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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended September 30, 2004

For the transition period from              to             

Commission file number: 000-29311

DYNEGY HOLDINGS INC.

(Exact name of registrant as specified in its charter)

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  ¨    No  x

All of the registrant’s outstanding stock is owned, directly or indirectly by Dynegy Inc.

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DYNEGY HOLDINGS INC.

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Explanatory Note

On September 23, 2004, we filed a Current Report on Form 8-K with the SEC 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 deferred income tax accounts. As a result of our inability to complete our review of our deferred income tax accounts prior to the filing of this report, the financial statements accompanying this report do not reflect the effects of this item and have not been reviewed by an independent public accountant under Rule 10-01(d) of Regulation S-X. We expect that our independent public accountant, PricewaterhouseCoopers LLP, will complete the quarterly review required by Rule 10-01(d) of Regulation S-X following the issuance of restated financial statements contained in our third quarter 2004 Form 10-Q.

Also as a result of our inability to complete our deferred income tax account review and reflect its effects in our financial statements, this report is not accompanied by the certifications required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 and Rule 13a-14 and 15d-14 of the Securities Exchange Act of 1934, as amended. As soon as practicable following the date of this report, we expect to file an amendment to this report which includes these certifications, as well as amendments to our 2003 Form 10-K and first and second quarter 2004 Form 10-Qs.

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DEFINITIONS

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

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions)

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions)

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(unaudited) (in millions)

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

Introductory Note

On September 23, 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 deferred income tax accounts. The financial information in this report has not been revised to reflect the effects of this item. We expect to file amendments to our 2003 Form 10-K and first, second and third quarter 2004 Form 10-Qs as soon as practicable after the date of this report.

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, except that they have not been reviewed by an independent public accountant under Rule 10-01(d) of Regulation S-X. 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 and the Introductory 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, except for the deferred income tax accounts adjustment, as described in the Introductory Note above. The results of operations for the interim periods presented in this Form 10-Q 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 the realization of tax assets and (5) determining amounts to accrue for contingencies. 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 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.

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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

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 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 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.

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:

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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

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.

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 and NGL 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. Shipping and handling costs are included in revenue when billed to customers with the sale of products.

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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

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.

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

Income Taxes. Dynegy, our parent, files a consolidated U.S. federal income tax return and, for financial reporting purposes, accounts 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.

We are included in the consolidated federal and state income tax returns filed by Dynegy. Pursuant to tax allocation arrangements, we record a receivable in an amount equal to the tax benefits realized in Dynegy’s consolidated federal income tax return resulting from the utilization of our net operating losses and/or tax credits, or record a payable to Dynegy in an amount equal to the federal income tax computed on our separate company taxable income less the tax benefits associated with net operating losses and/or tax credits generated by us which are utilized in Dynegy’s consolidated federal income tax return.

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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

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 income (loss) in stockholder’s 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 $2 million and $1 million for the three months ended September 30, 2004 and 2003, respectively, and gains of $1 million and $10 million for the nine months ended September 30, 2004 and 2003, respectively.

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.

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):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 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 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 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 and $10 million for our NGL 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 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 Illinois Power 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

stock-based employee compensation. Although we do not grant stock options to our employees, these employees do participate in Dynegy’s stock-based employee compensation programs. 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 by Dynegy 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 recognized compensation expense over the applicable vesting periods for in-the-money stock options Dynegy previously granted. No in-the-money stock options have been granted by Dynegy since 1999.

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) would have approximated the following pro forma amounts for the three- and nine-month periods ended September 30, 2004 and 2003, respectively.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

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 stockholder’s 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.

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, Dynegy 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003

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, Dynegy 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, Dynegy 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 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. At the time of closing, ExRes SHC, Inc. will not be consolidated by us. The acquisition transforms the tolling and swap contracts into Dynegy intercompany and our affiliate agreements. Other than the reporting of the transactions with Sithe Independence, L.P. as affiliate transactions, we do not anticipate any other material impact to us from the transaction.

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 and Power Purchase Agreement. On September 30, 2004, Dynegy sold all of its outstanding common and preferred shares of Illinois Power Company, owned by Illinova Corporation, its subsidiary, as well as its 20% interest in the Joppa power generation facility, to Ameren for $2.3 billion. Concurrent with that sale, 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.

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

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$36 million. This gain 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 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 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:

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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. 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 11—Income Taxes for further discussion.

Note 3—Restructuring Charges

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:

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 Dynegy’s former chief executive officer and Dynegy’s former president. Cash payments during 2004 reflect payments made to Dynegy’s former chief executive officer and Dynegy’s former president. Please see Note 8—Commitments and Contingencies—Severance Arbitrations for further discussion regarding the status of these claims and settlement payments.

We expect the $26 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-22 of our Form 10-K.

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

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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. 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 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 stockholder’s equity were recognized in income, resulting in an after-tax loss of approximately $5 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 stockholder’s equity.

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

Note 5—Unconsolidated Investments

A summary of our unconsolidated investments is as follows:

Summarized aggregate financial information for West Coast Power and our equity share thereof was:

Summarized aggregate financial information for unconsolidated equity investments, exclusive of the West Coast Power information above, and our equity share thereof was:

Earnings from unconsolidated investments of $117 million for the nine months ended September 30, 2004 include $123 million from West Coast Power and the $33 million above and gains on the sales of our equity investment in Oyster Creek and Hartwell of $15 million and $2 million, respectively. These gains were partially

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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 $3 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 $140 million for the nine months ended September 30, 2003 consist of $102 million from West Coast Power and the $41 million above, partially offset by $3 million in losses due to impairments of cost investments.

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

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, we entered into a $1.3 billion credit facility consisting of:

The credit facility replaced our $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 our 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.

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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 our 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). We 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 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 us; 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. Dynegy Inc. and substantially all of its subsidiaries also guarantee this facility.

The credit facility contains affirmative and negative covenants, including negative covenants relating to the following which restrict us and our subsidiaries but do not restrict Dynegy: 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. We are currently in compliance with these restrictive covenants, with the exception of our filing of this report without (i) the requisite review of the accompanying financial statements by our independent auditor and (ii) the certifications mandated by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 and Rule 13a-14 and 15d-14 of the Securities Exchange Act of 1934, as amended, which may not constitute compliance with our obligation under the indenture to file with the SEC a quarterly report prepared in all material respects in accordance with all of the rules and regulations applicable thereto. Notwithstanding this possible non-compliance, we expect to file an amendment to this report with the required review and certifications prior to the expiration of the applicable cure period in the indenture.

The credit facility generally prohibits us and our subsidiaries, subject to specified exceptions, from incurring additional debt. Notwithstanding this restriction, we may issue, to the extent permitted by the more restrictive covenants with respect to secured debt in the indenture governing our 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.

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

Dynegy and its 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 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.

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, Illinois Power delivered notice of its intent to exercise its option in order for DMG to purchase the turbines upon the expiration of the operating lease in September 2004. Based on Dynegy’s and 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 routinely engage in business transactions with subsidiaries of Dynegy that are not part of our consolidated group. These transactions included among others, sales of energy and capacity to Illinois Power under a power purchase agreement, as well as purchases of natural gas from Illinois power. Please read Note 13—Related Party Transactions—Other beginning on page F-37 of our Form 10-K for further discussion. Additionally, 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 read Note 13—Related Party Transactions beginning on page F-36 of our Form 10-K for further discussion.

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Note 8—Commitments and Contingencies

Set forth below is a description of our material legal proceedings. In addition to the matters described below, we are party to legal proceedings arising in the ordinary course of business. In management’s opinion, the 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 $57 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 filing of our second quarter 2004 Form 10-Q:

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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 and Dynegy are defending a class action lawsuit filed on behalf of purchasers of Dynegy’s publicly traded securities from January 2000 to July 2002 seeking unspecified compensatory damages and other relief. The lawsuit principally asserts that we and Dynegy, 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, Dynegy is a nominal defendant in several derivative lawsuits brought by shareholders on Dynegy’s behalf against certain of its 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. A 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. Dynegy is 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 Dynegy’s 401(k) Savings Plan, including claims that Dynegy’s Board and certain of Dynegy’s former and current officers, past and present members of Dynegy’s Benefit Plans Committee, former employees who served on a predecessor committee to its 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

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stock—in particular with respect to Dynegy’s 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, Dynegy filed a motion to dismiss this action. The judge entered an order on this motion in March 2004, dismissing several of the plaintiff’s claims and all of the defendants except Dynegy and the members of its Benefit Plans Committee from January 2002 to January 2003, the substantially reduced class period established by the order. In May 2004, in 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 Dynegy’s applicable insurance limits, and Dynegy expects 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.

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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 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/or Dynegy 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/or Dynegy 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.

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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 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. This action has been removed from state court and consolidated 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.

In November 2004, each of Nurserymen’s Exchange, Inc., School Project for Utility Rate Reduction and the County of Alameda, California served Dynegy with lawsuits alleging price fixing, unfair competition and unjust enrichment arising from, among other things, the provision of false information to gas index publications which inflated the retail prices for intra-state gas sales. We anticipate that these cases will be consolidated into the In re Western States Wholesale Natural Gas Anti-Trust Litigation referenced above.

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

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 we and/or 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,

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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 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.

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Severance Arbitrations. Dynegy’s 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, Dynegy 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, Dynegy 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 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.