loss, if any, that we might incur in connection with these lawsuits. However, given the nature of the claims, 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. In October 2004, the FERC approved in all respects the agreement announced by Dynegy and West Coast Power in April 2004 which

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provides for the settlement of FERC claims relating to western energy market transactions that occurred from January 2000 through June 2001, including:

•

the FERC’s June 2003 order to show cause why the activities of certain participants in the California power markets from January 2000 to June 2001, including Dynegy, did not constitute gaming and/or anomalous market behavior as defined in the Cal ISO and Cal PX tariffs, which matter was resolved by the January 2004 settlement providing that West Coast Power will pay approximately $3 million into a fund for the benefit of California and Western electricity consumers. This January 2004 settlement has been incorporated into the broader settlement described below; and

•

the FERC’s July 2001 hearings and October 2003 orders relating to the establishment of (i) refunds to electricity customers, or offsets against amounts owed to electricity suppliers, during the period of October 2000 through June 2001 and (ii) a methodology to calculate mitigated market clearing prices in the Cal ISO and the Cal PX markets.

The parties to this settlement other than Dynegy and West Coast Power include the FERC, Pacific Gas and Electric Company, Southern California Edison, San Diego Gas & Electric Company, the CDWR, the California Electricity Oversight Board and the California Attorney General. Other market participants may opt into this settlement and share in the distribution of the settlement proceeds. As part of the settlement agreement, West Coast Power will (i) forego its right to collect approximately $259 million in past-due receivables, plus interest, from the Cal ISO and the Cal PX related to the settlement period, (ii) forego natural gas cost recovery claims against the California settling parties related to the settlement period, and (iii) place into escrow accounts a total of $22.5 million, which includes the above-referenced $3 million settlement with the FERC staff, for subsequent distribution to various California energy purchasers. In exchange, the other settling parties will forego (i) all claims relating to refunds or other monetary damages for sales of electricity during the settlement period, and (ii) claims alleging receipt of unjust or unreasonable rates for the sale of electricity during the settlement period.

The settlement does not apply to the ongoing civil litigation related to the California energy markets described above in which Dynegy and West Coast Power are defendants. The settlement also does not apply to the pending appeal by the CPUC and the California Electricity Oversight Board of the FERC’s prior decision to affirm the validity of the West Coast Power-CDWR contract. We are currently awaiting a ruling on this appeal and related filings and cannot predict their outcome.

West Coast Power. Through our interest in West Coast Power, we have credit exposure for transactions to the Cal ISO, which rely on cash payments from California utilities to in turn pay their bills. In addition, West Coast Power currently sells directly to the CDWR pursuant to a long-term sales agreement which expires at the end of December 2004.

At September 30, 2004, our portion of the receivables owed to West Coast Power by the Cal ISO and Cal PX approximated $214 million. Management periodically assesses our exposure through West Coast Power, relative to our California receivables and establishes and maintains reserves under SFAS 5. Our share of the total reserve taken by West Coast Power, at September 30, 2004, with respect to receivables arising during the settlement period from January 2000 through June 2001 was approximately $194 million. The approval by the FERC in October 2004 of the above-described settlement resolved the claims and disputes which initially gave rise to this reserve at West Coast Power.

Enron Trade Credit Litigation. Shortly before their bankruptcy filing in the fourth quarter 2001, we determined that Enron Corp. and its affiliates had net exposure to us, including certain liquidated damages and

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other amounts relating to the termination of commercial transactions among the parties, of approximately $84 million. This exposure was calculated by setting off approximately $230 million owed from Dynegy entities to Enron entities against approximately $314 million owed from Enron entities to Dynegy entities. The master netting agreement between Enron and us 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. We are engaged in an ongoing process with Enron to reconcile the differences between our respective valuations of the transactions and accounts receivable. As a result of ongoing refinement of the values of past transactions, we reduced the $84 million amount that we originally believed we are owed by Enron to approximately $41 million, including the liabilities under the gas transportation agreement related to the Sithe Independence power tolling arrangement. This change in value had no impact on our results, as the net receivable was fully reserved in the fourth quarter 2001. As required by the master netting agreement, we instituted arbitration proceedings against those Enron parties not in bankruptcy in 2002 and 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 opposed our request and filed an adversary proceeding against us, alleging that the master netting agreement should not be enforced and that the Enron companies should recover approximately $230 million from us. We have disputed such allegations and are vigorously defending our position regarding the setoff rights contained in the master netting agreement, although the Bankruptcy Court has yet to rule on the enforceability of the master netting agreement.

In November 2003, we gave notice of our intent to pursue arbitration against Enron Canada Corp. as a non-bankrupt party to the master netting agreement. In response, Enron Canada Corp. filed a lawsuit in Canadian District Court to recover the amounts that it claims to be owed by our Canadian subsidiary under the master netting agreement, contingent upon a Bankruptcy Court ruling on the enforceability of the master netting agreement. In December 2003, Enron filed an application with the Bankruptcy Court for an injunction to prohibit this arbitration; the Bankruptcy Court ruled that the automatic stay of the bankruptcy applied to our request to pursue arbitration against Enron Canada Corp. under the master netting agreement. Consequently, we are currently prohibited from enforcing the master netting agreement by arbitration. In March 2004, we appealed the enforcement of the automatic stay and requested permission from the appellate court to proceed with arbitration against Enron Canada Corp. We also filed a motion with the Bankruptcy Court requesting a trial to determine the enforceability of the master netting agreement under the U.S. Bankruptcy Code. We are currently awaiting rulings on the appeal and the motion. The Bankruptcy Court has ordered the parties to a second mediation, which is scheduled to occur in November 2004.

If the setoff rights are modified or disallowed, either by agreement or otherwise, the amount available for our entities to set off against sums that might be due Enron entities could be reduced materially. In fact, we could be required to pay to Enron the full amount that it claims to be owed, while we would be an unsecured creditor of Enron to the extent of our claim. We cannot predict with certainty whether we will incur any liability in connection with these disputes. However, given the size of the claims at issue, an adverse result could have a material adverse effect on our financial condition, results of operations and cash flows.

Severance Arbitrations. Our former CEO, Chuck Watson, former President, Steve Bergstrom, and former CFO, Rob Doty, each filed for arbitration pursuant to the terms of their employment/severance agreements. These former officers made arbitration claims seeking payments of up to approximately $28.7 million, $10.4 million and $3.4 million, respectively. In May 2004, following arbitration, we paid Mr. Bergstrom $10.4 million plus attorneys’ fees, costs and interest in accordance with the arbitration panel’s decisions. Shortly after the panel’s decisions in the Bergstrom matter and following mediation, we paid Mr. Watson $22 million to settle his severance claims. We recorded an expense in the second quarter 2004 in the amount of the difference between

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this settlement amount and our severance accrual for this matter. Please read Note 3—Restructuring Charges for further discussion regarding the accrual relating to Mr. Watson.

The arbitration with respect to Mr. Doty is scheduled to commence in May 2005. Mr. Doty’s agreement is subject to interpretation and we maintain that the amount owed is substantially lower than the amount sought. We recorded a severance accrual we consider reasonable relating to this proceeding.

Farnsworth Litigation. In August 2002, Bradley Farnsworth filed a lawsuit against us in state 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. Specifically, Mr. Farnsworth alleged, 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. In March 2004, the judge dismissed Mr. Farnsworth’s claim that he was asked to “shave” forward price curves. Under his remaining breach of contract claim, Mr. Farnsworth alleges he is entitled to a termination payment under his employment agreement, which he estimates at $11 million, 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. The agreement is subject to interpretation and we maintain that the amount owed is substantially lower than the amount sought. Trial on the breach of contract claim is scheduled to commence in November 2004. We are defending this claim vigorously. Although reserves have been provided 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 or cash flows.

Apache Litigation. In May 2002, Apache Corporation filed suit in state court against Versado, as purchaser and processor of Apache’s gas, and DMS, as operator of the Versado assets in New Mexico, seeking more than $9 million in damages. The plaintiff’s petition, as amended, alleges (i) excessive field losses of natural gas from wells owned by the plaintiff, (ii) that Versado engaged in “sham” transactions with affiliates, resulting in Versado not receiving fair market value when it sells gas and liquids, and (iii) 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. At trial, the plaintiff’s claim with respect to the alleged “sham” transactions and index manipulation, among others, were severed by the court and abated for a future trial, and the jury found in favor of the plaintiff on the remaining lost gas claim, awarding approximately $1.6 million in damages. In May 2004, our motion to set aside this judgment was granted by the court and the jury’s award to the plaintiff was vacated. The plaintiff filed its appeal with the court in October 2004. 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.

Gas Index Pricing Litigation. We are defending the following suits claiming damages resulting from the alleged manipulation of gas index publications and prices by us and others: Sierra Pacific Resources and Nevada Power Company v. El Paso Corp. et al.; Bustamante v. The McGraw Hill Companies et al.; In re Natural Gas Commodity Litigation (a consolidation of two cases); People of the State of Montana et al. v. Williams Energy Marketing et al; In re Western States Wholesale Natural Gas Anti-Trust Litigation (a consolidation of seven cases); and Nelson Brothers LLC v. Cherokee Nitrogen v. Dynegy Marketing and Trade and Dynegy Inc. In each of these suits, the plaintiffs allege that we and other energy companies engaged in an illegal scheme to inflate natural gas prices by providing false information to gas index publications, thereby manipulating the price. All of the complaints rely heavily on the FERC and CFTC investigations into and report concerning index-reporting

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manipulation in the energy industry. The plaintiffs generally seek unspecified actual and punitive damages relating to costs they claim to have incurred as a result of the alleged conduct. These cases are in varying procedural stages, although we have not been served in the Montana case.

We are analyzing all of these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or to estimate the damages, if any, that might be incurred in connection with these lawsuits. We do not believe that any liability that 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.

Atlantigas Corp. Litigation. In November 2003, Atlantigas Corporation filed suit in Maryland against us and several other defendants alleging certain conspiracies between natural gas shippers and storage facilities. The complaint alleged that the interstate pipelines provided preferential storage and transportation services to their own unregulated marketing affiliate in return for percentages of the profits reaped by the marketing affiliate and that such conduct violated applicable FERC regulations and the federal antitrust laws and constituted common law tortious interference with contractual and business relations. In addition, the complaint claimed we conspired with the other defendants to receive preferential natural gas storage and transportation services at off-tariff prices. The complaint sought unspecified compensatory and punitive damages. In January 2004, the defendants filed motions to dismiss the plaintiff’s claims. In July 2004, prior to the Court’s ruling on the defendants’ motions, the plaintiff voluntarily dismissed the Maryland federal court action against all defendants. Shortly thereafter, plaintiff filed a class action lawsuit in a West Virginia state court against several defendants, excluding us, on similar grounds to the previous Maryland federal action. In October 2004, the plaintiff filed an amended class action complaint naming us as a defendant in the litigation. We are analyzing these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or to estimate the damages, if any, that might be incurred in connection with these lawsuits. We do not believe that any liability that 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.

Stumpf Litigation. We and two former subsidiaries are defendants in a lawsuit filed in New York by Stumpf AG and two of its affiliates stemming from the shutdown of our Vienna telecommunications office in the spring of 2001. The plaintiffs are seeking $29 million in compensatory and unspecified punitive damages, alleging breach of contract, tortious interference and alter ego-based claims primarily relating to the termination of real property leases to which our former Austrian subsidiary was a party. These claims are based on similar lawsuits filed in Austria against our former Austrian subsidiary, which was sold to a third party in January 2003. This former subsidiary is in liquidation and, recently, one of its liquidators admitted, for purposes of the liquidation, the plaintiffs’ claims in the amount of $30 million. Although this lawsuit was initially stayed pending the Austrian insolvency proceeding, the stay was lifted and we filed our answer in May 2004. The parties are actively engaged in discovery.

We intend to oppose these claims vigorously and believe we have meritorious defenses. Although it is not possible to predict with certainty whether we will incur any liability in connection with these lawsuits, we do not believe that any liability we might incur as a result of these lawsuits would have a material adverse effect on our financial condition, results of operations or cash flows. Reserves have been provided in connection with this litigation.

Alleged Marketing Contract Defaults. We have posted collateral to support a portion of our obligations in our CRM business, including our obligations under one of our power tolling arrangements. While we worked with various counterparties to provide mutually acceptable collateral or other adequate assurance under these

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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 previously received a notice of default from each such party with regard to collateral. Despite receiving these notices, all parties are continuing to perform and we have fulfilled our economic commitments under these contracts. 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, with a five-year extension option for Sterlington. If these two parties were successfully to pursue claims that we defaulted on these contracts, they could declare a termination of their respective contracts, which generally 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.

U.S. Attorney Investigations. The U.S. Attorney’s office in Houston is continuing its investigation of our actions relating to Project Alpha and our gas trade reporting practices. We have produced documents and witnesses for interviews in connection with this investigation. Seven of our natural gas traders were terminated in the fourth quarter 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. In January 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. In August 2003, however, several of these counts were dismissed as unconstitutional. Upon request by the U.S. Attorney’s office for reconsideration of this ruling, the judge reinstated the dismissed counts. The case was originally set for trial in January 2004; however, both the U.S. Attorney’s office and the defense have appealed the court’s rulings regarding the dismissed and reinstated charges. The Fifth Circuit Court of Appeals heard argument on these matters in October 2004, and the parties are awaiting its ruling.

In June 2003, three former Dynegy employees were indicted on charges of conspiracy, securities fraud and mail and wire fraud related to the Project Alpha transaction. Subsequently, two of these former employees plead guilty to conspiracy to commit securities fraud. These former employees have not been sentenced pending the completion of the government’s investigation. Trial on the indictment against the third employee was held in November 2003. The defendant was convicted on all charges and, in March 2004, sentenced to a term of approximately 24 years in federal prison.

We are cooperating fully with the U.S. Attorney’s office in its continuing investigation 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 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.

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 we maintain and our ERISA

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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 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.

Danskammer Water Permit. As previously disclosed, the state-issued water intake and discharge permit associated with our Danskammer facility expired in 1992. However, under New York State law, each permit remains in effect and allows for continued operation under the terms of the original permit, provided that a timely and sufficient application requesting renewal has been filed as required. In May 1992, the then owner of the Danskammer facility filed a renewal application which we believe was timely and sufficient.

In November 2002, several environmental groups filed suit in the Supreme Court of the State of New York seeking, among other things, a declaratory judgment that the Danskammer water intake and discharge permit expired because of alleged deficiencies in the renewal application process. In September 2004, the Court ruled that the water intake and discharge permit for our Danskammer facility is void, but stayed the enforcement of the decision pending further review by the Court or by the Appellate Division.

In October 2004, we filed our appeal of the Court’s decision with the Appellate Division, and we intend to pursue vigorously our challenge to the Court’s ruling voiding our permit. We will also continue to seek approval of our application to renew the water intake and discharge permit in proceedings before the New York State Department of Environmental Conservation. If our appeal is ultimately unsuccessful, we may be required to curtail operations at our Danskammer facility pending receipt of final approval of the renewal of our water intake and discharge permit. We cannot predict with any certainty the outcome of these proceedings; however, an adverse outcome, particularly a requirement that we curtail operations at our Danskammer facility for any period of time, could have a material adverse effect on our financial condition, results of operations and cash flows.

FERC Market-Based Rate Authority. Market-based rate authority allows the sale of power at negotiated rates through the bilateral market or within an organized energy market. In April 2004, the FERC issued an order concerning the ability of companies to sell electricity at market-based rates. In this order, the FERC adopted two new tests for assessing generation market power. If an applicant for market-based rate authority is found to possess generation market power under these tests and is unsuccessful in challenging that finding, the applicant may either propose mitigation measures or adopt cost-based rates. If the FERC finds that the proposed mitigation measures fail to eliminate the ability to exercise market power, the applicant’s market-based rate authority will be revoked and the applicant will be subject to cost-based default rates, or other cost-based rates proposed by the applicant and approved by the FERC. The FERC issued a follow up order in May 2004, which (i) addressed the

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

implementation process for pending and new market-based rate applications and (ii) established a timeline for entities with FERC market-based rate authority to provide the FERC with their market power assessment. Despite challenges from numerous industry participants, in July 2004 the FERC upheld the April 2004 order. These orders require entities that were previously granted market-based rate authority by the FERC, including several Dynegy entities with applications pending since February 2002, to resubmit their market power applications in accordance with the new directive by February 5, 2005. Although we cannot predict with any certainty whether these applications will be approved or the loss of revenues that would result from the imposition of cost-based rates, an adverse outcome with respect to these applications, and the resulting requirement that we charge cost-based rates, could have a material adverse effect on our financial condition, results of operations and cash flows.

Note 11—Employee Compensation, Savings and Pension Plans

We have various defined benefit pension plans and post-retirement benefit plans, which are more fully described in Note 20—Employee Compensation, Savings and Pension Plans beginning on page F-74 of our Form 10-K/A.

Components of Net Periodic Benefit Cost. The components of net periodic benefit cost were:


	Pension Benefits						Other Benefits
	Three Months Ended September 30,
	2004			2003			2004			2003
	(in millions)
Service cost benefits earned during period	$	6		$	5		$	1		$	1
Interest cost on projected benefit obligation		10			10			3			3
Expected return on plan assets		(12	)		(13	)		(2	)		(1	)
Recognized net actuarial loss		4			2			2			1
Settlement and curtailment (gain) loss		144			—			(8	)		—

Total net periodic benefit cost (benefit)	$	152		$	4		$	(4	)	$	4


	Pension Benefits						Other Benefits
	Nine Months Ended September 30,
	2004			2003			2004			2003
	(in millions)
Service cost benefits earned during period	$	18		$	16		$	4		$	3
Interest cost on projected benefit obligation		31			30			9			8
Expected return on plan assets		(37	)		(40	)		(5	)		(4	)
Recognized net actuarial loss		12			7			4			4
Settlement and curtailment (gain) loss		144			—			(8	)		—

Total net periodic benefit cost	$	168		$	13		$	4		$	11

The settlement and curtailment (gain) loss is a result of the sale of Illinois Power, and resulting reduction in plan participants, and is included in the loss on its sale. For further information see Note 2—Acquisitions, Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Sale of Illinois Power.

Contributions. In Note 20—Employee Compensation, Savings and Pension Plans—Contributions beginning on page F-79 of our Form 10-K/A, we reported that we expected to contribute approximately $13 million to our

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

pension and other postretirement benefit plans in 2004. Due to the Pension Funding Equity Act of 2004, we are no longer required to make estimated quarterly contributions in 2004. However, under the terms of our agreement to sell Illinois Power to Ameren, we accelerated approximately $7 million of future cash funding requirements in September 2004.

Note 12—Income Taxes

Capital Loss Valuation Allowance. As a result of the asset sales discussed in Note 2—Acquisitions, Dispositions, Contract Terminations and Discontinued Operations, as well as other transactions forecasted to occur during the remainder of 2004, we reduced the valuation allowance related to our significant capital loss carryforward by $11 million and $58 million in the three and nine months ended September 30, 2004, respectively. This capital loss carryforward primarily related to our third quarter 2002 sale of Northern Natural Gas Company. This benefit is reflected in Income tax benefit (expense) on our unaudited condensed consolidated statements of operations.

Prior Year Tax Audits. In the second quarter 2004, we recognized an expense of $17 million associated with the conclusion of prior year federal tax audits. A charge of $20 million related to our discontinued U.K. CRM business is included in Loss from discontinued operations on our unaudited condensed consolidated statements of operations for the nine months ended September 30, 2004. An offsetting benefit of $3 million is reflected in Income tax benefit (expense) on our unaudited condensed consolidated statements of operations.

Note 13—Segment Information

We report our operations in the following segments: GEN, NGL, REG and CRM. All direct general and administrative expenses and other income (expense) items incurred by us on behalf of our subsidiaries are charged to the applicable subsidiary as incurred.

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, referred to as the WEN segment. Most, but not all, of the WEN third-party purchase and sale contracts were held by a subsidiary that became part of the CRM segment. When we began reporting results for the GEN and CRM segments, CRM continued to transact with third parties on behalf of GEN. When transacting on behalf of GEN and our other segments, CRM would record third party revenue related to GEN and our other segments, together with its other third-party marketing and trading positions unrelated to our other segments. Transfer pricing between CRM and our other segments was set at the actual amount received or paid for the purchases and sales to the third parties. Therefore, our other segments intersegment revenues included the effects of intra-month market price volatility, and represented amounts actually received from or paid to third parties.

Effective July 1, 2004, GEN began transacting directly with third parties on its own behalf. Therefore, certain generation capacity, forward sales, and related market positions previously sold by GEN to CRM are now sold by GEN directly to third parties. The GEN segment now records revenues for such third party sales as unaffiliated revenues.

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 unaudited 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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

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. In addition, intersegment hedging activities are presented net pursuant to SFAS No. 133.

Reportable segment information for the three- and nine-month periods ended September 30, 2004 and 2003 is presented below:

Dynegy’s Segment Data for the Quarter Ended September 30, 2004

(in millions)


	GEN			NGL			REG			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	273		$	920		$	377		$	94		$	—		$	1,664
Other		—			—			—			(14	)		—			(14	)

		273			920			377			80			—			1,650
Intersegment revenues		156			76			6			(71	)		(167	)		—

Total revenues	$	429		$	996		$	383		$	9		$	(167	)	$	1,650


Depreciation and amortization	$	(50	)	$	(21	)	$	—		$	(1	)	$	(7	)	$	(79	)
Operating income (loss)	$	71		$	72		$	83		$	(32	)	$	(55	)	$	139
Earnings from unconsolidated investments		99			3			—			—			—			102
Other items, net		—			(6	)		2			(3	)		1			(6	)
Interest expense																	(125	)

Income from continuing operations before taxes																	110
Income tax expense																	(30	)

Income from continuing operations																	80
Loss from discontinued operations, net of taxes																	(2	)

Net income																$	78

Identifiable assets:
Domestic	$	6,449		$	1,809		$	18		$	1,667		$	560		$	10,503
Other		3			4			—			192			29			228

Total	$	6,452		$	1,813		$	18		$	1,859		$	589		$	10,731

Unconsolidated investments	$	381		$	78		$	—		$	—		$	—		$	459

Capital expenditures	$	(20	)	$	(14	)	$	(31	)	$	—		$	(5	)	$	(70	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

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

(in millions)


	GEN			NGL			REG			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	65		$	620		$	394		$	352		$	—		$	1,431
Other		—			3			—			(49	)		—			(46	)

		65			623			394			303			—			1,385
Intersegment revenues		410			58			8			(301	)		(175	)		—

Total revenues	$	475		$	681		$	402		$	2		$	(175	)	$	1,385

Depreciation and amortization	$	(48	)	$	(19	)	$	(30	)	$	—		$	(12	)	$	(109	)

Operating income (loss)	$	77		$	31		$	64		$	(26	)	$	(45	)	$	101
Earnings (losses) from unconsolidated investments		51			2			—			(2	)		—			51
Other items, net		1			(2	)		—			4			(3	)		—
Interest expense																	(145	)

Income from continuing operations before taxes																	7
Income tax expense																	(3	)

Income from continuing operations																	4
Income from discontinued operations, net of taxes																	1

Net Income																$	5

Identifiable assets:
Domestic	$	6,380		$	1,679		$	5,408		$	2,357		$	(2,315	)	$	13,509
Other		—			—			—			297			35			332

Total	$	6,380		$	1,679		$	5,408		$	2,654		$	(2,280	)	$	13,841

Unconsolidated investments	$	573		$	95		$	—		$	—		$	—		$	668

Capital expenditures	$	(24	)	$	(11	)	$	(33	)	$	—		$	(2	)	$	(70	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

Dynegy’s Segment Data for the Nine Months Ended September 30, 2004

(in millions)


	GEN			NGL			REG			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	373		$	2,440		$	1,146		$	868		$	—		$	4,827
Other		2			2			—			(84	)		—			(80	)

		375			2,442			1,146			784			—			4,747
Intersegment revenues		910			221			19			(613	)		(537	)		—

Total revenues	$	1,285		$	2,663		$	1,165		$	171		$	(537	)	$	4,747

Depreciation and amortization	$	(145	)	$	(66	)	$	(10	)	$	(1	)	$	(27	)	$	(249	)
Impairment and other charges		—			(5	)		(54	)		—			(24	)		(83	)

Operating income (loss)	$	159		$	214		$	158		$	45		$	(197	)	$	379
Earnings from unconsolidated investments		187			7			—			—			—			194
Other items, net		—			(15	)		3			(1	)		4			(9	)
Interest expense																	(402	)

Income from continuing operations before taxes																	162
Income tax benefit																	1

Income from continuing operations																	163
Loss from discontinued operations, net of taxes																	(7	)

Net income																$	156

Identifiable assets:
Domestic	$	6,449		$	1,809		$	18		$	1,667		$	560		$	10,503
Other		3			4			—			192			29			228

Total	$	6,452		$	1,813		$	18		$	1,859		$	589		$	10,731

Unconsolidated investments	$	381		$	78		$	—		$	—		$	—		$	459

Capital expenditures	$	(78	)	$	(41	)	$	(92	)	$	—		$	(10	)	$	(221	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Restated and Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

Dynegy’s Segment Data for the Nine Months Ended September 30, 2003

(in millions)


	GEN			NGL			REG			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	286		$	2,218		$	1,170		$	698		$	—		$	4,372
Other		—			3			—			(44	)		—			(41	)

		286			2,221			1,170			654			—			4,331
Intersegment revenues		940			193			22			(790	)		(365	)		—

Total revenues	$	1,226		$	2,414		$	1,192		$	(136	)	$	(365	)	$	4,331

Depreciation and amortization	$	(138	)	$	(60	)	$	(91	)	$	(1	)	$	(50	)	$	(340	)
Operating income (loss)	$	176		$	121		$	158		$	(348	)	$	(193	)	$	(86	)
Earnings from unconsolidated investments		135			7			—			—			—			142
Other items, net		4			(12	)		—			27			(7	)		12
Interest expense																	(364	)

Loss from continuing operations before taxes																	(296	)
Income tax benefit																	109

Loss from continuing operations																	(187	)
Loss from discontinued operations, net of taxes																	(6	)
Cumulative effect of change in accounting principles, net of taxes																	55

Net loss																$	(138	)

Identifiable assets:
Domestic	$	6,380		$	1,679		$	5,408		$	2,357		$	(2,315	)	$	13,509
Other		—			—			—			297			35			332

Total	$	6,380		$	1,679		$	5,408		$	2,654		$	(2,280	)	$	13,841

Unconsolidated investments	$	573		$	95		$	—		$	—		$	—		$	668
Capital expenditures	$	(117	)	$	(36	)	$	(101	)	$	—		$	(5	)	$	(259	)

Note 14—Subsequent Events

In October 2004, we paid approximately $125 million to mandatorily redeem all outstanding ChevronTexaco junior notes. Please read Note 6—Debt for further discussion.

On October 22, 2004, the American Jobs Creation Act of 2004 was signed into law. This legislation contains a number of changes to the Internal Revenue Code that may affect us. We are in the process of analyzing the law in order to determine its effects. At this time we do not expect any material impact on our consolidated financial statements from this legislation.

In November 2004, we entered into an agreement to purchase from Exelon Corporation all of the outstanding capital stock of ExRes SHC, Inc., the parent company of Sithe Energies and Sithe Independence, L.P. Please read Note 2—Acquisitions, Dispositions, Contract Terminations and Discontinued Operations—Acquisitions—Sithe Energies for further discussion.

In November 2004, we sold our Sherman natural gas processing facility located in Sherman, Texas. Please read Note 2—Acquisitions, Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Sherman.

Item 4—CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. Effective as of the end of the third quarter 2004, 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 the various processes carried out under the direction of our disclosure 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 considered the work completed as of the end of the third quarter 2004 relating to our efforts to achieve compliance with Section 404 of the Sarbanes-Oxley Act of 2002, which is further described below. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective at the reasonable assurance level and designed to ensure that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the requisite time periods. While our disclosure controls and procedures provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.

Changes in Internal Controls. There were no changes in our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of our internal controls performed during the third quarter 2004, other than those noted below, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

During the second and third quarter 2004, we identified deficiencies in our internal controls over financial reporting, including matters relating to system access and system implementation controls, segregation of duties and documentation of controls and procedures and their effective operation and monitoring. We also identified deficiencies in our tax accounting and tax reconciliation controls and processes that make this an area of particular focus. In the third quarter 2004, we determined that adjustments related to our deferred income tax accounts in periods prior to 2004 were required. We identified these deficiencies and promptly brought them to the attention of our audit and compliance committee and independent auditors. Accordingly, in the Original Filing, as amended by this Form 10-Q/A, we have revised our unaudited condensed consolidated balance sheet at December 31, 2003 to reflect a reduction to our deferred tax liability of $154 million. We believe we have addressed these tax deficiencies, by taking the following steps to improve our internal controls around our tax accounting and tax reconciliation controls and processes:

•

Increased the levels of review in the preparation of the quarterly and annual tax provision;

•

Formalized processes, procedures and documentation standards; and

•

Restructured our Tax Department to ensure appropriate segregation of duties regarding preparation and review of the quarterly and annual tax provision.

Beginning with the year ending December 31, 2004, Section 404 of the Sarbanes-Oxley Act of 2002 requires us to provide an annual internal controls report of management. This report must contain (i) a statement of management’s responsibility for establishing and maintaining adequate internal controls over financial reporting for our company, (ii) a statement identifying the framework used by management to conduct the required evaluation of the effectiveness of our internal controls over financial reporting, (iii) management’s assessment of the effectiveness of our internal controls over financial reporting as of the end of our most recent fiscal year, including a statement as to whether or not our internal controls over financial reporting are effective, and (iv) a statement that our independent auditors have issued an attestation report on management’s assessment of our internal controls over financial reporting. Additionally, Section 404 requires that our independent auditors attest to and report on management’s assessment of our internal controls over financial reporting. In seeking to achieve compliance with Section 404 within the prescribed period, management formed an internal control steering committee, engaged outside consultants and adopted and implemented a detailed project work plan to

assess the adequacy of our internal controls over financial reporting, remediate any control weaknesses that may be identified, validate through testing that controls are functioning as documented and implement a continuous reporting and improvement process for internal controls over financial reporting.

Additionally, the Public Company Accounting Oversight Board recently adopted very stringent standards governing management’s required evaluation of its internal controls over financial reporting and the independent auditors’ review of those controls and management’s evaluation thereof. These standards will likely result in a significant number of companies, which may include Dynegy, identifying significant deficiencies and/or material weaknesses in their internal controls. Indeed, the items referenced in the preceding paragraphs could preclude our independent auditors from delivering an unqualified opinion on internal controls under Section 404 of Sarbanes-Oxley.

DYNEGY INC.

PART II. OTHER INFORMATION

Item 6—EXHIBITS

The following documents are included as exhibits to this Form 10-Q/A:


** 10.1		Power Purchase Agreement dated September 30, 2004 between Illinois Power Company and Dynegy Power Marketing, Inc.

** 10.2		Escrow Agreement dated as of September 30, 2004 among Illinova Corporation, Ameren Corporation and JPMorgan Chase Bank, as escrow agent.

+ 31.1		Chief Executive Officer 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		Chief Financial Officer 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		Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2		Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

+	Filed herewith.

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.

**	Previously filed.

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: January 19, 2005	By:	/s/ NICK J. CARUSO
		Nick J. Caruso
		Executive Vice President and Chief Financial Officer
		(Duly Authorized Officer and Principal Financial Officer)