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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended March 31, 2004

For the transition period from              to             

Commission file number: 1-15659

DYNEGY 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  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, 282,071,325 shares outstanding as of May 3, 2004; Class B common stock, no par value per share, 96,891,014 shares outstanding as of May 3, 2004.

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DYNEGY INC.

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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 INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited) (in millions)

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2004 and 2003

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.

The unaudited condensed consolidated financial statements contained in this report include all material adjustments that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods. Interim period results are not necessarily indicative of the results for the full year. The preparation of the 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 discounts 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, (5) determining amounts to accrue for contingencies and (6) estimating various factors used to value our pension assets. Actual results could differ materially from any such estimates. Certain reclassifications have been made to prior period amounts in order to conform to current year presentation.

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 pursuant to adopting the provisions of EITF Issue 02-03. The cumulative effect of this change in accounting principle resulted in after-tax earnings of $21 million in the first quarter 2003 and comprised the following items that are no longer required to be recorded using mark-to-market accounting (in millions):

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2004 and 2003

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. 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-month periods ended March 31, 2004 and 2003, accretion expense recognized for the fair value for all of our ARO liabilities totaled approximately $1 million and $1 million, respectively. There were no additional AROs recorded or settled, nor were there any revisions to estimated cash flows associated with existing AROs, during the three-month periods ended March 31, 2004 and 2003. At March 31, 2004, our aggregate ARO liability was $42 million.

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2004 and 2003

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. 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.

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 and basic and diluted earnings per share amounts would have approximated the following pro forma amounts for the three-month periods ended March 31, 2004 and 2003, respectively.

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.

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2004 and 2003

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, California, Georgia, Texas and Michigan, 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 62 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 $475 million at March 31, 2004, and one of our affiliates has a loan outstanding to one of these entities, which totaled $11 million at March 31, 2004.

FIN No. 46R also requires additional disclosure for entities where we are unable to obtain financial information to determine (1) if the entity is a VIE and (2) if we are deemed to be the primary beneficiary of the entity. We identified one potential VIE for which we were unable to obtain adequate financial information. As required to be disclosed by FIN No. 46R, following is a description of the agreements with this potential VIE. 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 owns and operates a 955 MW combined cycle natural gas generation facility in Oswego, New York. These agreements are in effect through 2014. Our future obligations under these agreements are approximately $807 million, which includes the fixed capacity payments for our physical tolling contract and fixed payments related to the financial derivative instrument. We recorded expense of $6 million and $9 million under the tolling agreement and financial derivative instrument during the quarters ended March 31, 2004 and 2003, respectively.

Cumulative Effect of Change in Accounting Principles

We adopted SFAS No. 143 and provisions of EITF Issue 02-03 in the first quarter 2003. We adopted provisions of FIN No. 46R in the first quarter 2004. Please see above for a discussion of the impact of adopting these standards.

Note 2—Dispositions and Discontinued Operations

Dispositions

Pending Sale of Illinois Power. In February 2004, we entered into a purchase agreement to sell all of the outstanding common and preferred shares of Illinois Power Company, which currently comprises our REG segment, owned by Illinova Corporation, our indirect wholly owned subsidiary and the direct parent company of Illinois Power, and our 20% interest in the Joppa power generation facility, to Ameren for $2.3 billion. The sale is scheduled to be completed by the end of 2004. In a related agreement that is conditioned upon the closing of the transaction, we have contracted to sell 2,800 MWs of generating capacity and up to 11.5 million MWh of energy to Illinois Power at fixed prices for two years beginning in January 2005. We also agreed to sell 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.

At March 31, 2004, Illinois Power met the held for sale classification requirements of SFAS No. 144 and is classified as such on our unaudited condensed consolidated balance sheet. The major classes of current and long-term assets and liabilities classified as Assets held for sale or Liabilities held for sale at March 31, 2004 are as follows (in millions):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2004 and 2003

Additionally, $11 million included in Redeemable preferred securities and $34 million of Accumulated other comprehensive loss at March 31, 2004 relate to Illinois Power and will not be included in our unaudited condensed consolidated balance sheets subsequent to the sale.

SFAS No. 144 also 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. In addition, SFAS No. 144 requires a loss to be recognized by the amount Assets held for sale less Liabilities held for sale are in excess of fair value less costs to sell. Accordingly, in the first quarter 2004, we recorded a $15 million pre-tax loss on sale primarily associated with the expected transaction costs. This loss is reflected in Gain on sale of assets, net on the unaudited condensed consolidated statements of operations.

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) on 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 FAS 144 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 will continue to report the historical results of Illinois Power’s operations in continuing operations. Earnings from power sales to

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2004 and 2003

Illinois Power derived from periods following the closing of the transaction will continue to be reported in the GEN segment in continuing operations.

Changes in Assets held for sale less Liabilities held for sale in future quarters, prior to the closing of the transaction, may result in additional losses. In accordance with SFAS No. 142, such losses would first be recorded as a reduction to goodwill in our REG segment. The amount of such losses depends on various factors including timing of the closing of the transaction, capital expenditures prior to closing and other matters. Given the nature of these factors, we currently are unable to predict with certainty the amount of loss we expect to realize.

We expect to record a pre-tax gain of approximately $75 million upon closing of the transaction related to the sale of our 20% interest in the Joppa power generation facility. Our interest in the Joppa power generation facility is included in our unaudited condensed consolidated balance sheets in Unconsolidated investments and totaled $23 million at March 31, 2004.

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 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 on sale of assets, net on the 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 expect to recognize a pre-tax gain on the sale of approximately $36 million.

PESA. In April 2004, we sold our interest in the Plantas Eolicas, S. de R.L. 20 MW wind-powered electric generation facility located in Costa Rica for approximately $11 million. We do not expect to recognize a material gain or loss on the sale.

Capital Loss Valuation Allowance. As a result of the transactions discussed above, as well as other transactions forecasted to occur in 2004, we reduced the valuation allowance related to our significant capital loss carryforward by $39 million in the first quarter 2004. This capital loss carryforward primarily relates to our third quarter 2002 sale of Northern Natural Gas Company. The $39 million benefit is reflected in Income tax benefit (expense) on the unaudited condensed consolidated statements of operations.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2004 and 2003

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:

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 information. 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.

Note 3—Restructuring Charges

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 our former chief executive officer. Please see Note 9—Commitments and Contingencies—Severance Arbitrations for further information regarding the status of these claims.

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-25 of our Form 10-K.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2004 and 2003

Cash flow hedges. We enter into financial derivative instruments that qualify as cash flow hedges. Instruments related to our power generation and natural gas liquids businesses are entered into for purposes of hedging future fuel requirements and 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 months ended March 31, 2004 and 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 months ended March 31, 2004 and 2003, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.

The balance in cash flow hedging activities, net at March 31, 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 $34 million are currently estimated to be reclassified into earnings over the 12-month period ending March 31, 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 months ended March 31, 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 months ended March 31, 2004 and 2003, no amounts were recognized in relation to firm commitments that no longer qualified as fair value hedges.

Net investment hedges in foreign operations. We 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 March 31, 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 three months ended March 31, 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.

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:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2004 and 2003

Note 5—Unconsolidated Investments

A summary of our unconsolidated investments is as follows:

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

Earnings from unconsolidated investments of $40 million for the three months ended March 31, 2004, include the $47 million above, offset by a $7 million impairment of our Michigan Power equity investment discussed below. Earnings from unconsolidated investments of $53 million for the three months ended March 31, 2003 consist entirely of the net income related to such investments.

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. Also during the first quarter 2004, we entered into agreements to sell our unconsolidated investments in the Oyster Creek and Michigan Power generation facilities for aggregate net cash proceeds of approximately $103 million. Closing of the transactions, targeted for the second quarter 2004, are subject to lender and counterparty consents and other closing conditions. In the first quarter 2004, we recorded an impairment on our investment in Michigan Power totaling $7 million to adjust our book value to the selling price.

Note 6—Debt

Revolvers and Commercial Paper. During the three-month period ended March 31, 2004, we issued an aggregate of approximately $20 million of letters of credit under our $1.1 billion revolving credit facility for a total of $208 million at March 31, 2004. As of March 31, 2004, there were no borrowings outstanding under this facility. During the period from March 31, 2004 through May 3, 2004, we reduced our outstanding letters of credit under this facility by $19 million.

Repayments. In the first quarter 2004, we repaid the $95 million aggregate principal amount of Illinova’s 7.125% Senior Notes due 2004. We also made payments of $19 million related to the ABG Gas Supply financing and $22 million related to Illinois Power’s transitional funding trust notes.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2004 and 2003

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-43 of our Form 10-K 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-48 of our Form 10-K, we issued 8 million shares of our Series C convertible preferred stock due 2033 to CUSA. We accrue dividends on our Series C 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.

Note 8—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 dilutive potential common shares outstanding during the period. The reconciliation of basic earnings per share from continuing operations to diluted earnings per share from continuing operations is shown in the following table:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2004 and 2003

Note 9—Commitments and Contingencies

Set forth below is a description of our material legal proceedings. In addition to the matters described below, we are party to legal proceedings arising in the ordinary course of business. In 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, “Accounting for Contingencies.” For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Please see Note 2—Accounting Policies—Other Contingencies beginning on page F-11 of our Form 10-K 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 these matters based on current information and made a judgment concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may, as a result of facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.

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 Form 10-K:

The above summary of recent developments is qualified in its entirety by, and should be read in conjunction with, the more detailed summary of our significant legal proceedings set forth below.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2004 and 2003

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 have been appointed as lead plaintiff and Milberg Weiss is class counsel. The plaintiff filed an amended complaint in January 2004 and, in March 2004, we filed a motion to dismiss. We expect the plaintiff’s response and our corresponding reply to be filed in May and June 2004, respectively. An adverse result in this action could have a material adverse effect on our financial condition, results of operations and cash flows. We previously recorded a reserve 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 June 2004. 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 putative 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 the gas price index investigation. 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 the Dynegy Benefit Plans Committee from January 2002 to January 2003, the substantially reduced class period established by the order. An answer was filed to the plaintiff’s suit denying the remaining claims in April 2004. Discovery is proceeding. 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 this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

Baldwin Station Litigation. Illinois Power and DMG 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 Prevention of Significant Deterioration (PSD), the New Source Performance Standard (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

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2004 and 2003

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. These interventions and delays in post-trial briefing have postponed the issuance of the liability order, and we cannot predict with certainty when a decision will be rendered. We have recorded a reserve in an 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.

Also in August 2003, the EPA issued a new rule, the “Equipment Replacement Provision of the Routine Maintenance, Repair and Replacement Exclusion,” the effectiveness of which has been delayed pending the resolution of an appeal filed by several northeastern states and environmental groups. The new rule, if sustained, would provide that replacing components of a process unit with identical components (or functional equivalents) falls within the scope of the routine maintenance, repair and replacement exclusion if (i) the replacement cost is less than 20% of the total cost of replacing the unit, (ii) the replacement does not alter the unit’s basic design and (iii) the unit will continue to comply with applicable emission and operational standards.

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. The EPA could eventually commence enforcement actions based on activities at these plants, although the uncertainty surrounding the new rule makes it difficult to assess the likelihood of 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.

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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. A decision on the plaintiffs’ appeal of that dismissal is not expected before the third quarter 2004. Regarding the other six consolidated cases, we are awaiting a ruling from the Ninth Circuit Court of Appeals, which we do not expect to occur prior to the third quarter 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 to enjoin illegal conduct, 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 granted our motion to dismiss eight of these nine actions, although the plaintiffs have appealed and we are awaiting a hearing date on their appeal. 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. 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 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. Most recently, the Montana Attorney General has filed a case alleging similar antitrust and market manipulation claims, although we have not 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 July 2001, the FERC initiated a hearing to establish refunds to electricity customers, or offsets against amounts owed to electricity suppliers, during the period of October 2000 through June 2001. In particular, the FERC established a methodology to calculate mitigated market clearing prices in the Cal ISO and the Cal PX markets. In December 2002, an administrative law judge issued his recommendations regarding the appropriate level of refunds or offsets. Those recommendations, however, do not fully reflect proposed refund or offset amounts for individual companies. In October 2003, the FERC issued two orders addressing various applications for rehearing, including ours, relating to its previous refund orders. The orders addressed numerous requests by the parties, the most significant of which was the refusal to change the gas pricing methodology and a requirement that the Cal ISO and Cal PX recalculate the refund liability of market participants. The gas price methodology approved by the FERC in March 2003 replaces the gas prices used in the computation, thus reducing the mitigated market clearing price for power and increasing calculated refunds, subject to a provision that provides full recoverability of actual gas costs paid by the generators to

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unaffiliated third parties. No final refund calculation is expected prior to August 2004. West Coast Power recorded a reserve in the fourth quarter 2003 relating to its estimated refund exposure.

In June 2003, the FERC issued an 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. In January 2004, Dynegy and the FERC staff submitted a stipulation and settlement agreement to the presiding administrative law judge to settle the issues raised in the June 2003 show cause order. This settlement, which provides that West Coast Power will pay approximately $3 million, following final FERC approval, into a fund established at the U.S. Treasury for the benefit of California and Western electricity consumers, will be incorporated into the broader settlement described below.

Also in June 2003, the FERC issued an order requiring parties to demonstrate that certain bids did not constitute anomalous market behavior. Specifically, the order requires the FERC staff to investigate all parties who bid above the level of $250/MWh in the Cal ISO and Cal PX markets during the period from May 2000 to October 2000. Parties identified through this process will be required to demonstrate why this bidding behavior did not violate market protocols. The order also states that, to the extent such practices are not found to be legitimate business behavior, the FERC will require the disgorgement of all unjust profits for that period and will consider other non-monetary remedies, such as the revocation of market-based rate authority.

In April 2004, Dynegy and West Coast Power announced an agreement to settle FERC claims relating to western energy market transactions that occurred from January 2000 through June 2001. 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 past-due receivables and 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 is subject to the execution of definitive agreements and approval by the FERC and the CPUC, which is expected in the third quarter 2004. We recorded an additional $5 million charge in the first quarter 2004 related to the settlement.

The settlement will 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 will 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 and Cal PX, which rely on cash payments from California utilities to in turn pay their bills. West Coast Power currently sells directly to the CDWR pursuant to a long-term sales agreement.

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At March 31, 2004, our portion of the receivables owed to West Coast Power by the Cal ISO and Cal PX, as reflected in West Coast Power’s financial records, approximated $235 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 March 31, 2004 was approximately $196 million. We also recorded an additional $5 million charge in the first quarter 2004 related to the above-described settlement which, if approved, will resolve the claims and disputes which initially gave rise to these reserves at West Coast Power.

Enron Trade Credit Litigation. At the time of their bankruptcy filing in the fourth quarter 2001, 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, with respect to which we recognized a charge in our fourth quarter 2001 financial statements, 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 recalculations of mark-to-market values of past transactions, we have reduced the amount that we believe we are owed by Enron to approximately $68 million, including the liabilities under the gas transportation agreement related to the Sithe Independence power tolling arrangement. 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.

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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Trans-Elect Litigation. In October 2003, Trans-Elect, Inc. and Illinois Electric Transmission Company, LLC filed suit against Illinois Power Company in the Northern District of Illinois requesting specific performance and estoppel, and claiming damages as a result of breach of contract and lost profits. These causes of action allegedly arise from Illinois Power’s termination of an asset purchase and sale agreement entered into by the parties in October 2002. Under the terms of the agreement, Illinois Power agreed to sell its transmission assets to Trans-Elect if, on or before July 7, 2003, the agreement received the required FERC, ICC, SEC and Hart-Scott Rodino approvals. As of July 7, 2003, the agreement had not been approved by, among other entities, the FERC and, as a result, Illinois Power terminated the agreement in accordance with its terms on July 8, 2003. Trans-Elect claims that Illinois Power breached the agreement by failing to use its “best efforts” to obtain the required approvals and/or to negotiate an alternate agreement that could be approved. In April 2004, the plaintiffs amended their complaint to add Dynegy Inc. as a defendant, claiming that we tortiously interfered with the asset purchase and sale agreement. Trial has been scheduled in this matter for January 2005.

In April 2004, the plaintiffs also filed a separate lawsuit in Illinois state court against DHI, similarly claiming that DHI tortiously interfered with the Illinois Power asset purchase and sale agreement. We intend to file an answer to this claim in May 2004.

We deny these claims, in that we believe we complied with the terms of the agreement, and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or estimate the damages, if any, that might be incurred in connection with these lawsuits. However, we do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition or results of operations. Additionally, in connection with our proposed sale of Illinois Power to Ameren, we have retained this contingent liability and do not expect that the outcome will negatively impact our ability to close the sale.

Severance Arbitrations. Our former CEO, Chuck Watson, former President, Steve Bergstrom, and former CFO, Rob Doty, have each filed for arbitration pursuant to the terms of their employment/severance agreements. In each case, the parties disagree as to the amounts that may be owed pursuant to their respective agreements. These former officers made arbitration claims seeking payments of up to approximately $28.7 million, $10.4 million and $3.4 million, respectively. Their agreements are subject to interpretation and we believe that, with respect to the claims asserted by Messrs. Watson and Doty, the amounts owed are substantially lower than the amounts sought.

The arbitration relating to Mr. Bergstrom’s severance agreement was tried before a panel of three arbitrators in March 2004. In April 2004, the panel issued its decision with respect to his severance claim awarding Mr. Bergstrom approximately $10.4 million. We anticipate a decision on Mr. Bergstrom’s request for attorneys’ fees and interest in May 2004. The arbitrations with respect to Messrs. Watson and Doty are currently scheduled to commence in June and November 2004, respectively.

We have taken severance accruals in amounts we consider reasonable relating to these proceedings. Please read Note 3 – Restructuring Charges for further discussion regarding the accrual relating to Mr. Watson.

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 alleges, in the words of his amended complaint, that certain of our former executive officers requested that he “shave or reduce for accounting purposes” the forward price curves associated with the natural gas business in the United Kingdom for the period of October 1, 2000 through March 31, 2001, in order to indicate a reduction in our mark-to-market losses. Mr. Farnsworth, who seeks unspecified actual and exemplary damages and other compensation, also alleges that he is entitled to a termination payment under his employment agreement equal to 2.99 times the greater of his average base salary and incentive

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compensation for the highest three calendar years preceding termination or his base salary and target bonus amount for the year of termination (currently estimated at a range of approximately $700,000 to $1,200,000). In March 2004, the judge dismissed Mr. Farnsworth’s claim that he was asked to “shave” forward price curves. Trial on the claim concerning his employment agreement has been rescheduled for October 2004. We are vigorously defending this claim. Although we have recorded a reserve with respect to this litigation, we do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations 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 amended petition alleges that Versado engaged in “sham” transactions with affiliates, resulting in Versado not receiving fair market value when it sells gas and liquids, and 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 jury found in favor of the plaintiff and awarded approximately $1.6 million in damages. We are awaiting a ruling from the court on a motion to set aside the judgment. Although we have recorded a reserve with respect to this litigation, we do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations 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; Texas-Ohio Energy Inc. et al. v. Centerpoint Energy et al; People of the State of Montana et al. v. Williams Energy Marketing et al; Benscheidt v. AEP Energy Services et al. 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 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. Our motion to dismiss the Sierra Pacific suit was granted. In April 2004, in response to a motion by the plaintiff, the court affirmed its dismissal of the original complaint but allowed plaintiff leave to file an amended complaint. We have not yet received the amended complaint. The other 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.

Triad Litigation. In March 2003, Triad Energy Resources Corp. and five other alleged representatives of two plaintiffs’ classes filed a putative antitrust class action against NiSource Inc. and other defendants, including us, in federal district court. The plaintiffs purport to represent classes of purchasers, marketers, wholesalers, managers, sellers and shippers of natural gas that allegedly were damaged by an illegal gas scheme devised by three federally regulated interstate pipeline systems which are now owned by NiSource, and certain shippers on these pipelines. It alleges that the interstate pipelines provided preferential storage and transportation services to their own unregulated marketing affiliate, in violation of FERC regulations, and in return for percentages of the profits reaped by the marketing affiliate. The complaint also alleges that certain shippers, including us, having learned of these preferential arrangements, demanded and received similar preferential storage and transportation services that were not available to all shippers.

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Although this alleged scheme was the subject of an October 2000 FERC order, which required the Columbia companies to pay $27.5 million to certain customers of Columbia Gas and Columbia Gulf, plaintiffs claim that the FERC order did not remedy the competitive injury to plaintiffs caused by the scheme. The complaint seeks aggregate damages of approximately $1.716 billion, which damages are subject to trebling under federal antitrust laws. In October 2003, the court granted defendants’ motion to dismiss for lack of jurisdiction and allowed time for the plaintiffs to amend their complaint. The plaintiffs have since filed a motion to voluntarily dismiss their complaint and indicated an intent to refile in a proper jurisdiction, although plaintiffs have not yet re-filed. We are analyzing these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or estimate the damages, if any, that we might incur in connection with this lawsuit.

Atlantigas Corp. Litigation. In November 2003, Atlantigas Corporation filed a suit similar to Triad in Maryland against us and several other defendants alleging certain conspiracies between natural gas shippers and storage facilities. The complaint seeks unspecified compensatory and punitive damages. In addition, we are alleged to have conspired with the other defendants to receive preferential natural gas storage and transportation services at off-tariff prices. Defendants are currently challenging plaintiff on the threshold issues of standing, statute of limitations and jurisdiction. These issues were fully briefed in February 2004 and a hearing date has been requested but not scheduled. 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 we might incur in connection with this lawsuit.

Maxus Litigation. In April 2001, in the case of Natural Gas Clearinghouse v. Midgard Energy, formerly known as Maxus Exploration Co., a Texas district court found us liable for failing to deliver processable “wet” gas to a Maxus processing plant. Following our appeal of the judgment, we filed an expedited writ with the Texas Supreme Court seeking further review, which was denied in April 2004. We paid the judgment of approximately $6.9 million dollars in April 2004, against which we had recorded a reserve.

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 or is prepared to admit for purposes of the liquidation the plaintiffs’ claims in the amount of $30 million. Although these Austrian lawsuits are stayed as a result of the liquidation, the outcome of the liquidation could impact the New York lawsuit. 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 or results of operations. We have recorded a reserve in connection with this litigation.

Alleged Marketing Contract Defaults. We have posted collateral to support a substantial portion of our obligations in our CRM business, including our obligations under power tolling arrangements. While we worked with various counterparties to provide mutually acceptable collateral or other adequate assurance under these contracts, we have not reached agreement with Sithe Independence and Sterlington/Quachita Power LLC regarding a mutually acceptable amount of collateral in support of our obligations under our power tolling arrangements with either of these two parties. Although we are current on all contract payments to these counterparties, we 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,

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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 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 appeals are pending and a new trial date has not been set.

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 pleaded guilty to conspiracy to commit securities fraud and are scheduled to be sentenced in August 2004. Trial on the indictment against the third employee was held in November 2003, and the defendant was convicted on all charges. In March 2004, this defendant was 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 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.

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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.

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-68 of our Form 10-K.

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