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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended March 31, 2005

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, 284,688,181 shares outstanding as of May 5, 2005; Class B common stock, no par value per share, 96,891,014 shares outstanding as of May 5, 2005.

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DYNEGY INC.

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DEFINITIONS

As used in this Form 10-Q, the abbreviations contained herein have the meanings set forth below. Additionally, the terms “Dynegy,” “we,” “us” and “our” refer to Dynegy Inc. and its subsidiaries, unless the context clearly indicates otherwise.

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DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)

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 (LOSS)

(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, 2005 and 2004

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 consolidated 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 for the year ended December 31, 2004, which we refer to as 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. 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 judgments that affect our reported financial position and results of operations. These estimates and judgments also impact the nature and extent of disclosure, if any, of our contingent liabilities. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments 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, (5) determining amounts to accrue for contingencies, guarantees and indemnifications and (6) estimating various factors used to value our pension assets and liabilities. 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.

Asset Retirement Obligations. At December 31, 2004, our ARO liabilities were $35 million for our GEN segment and $11 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 and equipment lease obligations. We continue to follow the provisions for disclosure and accounting for these AROs under SFAS No. 143, “Asset Retirement Obligations.” During the three-months ended March 31, 2005 and 2004, there were no material additional AROs recorded or settled, and our accretion expenses and revisions to estimated cash flows were not material. At March 31, 2005, our ARO liabilities were $36 million for our GEN segment and $10 million for our NGL segment.

Employee Stock Options. 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.

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

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 (loss) and basic and diluted earnings (loss) per share amounts would have approximated the following pro forma amounts for the three-month periods ended March 31, 2005 and 2004, respectively.

Accounting Principle Adopted

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 facilities ranges from 165 MW to 902 MW. As a result of various contractual arrangements into which these entities have entered,

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

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 $325 million at March 31, 2005, and one of our affiliates has a loan outstanding to one of these entities, which totaled $20 million at March 31, 2005.

On January 31, 2005, we completed the acquisition of ExRes SHC, Inc., the parent company of Sithe Energies, Inc., which we refer to as “Sithe Energies,” and Sithe/Independence Power Partners, L.P., which we refer to as “Independence.” ExRes SHC, Inc., which we refer to as “ExRes,” owns through its subsidiaries four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. The entities owning these facilities meet the definition of VIEs. In accordance with the purchase agreement, Exelon has the sole and exclusive right to direct our efforts to decommission, sell, or otherwise dispose of the hydroelectric facilities owned through the VIE entities. Exelon is obligated to reimburse ExRes for all costs, liabilities, and obligations of the entities owning these facilities, and to indemnify ExRes with respect to the past and present assets and operations of the entities. As a result, we are not the primary beneficiary of the entities, and have not consolidated them in accordance with the provisions of FIN No. 46R.

With regard to the four natural gas-fired merchant facilities, we have the option to elect to decommission any or all of these facilities within a 180-day period after the January 31, 2005 closing date. If we elect to decommission any of these assets, Exelon will be entitled to direct the decommissioning, sale, or other disposal of the facility. Further, Exelon is obligated to indemnify ExRes with respect to the past and present assets and operations of the entity owning such facility, and must provide written consent for any payments or actions outside the ordinary course of operations. Effective April 1, 2005, we have elected to decommission three of these four natural gas-fired facilities owned by these entities. We will continue to evaluate our involvement with the remaining entity. As a result of the rights retained by Exelon with respect to these facilities, we are not the primary beneficiary of these VIE’s, and have not consolidated them in accordance with the provisions of FIN No. 46R. Please see Note 2—Acquisitions, Dispositions and Discontinued Operations—Acquisitions—Sithe Energies for further discussion regarding this acquisition.

These hydroelectric generation facilities have commitments and obligations that are off-balance sheet with respect to Dynegy arising under operating leases for equipment and long-term power purchase agreements with local utilities. As of March 31, 2005, the equipment leases have remaining terms from two to sixteen years and involve a maximum aggregate obligation of $137 million over the terms of the leases. Additionally, each of these facilities is party to a long-term power purchase agreement with a local utility. Under the terms of each of these agreements, a project tracking account, which we refer to as a “Tracking Account,” was established to quantify the difference between (i) the facility’s fixed price revenues under the power purchase agreement and (ii) the respective utility’s Public Utility Commission approved avoided costs associated with those power purchases plus accumulated interest on the balance. Each power purchase agreement calls for the hydroelectric facility to return to the utility the balance in the Tracking Account before the end of the facility’s life through decreased pricing under the respective power purchase agreement. Two of the four hydroelectric facilities are currently in the Tracking Account repayment period of the contract, whereby balances are repaid through decreased pricing. This pricing cannot be decreased below a level sufficient to allow the facilities to recover their operating costs. The remaining two facilities are anticipated to begin reducing the Tracking Accounts in 2006. The aggregate balance of the Tracking Accounts as of March 31, 2005, was approximately $281 million, and the obligations with respect to each Tracking Account are secured by the assets of the respective facility. The decreased pricing necessary to reduce the Tracking Accounts will make the continued sale of electricity from the facilities uneconomical. As discussed above, the obligations of the four hydroelectric facilities are non-recourse to us. Under the terms of the stock purchase agreement with Exelon, we are indemnified for any net cash outflow arising from ownership of these facilities.

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

Accounting Principles Not Yet Adopted

SFAS No. 123(R). In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment,” which revises SFAS No. 123. For public entities such as us, SFAS No. 123(R) is effective for annual periods beginning after June 15, 2005. SFAS No. 123(R) requires companies to expense the fair value of employee stock options and other forms of stock-based compensation. The fair value for these awards is calculated on the grant date in accordance with SFAS 123 for either recognition in our statement of operations or through our pro forma disclosures. This expense will be recognized over the period during which an employee is required to provide services in exchange for the award. SFAS 123(R) describes several transition methods, and we expect to apply the modified prospective method of adoption. Under this method, compensation expense will be recognized for the remaining portion of outstanding, unvested awards at January 1, 2006.

As noted in “Employee Stock Options” above, we transitioned to a fair value based method of accounting for stock-based compensation in the first quarter 2003. Our share-based payments primarily consist of stock options and restricted stock awards. For stock options, we determine the fair value of each stock option at the grant date using a Black-Scholes model. For restricted stock awards, we consider the fair value to be the closing price of the stock on the grant date. We recognize the fair value of our share based payments over the vesting periods of the awards, which is typically a three-year service period.

Prior to the issuance of SFAS No. 123(R), we adopted the prospective method for expensing the fair value of stock options and restricted stock awards granted after January 1, 2003. As such, under the modified prospective method of adoption under SFAS

123(R), three option grants made in September 2002 and October 2002 would require recognition of expense over the remaining vesting periods of these outstanding awards. We do not expect this incremental expense to be material.

FIN No. 47. In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” which is an interpretation of SFAS No. 143. FIN No. 47 clarifies the term “conditional asset retirement obligation,” which refers to legal obligations for which companies must perform asset retirement activity for which the timing and/or method of settlement are conditional upon future events that may or may not be within the control of the entity. However, the obligation to perform the asset retirement is unconditional, despite the uncertainty that exists surrounding the timing and method of settlement. Uncertainty about the timing and method of settlement for a conditional ARO should be considered in estimating the ARO when sufficient information exists. FIN No. 47 clarifies when sufficient information exists to reasonably estimate the fair value of an ARO. FIN No. 47 is effective no later than the end of the first fiscal year ending after December 15, 2005, and early adoption is encouraged.

As noted in “Asset Retirement Obligations” above, we currently record AROs for our GEN and NGL segments. These AROs involve significant judgment regarding future cash flows and the ultimate timing of these cash flows, some of which include the probability of future events occurring such as the timing and method of settlement. As such, we are in the process of evaluating the impact of FIN No. 47.

Note 2—Acquisitions, Dispositions and Discontinued Operations

Acquisitions

Sithe Energies. On January 31, 2005, we acquired 100 percent of the outstanding common shares of ExRes, the parent company of Sithe Energies and Independence. The results of the operations of ExRes have been included

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

in our consolidated financial statements since that date. Through this acquisition, we acquired the 1,021 MW Independence power generation facility located near Scriba, New York, as well as four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. We have not consolidated the entities that own these four natural gas-fired facilities and four hydroelectric generation facilities, in accordance with the provisions of FIN No. 46R. See Note 1—Accounting Policies—Accounting Principles Adopted—FIN No. 46R for additional discussion of these facilities. In addition to these power plants, we acquired the 750-MW firm capacity sales agreement between Independence and Con Edison, a subsidiary of Consolidated Edison, Inc. This agreement, which runs through 2014, will provide us with annual cash receipts of $100 million, subject to the restrictions on distribution under Independence’s indebtedness. Independence holds power tolling, financial swap and other contracts with other Dynegy subsidiaries. As a result of the acquisition, these contracts have become intercompany agreements, and their financial statement impact has been substantially eliminated. This transaction enabled us to address one of our outstanding power tolling arrangements, and to expand our generation capacity in a market where we have an existing presence.

The aggregate purchase price was comprised of (i) $135 million cash, which was reduced by a purchase price adjustment of approximately $2 million; (ii) transaction costs of approximately $16 million, approximately $3 million of which were paid in 2004, and (iii) the assumption of $919 million of face value project debt, which was recorded at its fair value of $797 million as of January 31, 2005. Please read Note 6—Debt—Independence Debt for additional information regarding the debt assumed.

The allocation of purchase price to specific assets and liabilities is based, in part, upon outside appraisals using customary valuation procedures and techniques. The allocation is still preliminary at this time; however, we do not expect material changes. We anticipate finalizing our allocation of purchase price in 2005, once the final tax basis of the assets and liabilities acquired has been determined and physical inventory counts are finalized. The acquisition resulted in an excess of the fair value of assets acquired over cost of the acquisition. This excess was then allocated to property plant and equipment and intangible assets acquired, including intangibles arising from contracts with us, on a pro-rata basis.

The following table summarizes the preliminary fair values of the assets and liabilities acquired at the date of acquisition, January 31, 2005 (in millions):

Included in the assets acquired are restricted cash and investments of approximately $132 million. The restricted investments include Federal Home Loan Bank Bonds, U.S. Treasury Bonds, and high-grade short-term

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

commercial paper. The restricted cash and investments are related to a sinking fund required by Independence debt instruments, including a major overhaul reserve, a debt service reserve, a principal payment reserve, an interest reserve and a project restoration reserve. Restrictions on the cash and investments are scheduled to be lifted at the end of the project financing term in 2014. For further discussion, please see Note 6—Debt—Independence Debt.

Of the $709 million of acquired intangible assets, $526 million was allocated to the firm capacity sales agreement with Con Edison. This asset will be amortized on a straight-line basis over the ten-year remaining life of the contract, through October 2014. In addition, Independence holds a power tolling contract, valued at $166 million, and a gas supply agreement, valued at $17 million, with another of our subsidiaries. Upon completion of our purchase of Independence, this power tolling agreement and gas supply agreement were effectively settled, which resulted in a first quarter 2005 charge equal to their fair values, in accordance with EITF Issue 04-01, “Accounting for Pre-existing Contractual Relationships Between the Parties to a Purchase Business Combination.” We recorded a first quarter 2005 pre-tax charge of $183 million, which is included in cost of sales on our unaudited condensed consolidated statements of operations.

Effective April 1, 2005, we exercised our right to require Exelon to decommission, sell, or otherwise dispose of three of the four natural gas-fired merchant facilities owned by ExRes. Under the terms of the purchase agreement, Exelon will direct the disposition of these facilities, and will indemnify us with respect to all past and present operations. We will continue to evaluate our involvement with the remaining natural gas-fired merchant facility, as we retain our right for a 180-day period following the January 31, 2005 purchase date to determine whether to continue operating the asset. Further, Exelon is entitled to cause us to decommission, sell, or bankrupt any or all of the four hydroelectric facilities owned by ExRes, for which we have been indemnified for any losses.

Dispositions

Sale of Illinois Power. On September 30, 2004, we sold all of our outstanding common and preferred shares of Illinois Power Company, which formerly comprised our REG segment, as well as our 20% interest in the Joppa power generation facility, to Ameren Corporation for $2.3 billion. The $2.3 billion sale price consisted of Ameren’s assumption of $1.8 billion of Illinois Power’s debt and preferred stock obligations, cash proceeds of approximately $375 million and an additional $100 million of cash placed in escrow. At March 31, 2005 and December 31, 2004, we reflected the balance held in escrow in prepayments and other current assets on our unaudited condensed consolidated balance sheets. Under the escrow agreement, which we filed as an exhibit to our third quarter 2004 Form 10-Q, the $100 million deposited by Ameren will be released to us upon the satisfaction of one of three conditions including the occurrence of specified events relating to contingent environmental liabilities associated with Illinois Power’s former generating facilities (currently owned by DMG). Once approved by the Illinois federal district court, we believe that the Baldwin consent decree announced in March 2005 will satisfy this condition and entitle us to receive the $100 million in escrowed funds. We expect this consent decree to receive such approval in the second quarter 2005. Please read Note 9—Commitments and Contingencies—Baldwin Station Litigation for further discussion of this consent decree. During the time that these funds remain in escrow, we will receive quarterly payments equivalent to the interest income earned on such funds.

During the first quarter 2005 we paid approximately $5 million to Ameren for a final working capital purchase price adjustment.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

Also on September 30, 2004, we entered into a two-year power purchase agreement with Illinois Power. Under the terms of this new agreement, which became effective January 1, 2005, we have agreed to provide Illinois Power with up to 2,800 MWs of capacity at $48.00 per KW-yr and up to 11.5 million MWh of energy each year at a fixed price of $30 per MWh. 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 of $16 per KW-yr with an option to purchase energy at market-based prices.

During the first quarter 2004, Illinois Power met the held for sale classification requirements of SFAS No. 144, and continued to meet the requirements through the closing of the sale on September 30, 2004. SFAS No. 144 requires that long-lived assets not be depreciated or amortized while they are classified as held for sale. As such, we discontinued depreciation and amortization of Illinois Power’s property, plant and equipment and regulatory assets, effective February 1, 2004. Depreciation and amortization expense related to Illinois Power totaled $10 million in the three months ended March 31, 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 (loss) on sale of assets, net on the unaudited condensed consolidated statements of operations. Additionally, we recorded a pre-tax asset impairment totaling $6 million ($4 million after-tax). This impairment is reflected in impairments and other charges on our unaudited condensed consolidated statements of operations.

Further, pursuant to SFAS No. 144, we are not reporting the results of Illinois Power’s operations as a discontinued operation. If we were to account for Illinois Power as a discontinued operation, its results of operations would be condensed into loss from discontinued operations, net of taxes, on our consolidated statements of operations, and prior periods would be required to be restated to conform to this presentation. To qualify for discontinued operations classification, SFAS No. 144 and subsequent interpretations, specifically EITF Issue 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations,” require that the seller have no significant continuing involvement with the business being sold. As noted above, we have contracted to sell capacity and energy to Illinois Power for two years beginning in January 2005. Consequently, because we still have significant continuing involvement with Illinois Power, we will continue to include the historical results of Illinois Power’s operations as part of our continuing operations. Additionally, power sales to Illinois Power occurring subsequent to the disposition will be reported in our consolidated statements of operations as third party sales. Approximately $75 million of revenues, derived from power sales to Illinois Power occurring subsequent to the disposition, are reflected in our continuing operations for the period ending March 31, 2005.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

Had the results of Illinois Power been excluded from our comparative results as though the sale had occurred on January 1, 2004, our revenues, net income applicable to common stockholders, and associated basic and diluted earnings (loss) per share would have approximated the following pro forma amounts for the period ended March 31, 2004 (in millions, except per share data):

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 our unaudited condensed consolidated statements of operations.

Capital Loss Valuation Allowance. As a result of the transactions discussed above, as well as other transactions that, at the time, we 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 on our unaudited condensed consolidated statements of operations.

Discontinued Operations

As part of our restructuring plan, we sold or liquidated some of our operations during 2003, including 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:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

In the first quarter 2005, we recognized $4 million of pre-tax income associated with U.K. CRM’s receipt of $4 million from a third party bankruptcy settlement.

In the first quarter 2004, we recognized $17 million of pre-tax income related to translation gains on foreign currency in the U.K. Please see Note 4—Risk Management Activities and Accumulated Other Comprehensive Loss—Net Investment Hedges in Foreign Operations for further discussion. Also in the first quarter 2004, we recognized $3 million of pre-tax income associated with DGC’s receipt of $3 million from a third party in settlement of a prior contractual claim.

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 2005 activity for the liabilities recorded in connection with this restructuring:

We expect the $22 million accrual as of March 31, 2005 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-33 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 and NGL businesses are entered into for purposes of hedging future fuel requirements and sales commitments and locking in future margin. Interest rate swaps have been used to convert floating interest-rate obligations to fixed-rate obligations.

During the three months ended March 31, 2005, we recorded a $4 million charge related to ineffectiveness from changes in fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. During the three months ended March 31, 2004, 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, 2005 and 2004, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

The balance in cash flow hedging activities, net at March 31, 2005 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 $25 million are currently estimated to be reclassified into earnings over the 12-month period ending March 31, 2006. 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 floating-rate debt. During the three months ended March 31, 2005 and 2004, 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, 2005 and 2004, no amounts were recognized in relation to firm commitments that no longer qualified as fair value hedges.

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 March 31, 2005, we had no net investment hedges in place.

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

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 had accumulated in stockholders’ equity.

Note 5—Unconsolidated Investments

A summary of our unconsolidated investments is as follows:

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

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

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

Earnings from unconsolidated investments of $4 million for the three months ended March 31, 2005, include the $3 million above and $1 million from West Coast Power. Earnings from unconsolidated investments of $40 million for the three months ended March 31, 2004 include the $12 million above and $35 million from West Coast Power, offset by a $7 million impairment of our Michigan Power equity investment discussed below.

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 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 sale price.

Note 6—Debt

Revolving Credit Facility. During the three-month period ended March 31, 2005, we increased letters of credit under our $700 million revolving credit facility by $9 million in the aggregate, resulting in a total of $103 million outstanding at March 31, 2005. As of March 31, 2005, there were no borrowings outstanding under this facility. During the period from March 31, 2005 through May 5, 2005, we increased our outstanding letters of credit under this facility by $143 million.

Repayments. In the first quarter 2005, we paid the outstanding $18 million balance on our 8.125% senior notes, which matured in March 2005. We also made payments of $1 million related to the DHI May 2004 term loan.

Independence Debt. On January 31, 2005, we completed the acquisition of ExRes, the parent company of Sithe Energies and Independence. Upon the closing, we consolidated $919 million in face value project debt, which was recorded at its fair value of $797 million as of January 31, 2005, for which certain of the entities acquired are obligated. Please see Note 2—Acquisitions, Dispositions and Discontinued Operations—Acquisitions—Sithe Energies for further discussion of this transaction.

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(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

Long-term debt consolidated upon completion of the Sithe Energies acquisition consisted of the following as of January 31, 2005:

Principal payments on the Independence senior notes, which we refer to as the “senior debt,” are due semiannually through 2013 and principal payments on the subordinated debt begin in 2015. Annual maturities of the Independence debt are as follows: 2005—$34 million; 2006—$37 million; 2007—$40 million; 2008—$44 million; 2009—$57 million; and thereafter—$707 million. The senior debt and subordinated debt are secured by substantially all of the assets of Independence, but are not guaranteed by Dynegy or DHI.

The terms of the indenture governing the senior debt, among other things, prohibit cash distributions by Independence to its affiliates, including Dynegy, unless certain project reserve accounts are funded to specified levels and the required debt service coverage ratio is met. The indenture also includes other covenants and restrictions, relating to, among other things, prohibitions on asset dispositions and fundamental changes, reporting requirements and maintenance of insurance. As of March 31, 2005, Independence had current restricted cash of $61 million and non-current restricted cash of $49 million as reflected on our unaudited condensed consolidated balance sheets. As of March 31, 2005, Independence had short-term and long-term restricted investment balances of $3 million and $36 million, respectively. The balances are included in prepayments and other current assets and restricted investments, respectively, on our unaudited condensed consolidated balance sheets.

Note 7—Related Party Transactions

We engage in transactions with Chevron Corporation, which we refer to as “Chevron,” 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 12—Related Party Transactions—Transactions with ChevronTexaco beginning on page F-47 of our Form 10-K for further discussion.

Series C Convertible Preferred Stock. As discussed in Note 14—Redeemable Preferred Stock—Series C Convertible Preferred Stock beginning on page F-54 of our Form 10-K, in August 2003, we issued to CUSA 8 million shares of our Series C convertible preferred stock due 2033, which we refer to as our “Series C preferred stock.” We accrue dividends on our Series C preferred stock at a rate of 5.5% per annum. We made a semi-annual dividend payment of $11 million in February 2005.

Note 8—Earnings (Loss) Per Share

Basic earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of common stock outstanding during the period. Diluted earnings (loss) per share represents the amount of earnings (losses) 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

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(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

outstanding during the period. The reconciliation of basic earnings (loss) per share from continuing operations to diluted earnings (loss) per share from continuing operations is shown in the following table:

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—Contingencies, Commitments, Guarantees and Indemnifications beginning on page F-16 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.

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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.

Shareholder Litigation. In April 2005, we settled, subject to court approval, 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 as filed principally alleged that we and certain of our current and former officers and directors violated the federal securities laws in connection with our disclosures, including accounting disclosures, regarding Project Alpha (a structured natural gas transaction entered into by us in April 2001), round-trip trading, the submission of false trade reports to publications that calculate natural gas index prices, the alleged manipulation of the California power market and the restatement of our financial statements for 1999-2001. The Regents of the University of California are lead plaintiff and Lerach Coughlin Stoia & Robbins, LLP is class counsel.

In October 2004, in response to our March 2004 motions to dismiss, the judge entered an order dismissing all of plaintiff’s claims under (i) the Securities Act of 1933, except those relating to Dynegy’s March 2001 note offering and December 2001 common stock offering, and (ii) the Securities Exchange Act of 1934, except those dealing with Project Alpha and two alleged round-trip trades. Further, the judge scheduled the trial to commence in May 2005. Also in October 2004, the plaintiff voluntarily dismissed its claim under the Securities Act relating to our March 2001 note offering. The parties filed motions on the class certification issue in the fourth quarter 2004. In December 2004, the court issued an order identifying the class period for the Exchange Act claims as June 21, 2001 through July 22, 2002, and the class period for the Securities Act claims to begin December 20, 2001.

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For the Interim Periods Ended March 31, 2005 and 2004

In April 2005, following mediation, the parties to the shareholder class action litigation reached a comprehensive settlement agreement which is subject to approval by the court and provides for the following:

We filed the settlement agreement with the court on May 9, 2005, and we are awaiting preliminary approval of the agreement and the scheduling of a fairness hearing. We cannot predict with certainty whether the court will approve the settlement or, in the event the settlement is ultimately rejected, whether we will incur any liability in connection with this litigation absent the proposed settlement. An adverse result in this litigation absent the proposed settlement could have a material adverse effect on our financial condition, results of operations and cash flows. Reserves have been provided in connection with this litigation.

In addition, we were named as 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 Texas state court. In February 2005, the plaintiffs voluntarily dismissed the federal derivative matter. In April 2005, the parties to the shareholder derivative litigation pending in Texas state court reached a settlement, and the related settlement agreement was filed with the court on May 10, 2005. A hearing on our settlement agreement has been scheduled for May 11, 2005. Under this settlement agreement, which is also subject to court approval, Dynegy has agreed to effect certain corporate governance changes, many of which were implemented since the claim was originally filed, and to pay related attorney fees and expenses incurred by the plaintiffs in the aggregate amount of approximately $5 million. The ongoing corporate changes relate to director qualifications, the involvement of a lead independent director, the structure and function of certain Board committees and other governance enhancements.

Dynegy and the other defendants did not admit any liability in connection with either of the proposed settlements described above, and there were no findings of any violations of the federal securities laws. We recorded a first quarter pre-tax charge of $222 million ($156 million after-tax) related to these settlements and associated legal expenses. This pre-tax charge is reflected in general and administrative expenses on our unaudited condensed consolidated statements of operations.

ERISA/Illinois Power 401(k) Litigation. In January 2005, three Illinois Power employees participating in the Illinois Power Company Incentive Savings Plan For Employees Covered Under a Collective Bargaining Agreement, which we refer to as the “Illinois Power 401(k) Plan,” purporting to represent all Illinois Power employees who held Dynegy common stock through the Illinois Power 401(k) Plan during the period from February 2000 through September 2004, filed a lawsuit in federal court in the Southern District of Illinois against us, Illinois

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(Unaudited)

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Power, DMG and several individual defendants. The complaint alleges violations of ERISA in connection with the Illinois Power 401(k) Plan that are similar to the claims made in the ERISA litigation settled in December 2004, including claims that certain of our former and current officers (who are past and present members of our Benefit Plans Committee) breached their fiduciary duties to the plan’s participants and beneficiaries in connection with the plan’s investment in Dynegy common stock—in particular with respect to our financial statements, Project Alpha, round-trip trades and gas price index reporting. The lawsuit seeks unspecified damages for the losses to the plan, as well as attorney’s fees and other costs. We do not believe that any liability which might be incurred by Dynegy 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. Since November 1999, DMG has been the subject of an NOV from the EPA and a complaint filed by the EPA and the DOJ in federal district court alleging violations of the Clean Air Act and related federal and Illinois regulations related to certain maintenance, repair and replacement activities at our Baldwin generating station. We have reached agreement with the EPA, the DOJ, the State of Illinois and the environmental group intervenors on terms to settle the litigation. A consent decree was signed by all parties and lodged with the U.S. District Court for the Southern District of Illinois on March 7, 2005. As required by the Clean Air Act, the consent decree was posted in the Federal Register and the period for public comment on the terms thereof has expired. The Court set a hearing on the consent decree for late May 2005. We expect the consent decree to be entered and approved by the Court in the second quarter 2005. The consent decree provides for our payment of a civil penalty of $9 million and for our funding of several environmental projects in the additional aggregate amount of $15 million. It also requires us to install additional emission controls at our Baldwin, Vermilion and Havana plants. Under the terms of the settlement, we will invest $321 million in emission control projects through 2010, including the previously planned conversion of our Vermilion facility to low-sulfur PRB coal, with an additional $224 million in emission control projects in the 2011-2012 timeframe. The decree settles all claims in the litigation, as well as similar claims that might have been brought related to maintenance, repair and replacement activities at other DMG plants including Vermilion, Wood River, Hennepin and Havana.

Reserves have been provided in an aggregate amount adequate to cover the civil penalties and the environmental projects provided for under the consent decree.

The EPA previously requested information, which we provided, concerning maintenance, repair and replacement activities at our Danskammer and Roseton plants. The consent decree does not cover any activities at the Danskammer and Roseton plants. Although the EPA could eventually commence enforcement actions based on activities at these plants, we are unable to assess the likelihood of any such additional EPA enforcement actions.

California Market Litigation. We and numerous other power generators and marketers are defendants in numerous lawsuits alleging rate and market manipulation in California’s wholesale electricity market during the California energy crisis and seeking unspecified treble damages. The cases included: Pamela R. Gordon v. Reliant Energy Inc., et al.; Ruth Hendricks v. Dynegy Power Marketing, et al.; The People of the State of California v. Dynegy Power Marketing, et al.; Sweetwater Authority v. Dynegy Inc., et al.; People of the State of California ex rel. Bill Lockyer, Attorney General v. Dynegy Inc., et al.; Public Utility District No. 1 of Sonomish County v. Dynegy Power Marketing, et al.; and Bustamante [I] v. Dynegy Inc., et al. Eventually, these cases were coordinated before a single federal judge, who dismissed two of them, Lockyer and Sonomish County, 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. In Lockyer, plaintiffs’ Petition for Writ of Certiorari to the U.S. Supreme Court was denied in April 2005. Plaintiffs in Sonomish County filed a Petition for Writ of Certiorari to the U.S. Supreme Court in November 2004. The five remaining coordinated cases were ultimately remanded to California state court, where we intend to file a motion to dismiss as soon as practicable.

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Between April and October 2002, the following nine additional 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: Pier 23 Restaurant v. PG&E Energy Trading, et al.; Bronco Don Holdings v. Duke Energy Trading and Marketing, LLC, et al.; T&E Pastorino Nursery v. Duke Energy Trading and Marketing LLC, et al.; Century Theaters, Inc. v. Allegheny Energy Supply Company, et al.; J&M Karsant Family Ltd. Partnership v. Duke Energy Trading and Marketing, LLC, et al.; Leo’s Day & Night Pharmacy v. Duke Energy Trading and Marketing, LLC, et al.; El Super Burrito v. Allegheny Energy Supply Company, LLC, et al.; RDJ Farms, Inc. v. Allegheny Energy Supply Company, et al.; and Millar v. Allegheny Energy Supply Company, LLC, et al. The complaints allege unfair, unlawful and deceptive practices in violation of the California Unfair Business Practices Act and seek injunctive relief, restitution and unspecified damages. Although some of the allegations in these lawsuits are similar to those in the seven cases referenced above, these lawsuits include additional allegations relating to, among other things, the validity of the contracts between these power generators and the CDWR. Following removal of these cases, the federal court dismissed eight of the nine actions and plaintiffs appealed. In February 2005, the Ninth Circuit affirmed the dismissals. The remaining case, Millar, was ultimately remanded to state court, where we intend to file a motion to dismiss as soon as practicable.

In December 2002, two additional actions were filed on behalf of consumers and businesses in Oregon, Washington, Utah, Nevada, Idaho, New Mexico, Arizona and Montana that purchased energy from the California market, alleging violations of the Cartwright Act and unfair business practices. These cases were subsequently dismissed and refiled in California Superior Court as one class action complaint styled Jerry Egger v. Dynegy Inc., et al. We 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. Plaintiffs challenged the removal, however, and the federal court stayed its ruling pending a decision by the Ninth Circuit on the five coordinated cases referenced above. Although the Ninth Circuit issued a decision remanding those cases, no ruling has been made with respect to Egger.

In May and June 2004, two additional lawsuits, Wah Chang v. Avista Corporation, et al. and City of Tacoma v. American Electric Power Service Corporation, et al., were filed in Oregon and Washington federal courts 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. In February 2005, the respective federal courts granted our motions to dismiss. Shortly thereafter, plaintiffs in both cases filed notices of appeal to the Ninth Circuit.

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. In March 2005, we were served with the suit. We removed the action to federal court in April 2005.

We believe that we have meritorious defenses to these claims and intend to defend vigorously against them. We cannot predict with certainty whether we will incur any liability 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.

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(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

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 provided for the settlement of FERC claims relating to western energy market transactions that occurred from January 2000 through June 2001. Market participants (other than the parties to the settlement) were permitted to opt into this settlement and share in the distribution of the settlement proceeds, and most of these other market participants have done so. The entitlement to refund and/or the liability of each non-settling market participant will be determined by the Cal ISO. Under the terms of the settlement, we will have no further liability to these non-settling parties. The settlement further provides that we are entitled to pursue claims for reimbursement of fuel costs against various non-settling market participants. We are currently pursuing these claims but are unable to predict the amounts that may be recovered from such parties.

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

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 some dispute. We have 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 were owed by Enron to approximately $57 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. In the event that Enron is victorious in its position that the master netting agreement is unenforceable, our exposure to Enron would be approximately $216 million, with as much as $220 million in unsecured Dynegy claims remaining to enforce against the bankruptcy estate. 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

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(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

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. The appellate court denied our appeal as interlocutory in November 2004. We also filed a motion with the Bankruptcy Court seeking to withdraw from mediation to enable us to proceed to discovery and eventually trial to determine the enforceability of the master netting agreement under the U.S. Bankruptcy Code. The Bankruptcy Court denied our motion and ordered us to resume mediation. The parties engaged in a second court-ordered mediation in November 2004, which was followed by further discussions between the parties, but no settlement has been reached.

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 claims. Reserves have been provided in an aggregate amount we consider reasonable with respect to Enron’s claims. Given the size of the claims at issue, an adverse result could have a material adverse effect on our financial condition, results of operations and cash flows.

Severance Arbitrations. Our former CEO, Chuck Watson, former President, Steve Bergstrom, and former CFO, Rob Doty, each filed for arbitration pursuant to the terms of their employment/severance agreements. These former officers made arbitration claims seeking payments of up to approximately $28.7 million, $10.4 million and $3.4 million, respectively. In addition, each claimed additional amounts related to long-term incentive payments. In May 2004, pursuant to the decision of the arbitration panel, we paid Mr. Bergstrom $10.4 million plus attorneys’ fees, costs and interest. Shortly after the panel’s decisions in the Bergstrom matter, we elected to enter into mediation with Mr. Watson. Through mediation, we agreed to pay 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 4—Restructuring and Impairment Charges—Severance and Other Restructuring Costs beginning on page F-31 of our Form 10-K for further discussion regarding the accrual relating to these former executive officers.

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

Apache Litigation. In May 2002, Apache Corporation filed suit in state court against Versado, as purchaser and processor of Apache’s gas, and DMS, as operator of the Versado assets in New Mexico, seeking more than $9 million in damages. The plaintiff’s petition, as amended, alleges (i) excessive field losses of natural gas from wells owned by the plaintiff, (ii) that Versado engaged in “sham” transactions with affiliates, resulting in Versado not receiving fair market value when it sells gas and liquids, and (iii) that the formula for calculating the amount Versado receives from its buyers of gas and liquids is flawed since it is based on gas price indexes that these same affiliates are alleged to have manipulated by providing false price information to the index publisher. At trial, the plaintiff’s claim with respect to the alleged “sham” transactions and index manipulation, among others, were severed by the court and abated for a future trial, and the jury found in favor of the plaintiff on the remaining lost gas claim, awarding approximately $1.6 million in damages. In May 2004, our motion to set aside this judgment was granted by the court and the jury’s award to the plaintiff was vacated. The plaintiff filed its notice of appeal with the court in October 2004 and its appellate brief in December 2004. The parties attended mediation in February 2005, but did not reach a settlement. Settlement discussions continue outside of mediation. Barring settlement, we expect to file our response to the plaintiff’s appellate briefs in the second quarter 2005. 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.

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(Unaudited)

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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: ABAG v. Sempra Energy et al. (filed in state court in November 2004); Ableman Art Glass v. Encana Corporation et al. (class action filed in federal court in December 2004); Benschiedt (class action filed in state court in February 2004); Bustamante v. The McGraw Hill Companies et al. (class action filed in state court in November 2002); City and County of San Francisco v. Dynegy Inc. et al. (filed in state court in July 2004); County of San Diego v. Dynegy Inc., Dynegy Marketing and Trade, West Coast Power, et al. (filed in state court in July 2004); County of San Mateov. Sempra Energy et al. (filed in state court in December 2004); County of Santa Clarav. Dynegy Inc., Dynegy Marketing and Trade, West Coast Power, et al. (filed in state court in July 2004); Fairhaven Power Company v. Encana Corp. et al. (class action filed in federal court in September 2004); In re Natural Gas Commodity Litigation (class action filed in federal court in January 2004); Leggett v. Duke Energy et al. (class action filed in state court in January 2005); Multiut v. Dynegy Inc. (filed in federal court in December 2004); Nelson Brothers LLC v. Cherokee Nitrogen v. Dynegy Marketing and Trade and Dynegy Inc. (filed in state court in April 2003); Nurserymen’s Exchange v. Sempra Energy et al. (filed in state court in October 2004); Older v. Dynegy Inc. et al. (filed in federal court in September 2004); Owens-Brockway v. Sempra Energy at al. (filed in state court in January 2005); People of the State of Montana et al. v. Williams Energy Marketing et al. (filed in federal court in July 2003); Sacramento Municipal Utility District (SMUD) v. Reliant Energy Services, et al. (filed in state court in November 2004); School Project for Utility Rate Reduction v. Sempra Energy et al. (filed in state court in November 2004); Sierra Pacific Resources and Nevada Power Company v. El Paso Corp. et al. (filed in federal court in April 2003); Tamco v. Dynegy Inc. et al. (filed in state court in December 2004); Texas-Ohio Energy, Inc. v. CenterPoint Energy Inc., et al. (class action filed in federal court in November 2003); and Utility Savings& Refund v. Reliant Energy Services, et al. (class action filed in federal court in November 2004). 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. We have not been served in the Montana case.

Pursuant to various motions filed by the parties to the litigation described above, the gas index pricing lawsuits pending in state court (except for Nelson Brothers) have been consolidated before a single judge in state court in San Diego. These cases are now entitled the “Judicial Counsel Coordinated Proceeding (JCCP) 4221, 4224, 4226, and 4228, the Natural Gas Anti-Trust Cases, I, II, III, & IV,” which we refer to as the “Coordinated Gas Index Cases.” The parties are presently engaged in discovery. The Nelson Brothers lawsuit involves an alleged breach of a gas purchase contract and is pending in Alabama state court. The parties are presently engaged in discovery. In March 2005, we moved to compel the matter to arbitration. The trial court denied the motion, and in April 2005 we appealed the decision to the Alabama Supreme Court.

As to the gas index pricing lawsuits filed in federal court, the Sierra Pacific case was dismissed in December 2004 on defendants’ motion. In Texas-Ohio, the defendants filed a motion to dismiss in May 2004, which the court granted in April 2005. In the In re Natural Gas Commodity Litigation matter, pending in New York federal court, the parties are actively engaged in discovery following denial of the appeal of the previous denial of defendants’ motion to dismiss. In April 2005, defendants filed a joint opposition to the motion for class certification filed by the plaintiffs earlier in the year. The Multiut case involves a counterclaim filed by the defendant, Multiut, against whom we have a pending breach of gas purchase contract claim. That case is proceeding in federal court in Illinois. The remaining federal court cases (Abelman, Fairhaven Power, Utility Savings and Leggett) are pending transfer, or have already been transferred, to the federal judge in Nevada who presided over the Texas-Ohio matter.

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