Edgar Filing: DYNEGY INC.

March 31,
2007

December 31,
2006

(in millions)

One Day VaR—95% Confidence Level

One Day VaR—99% Confidence Level

Average VaR for the Year-to-Date Period—95% Confidence Level

Form 10-Q for the quarterly period ended March 31, 2007

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2007

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

For the transition period from to

Commission file number: 001-33443

DYNEGY INC.

(Exact name of registrant as specified in its charter)


Delaware		20-5653152
(State of incorporation)		(I.R.S. Employer Identification No.)

1000 Louisiana, Suite 5800

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 507-6400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ Accelerated filer ¨ Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: Class A common stock, $0.01 par value per share, 499,227,487 shares outstanding as of May 3, 2007; Class B common stock, $0.01 par value per share, 340,000,000 shares outstanding as of May 3, 2007.

DYNEGY INC.

TABLE OF CONTENTS


		Page
PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS:

Condensed Consolidated Balance Sheets:
March 31, 2007 and December 31, 2006		5
Condensed Consolidated Statements of Operations:
For the three months ended March 31, 2007 and 2006		6
Condensed Consolidated Statements of Cash Flows:
For the three months ended March 31, 2007 and 2006		7
Condensed Consolidated Statements of Comprehensive Income (Loss):
For the three months ended March 31, 2007 and 2006		8
Notes to Condensed Consolidated Financial Statements		9

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		28
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		45
Item 4. CONTROLS AND PROCEDURES		47

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS		48
Item 1A. RISK FACTORS		48
Item 2. UNREGISTERED SALES OF SECURITIES AND USE OF PROCEEDS		52
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		53
Item 6. EXHIBITS		53

EXPLANATORY NOTE

We are a Delaware corporation formerly named Dynegy Acquisition, Inc. We entered into a Plan of Merger, Contribution and Sale Agreement (the “Merger Agreement”), dated as of September 14, 2006, with Falcon Merger Sub Co., an Illinois corporation (“Merger Sub”), LSP Gen Investors, L.P., a Delaware limited partnership, LS Power Partners, L.P., a Delaware limited partnership, LS Power Equity Partners PIE I, L.P., a Delaware limited partnership, LS Power Equity Partners, L.P., a Delaware limited partnership, LS Power Associates, L.P., a Delaware limited partnership, and Dynegy Illinois Inc., an Illinois corporation (formerly named Dynegy Inc.) (“Dynegy Illinois”). On March 29, 2007, at a special meeting of the shareholders of Dynegy Illinois, the shareholders of Dynegy Illinois adopted the Merger Agreement and approved the related merger of Merger Sub, our then-wholly owned subsidiary, with and into Dynegy Illinois (the “Merger”).

As a result of the Merger, which was completed on April 2, 2007, Dynegy Illinois became our wholly owned subsidiary, the then-shareholders of Dynegy Illinois became our stockholders and each Dynegy Illinois shareholder received one share of our Class A common stock for each share of Class A common stock or Class B common stock of Dynegy Illinois held by it. In addition, in connection with the completion of the Merger and the other transactions contemplated by the Merger Agreement, our name was changed from Dynegy Acquisition, Inc. to Dynegy Inc.

Unless otherwise stated herein or the context otherwise requires, references in this Quarterly Report on Form 10-Q to “Dynegy”, “the company”, “the Company”, “we”, “our”, or “us” refer to Dynegy Inc. and its direct and indirect subsidiaries and include Dynegy Illinois before it became a wholly owned subsidiary of Dynegy Inc. by way of the Merger. As the Merger was not completed until April 2, 2007, the condensed consolidated financial statements as of and for the three months ended March 31, 2007 and 2006, the notes thereto and the related financial and other information and discussion contained in this Quarterly Report on Form 10-Q relates to, and is with respect to, Dynegy Illinois.

We are a “successor registrant” to Dynegy Illinois for purposes of the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended, and the rules and regulations of the Securities and Exchange Commission promulgated thereunder.

DEFINITIONS

As used in this Form 10-Q, the abbreviations contained herein have the meanings set forth below.


ARB		Accounting Research Bulletin
APB		Accounting Principles Board
ARO		Asset retirement obligation
Bcf/d		Billion cubic feet per day
Cal ISO		The California Independent System Operator
CFTC		Commodity Futures Trading Commission
CPUC		California Public Utilities Commission
CRA		Canada Revenue Agency
CRM		Our customer risk management business segment
DHI		Dynegy Holdings Inc., our primary financing subsidiary
DMG		Dynegy Midwest Generation, Inc.
DMSLP		Dynegy Midstream Services L.P.
DMT		Dynegy Marketing and Trade
DNE		Dynegy Northeast Generation
DPM		Dynegy Power Marketing Inc.
EITF		Emerging Issues Task Force
EPA		Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas, Inc.
ERISA		The Employee Retirement Income Security Act of 1974, as amended
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIN		FASB Interpretation
FSP		FASB Staff Position
GAAP		Generally Accepted Accounting Principles of the United States of America
GEN		Our power generation business
GEN-MW		Our power generation business - Midwest segment
GEN-NE		Our power generation business - Northeast segment
GEN-SO		Our power generation business - South segment
GEN-WE		Our power generation business - West segment
IRS		Internal Revenue Service
ISO		Independent System Operator
KWh		Kilowatt hour
LNG		Liquefied natural gas
Mcf		Thousand cubic feet
MISO		Midwest Independent Transmission Operator, Inc.
MMBtu		Millions of British thermal units
MMCFD		Million cubic feet per day
MW		Megawatts
MWh		Megawatt hour
NGL		Our natural gas liquids business segment
NOL		Net operating loss
NOV		Notice of Violation issued by the EPA
NO_x		Nitrogen oxide
NRG		NRG Energy, Inc.
NYISO		New York Independent System Operator
NYSDEC		New York State Department of Environmental Conservation
PRB		Powder River Basin coal
RMR		Reliability Must Run
RTO		Regional Transmission Organization
SEC		U.S. Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
SO₂		Sulfur dioxide
SPE		Special Purpose Entity
VaR		Value at Risk
VIE		Variable Interest Entity

PART I. FINANCIAL INFORMATION

Item 1—FINANCIAL STATEMENTS

DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)


	March 31, 2007			December 31, 2006
ASSETS

Current Assets
Cash and cash equivalents	$	369		$	371
Restricted cash		271			280
Accounts receivable, net of allowance for doubtful accounts of $46 and $48, respectively		285			257
Accounts receivable, affiliates		1			1
Inventory		182			194
Assets from risk-management activities		309			701
Deferred income taxes		145			93
Prepayments and other current assets		106			92
Assets held for sale (Note 3)		1			—

Total Current Assets		1,669			1,989

Property, Plant and Equipment		6,374			6,473
Accumulated depreciation		(1,508	)		(1,522	)

Property, Plant and Equipment, Net		4,866			4,951
Other Assets
Restricted investments		82			83
Assets from risk-management activities		61			16
Intangible assets		332			347
Deferred income taxes		2			12
Other long-term assets		138			139
Assets held for sale (Note 3)		57			—

Total Assets	$	7,207		$	7,537


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities
Accounts payable	$	172		$	172
Accrued interest		85			66
Accrued liabilities and other current liabilities		142			231
Liabilities from risk-management activities		349			629
Notes payable and current portion of long-term debt		54			68

Total Current Liabilities		802			1,166

Long-term debt		2,987			2,990
Long-term debt to affiliates		200			200

Long-Term Debt		3,187			3,190
Other Liabilities
Liabilities from risk-management activities		84			35
Deferred income taxes		516			469
Other long-term liabilities		401			410

Total Liabilities		4,990			5,270

Commitments and Contingencies (Note 9)
Stockholders’ Equity
Class A Common Stock, no par value, 900,000,000 shares authorized at March 31, 2007 and December 31, 2006; 403,386,087 and 403,137,339 shares issued and outstanding at March 31, 2007 and December 31, 2006, respectively		3,368			3,367
Class B Common Stock, no par value, 360,000,000 shares authorized at March 31, 2007 and December 31, 2006; 96,891,014 shares issued and outstanding at March 31, 2007 and December 31, 2006		1,006			1,006
Additional paid-in capital		42			39
Subscriptions receivable		(8	)		(8	)
Accumulated other comprehensive income (loss), net of tax		(6	)		67
Accumulated deficit		(2,114	)		(2,135	)
Treasury stock, at cost, 2,061,089 and 1,787,004 shares at March 31, 2007 and December 31, 2006, respectively		(71	)		(69	)

Total Stockholders’ Equity		2,217			2,267

Total Liabilities and Stockholders’ Equity	$	7,207		$	7,537

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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


	Three Months Ended March 31,
	2007			2006
Revenues	$	573		$	600
Cost of sales, exclusive of depreciation shown separately below		(386	)		(409	)
Depreciation and amortization expense		(56	)		(59	)
Impairment and other charges		—			(2	)
General and administrative expenses		(53	)		(51	)

Operating income		78			79
Earnings from unconsolidated investments		—			2
Interest expense		(67	)		(98	)
Other income and expense, net		8			20

Income from continuing operations before income taxes		19			3
Income tax expense (Note 12)		(5	)		(3	)

Income from continuing operations		14			—
Income from discontinued operations, net of tax expense of zero and $1, respectively		—			—

Income before cumulative effect of change in accounting principle		14			—
Cumulative effect of change in accounting principle, net of tax expense of zero		—			1

Net income		14			1
Less: preferred stock dividends		—			5

Net income (loss) applicable to common stockholders	$	14		$	(4	)

Earnings (Loss) Per Share (Note 8):
Basic earnings (loss) per share:
Income (loss) from continuing operations	$	0.03		$	(0.01	)
Income from discontinued operations		—			—
Cumulative effect of change in accounting principle		—			—

Basic earnings (loss) per share	$	0.03		$	(0.01	)

Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	0.03		$	(0.01	)
Income from discontinued operations		—			—
Cumulative effect of change in accounting principle		—			—

Diluted earnings (loss) per share	$	0.03		$	(0.01	)

Basic shares outstanding		496			400
Diluted shares outstanding		498			526

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)


	Three Months Ended March 31,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	14		$	1
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		57			63
Impairment and other charges		—			2
Earnings from unconsolidated investments, net of cash distributions		—			(2	)
Risk-management activities		3			(41	)
Gain on sale of assets, net		—			(1	)
Deferred income taxes		3			6
Cumulative effect of change in accounting principle, net of tax (Note 1)		—			(1	)
Legal and settlement charges		17			15
Other		10			15
Changes in working capital:
Accounts receivable		(29	)		310
Inventory		18			9
Prepayments and other assets		(13	)		76
Accounts payable and accrued liabilities		(37	)		(763	)
Changes in non-current assets		(1	)		(2	)
Changes in non-current liabilities		2			2

Net cash provided by (used in) operating activities		44			(311	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(34	)		(18	)
Proceeds from asset sales, net		—			205
Business acquisitions, net of cash acquired		(1	)		(40	)
Decrease in restricted cash and restricted investments		9			322

Net cash provided by (used in) investing activities		(26	)		469

CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term borrowings		(19	)		—
Proceeds from issuance of capital stock		—			3
Dividends and other distributions, net		—			(11	)
Other financing, net		(1	)		(8	)

Net cash used in financing activities		(20	)		(16	)

Net increase (decrease) in cash and cash equivalents		(2	)		142
Cash and cash equivalents, beginning of period		371			1,549

Cash and cash equivalents, end of period	$	369		$	1,691

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)


	Three Months Ended March 31,
	2007			2006
Net income	$	14		$	1
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		(59	)		19
Reclassification of mark-to-market gains to earnings, net		(15	)		(14	)

Changes in cash flow hedging activities, net (net of tax benefit (expense) of $44 and ($3), respectively)		(74	)		5
Recognized prior service cost and actuarial loss		1			—
Foreign currency translation adjustments		—			(1	)

Other comprehensive income (loss), net of tax		(73	)		4

Comprehensive income (loss)	$	(59	)	$	5

See the notes to condensed consolidated financial statements.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

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 audited consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2006, as amended, 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 statement 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 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 (i) developing fair value assumptions, including estimates of future cash flows and discount rates, (ii) analyzing tangible and intangible assets for possible impairment, (iii) estimating the useful lives of our assets, (iv) assessing future tax exposure and the realization of tax assets, (v) determining amounts to accrue for contingencies, guarantees and indemnifications and (vi) 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 to conform with current-period presentation.

Accounting Principle Adopted

FIN No. 48. On July 12, 2006, the FASB issued FIN No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN No. 48”), which provides clarification of SFAS 109, “Accounting for Income Taxes” with respect to the recognition of income tax benefits of uncertain tax positions in the financial statements. FIN No. 48 requires that uncertain tax positions be reviewed and assessed with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard. We adopted the provisions of FIN No. 48 on January 1, 2007 and recorded a $7 million decrease to our accumulated deficit as of January 1, 2007 to reflect the cumulative effect of adopting FIN No. 48.

As of January 1, 2007, we have approximately $111 million of unrecognized tax benefits. Included in the balance are $44 million of unrecognized tax benefits whose uncertainty relates to the timing of the deductibility rather than the determination of deductibility. Recognition of these adjustments would not impact our effective tax rate, but would accelerate payment of cash taxes to the respective taxing authority. We have $67 million of unrecognized tax benefits, which, if recognized, would impact our effective tax rate.

Additionally, in conjunction with the adoption of FIN No. 48, we have reduced our regular federal tax NOL carryforwards by $253 million, from $948 million to $695 million. The reduction was offset by corresponding changes to our net deferred tax liability and reserve for uncertain tax positions.

We recognize accrued interest expense and penalties related to unrecognized tax benefits as income tax expense. We had approximately $5 million for the payment of interest and penalties accrued at March 31, 2007 and January 1, 2007, respectively.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

We expect that our unrecognized tax benefits could change due to the settlement of audits and the expiration of statutes of limitation in the next twelve months; however, we do not anticipate any such change to have a significant impact on our results of operations, our financial position or cash flows.

We file a consolidated income tax return in the U.S. federal jurisdiction, and other income tax returns in various states and foreign jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2001. The IRS commenced an examination of our U.S. consolidated income tax return for 2004 through 2005 in the second quarter 2006 that is anticipated to be completed by the end of 2007. The IRS examination for 2001 through 2002 was completed in January 2006. We have reached tentative agreement on all audit issues and are awaiting final resolution with the IRS. The CRA is currently examining 2002 through 2004 and we are expecting completion of the audit in 2007 or 2008.

Accounting Principles Not Yet Adopted

SFAS No. 157. On September 15, 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements. Accordingly, SFAS No. 157 does not require any new fair value measurements; however, the application of SFAS No. 157 will change current practice for some entities. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact of this statement on our financial statements.

SFAS No. 159. On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure eligible items at fair value at specified election dates. A business entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact of this statement on our financial statements.

Note 2—LS Power Business Combination

On March 29, 2007, at a special meeting of the shareholders of Dynegy Illinois, the shareholders of Dynegy Illinois (i) adopted the Plan of Merger, Contribution and Sale Agreement, dated as of September 14, 2006 (the “Merger Agreement”), by and among Dynegy, Dynegy Illinois, Falcon Merger Sub Co., an Illinois corporation and a then-wholly owned subsidiary of Dynegy (“Merger Sub”), LSP Gen Investors, L.P., LS Power Partners, L.P., LS Power Equity Partners PIE I, L.P., LS Power Equity Partners, L.P. and LS Power Associates, L.P. (“LS Associates” and, collectively, the “LS Contributing Entities”) and (ii) approved the merger of Merger Sub with and into Dynegy Illinois (the “Merger”).

On April 2, 2007, in accordance with the Merger Agreement, (i) the Merger was effected, as a result of which Dynegy Illinois became a wholly owned subsidiary of Dynegy and each share of the Class A common stock and Class B common stock of Dynegy Illinois outstanding immediately prior to the Merger was converted into the right to receive one share of the Class A common stock of Dynegy, and (ii) the LS Contributing Entities transferred all of the interests owned by them in entities that own 11 power generation facilities to Dynegy.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

As part of the transactions contemplated by the Merger Agreement, LS Associates transferred its interests in certain power generation development projects to DLS Power Holdings, LLC, a newly formed Delaware limited liability company (“DLS Power Holdings”), and contributed 50% of the membership interests in DLS Power Holdings to Dynegy. In addition, immediately after the completion of the Merger, LS Associates and Dynegy each contributed $5 million to DLS Power Holdings as their initial capital contributions, and also contributed their respective interests in certain additional power generation development projects to DLS Power Holdings. In connection with the formation of DLS Power Holdings, LS Associates formed DLS Power Development Company, LLC, a Delaware limited liability company (“DLS Power Development”). LS Associates and Dynegy each now own 50% of the membership interests in DLS Power Development.

In consideration of the transfer to Dynegy of their interests in the entities that own 11 power generation facilities and 50% of the membership interests in DLS Power Holdings and DLS Power Development, the LS Contributing Entities received (i) 340 million shares of the Class B common stock of Dynegy, (ii) $100 million in cash and (iii) a promissory note in the aggregate principal amount of $275 million (the “Note”) (which was simultaneously issued and repaid in full without interest or prepayment penalty). Dynegy also, via its indirect wholly owned subsidiary Griffith Holdings, LLC, simultaneously issued to the LS Contributing Entities, and repaid in full without interest or prepayment penalty and cancelled, an additional $70 million of project-related debt (the “Griffith Debt”) in connection with the completion of the Merger Agreement transactions. Dynegy funded the cash payment and the repayment of the Note and the Griffith Debt using cash on hand and borrowings by DHI (and subsequent permitted distributions to Dynegy) of (i) an aggregate $275 million under the Revolving Facility (as defined below) and (ii) an aggregate $70 million under the new Term Loan B (as defined below). Please read Note 7—Debt—Fifth Amended and Restated Credit Facility for further discussion.

The consummation of the Merger Agreement with the LS Contributing Entities constituted a change in control as defined in our severance pay plans, as well as the various long-term incentive award grant agreements. As a result, all restricted stock and stock option awards previously granted to employees and outstanding vested in full on April 2, 2007 upon the closing of the Merger Agreement. Specifically, the vesting of the restricted stock awards granted in 2005 and 2006 and the unvested tranches of stock option awards granted in those years was accelerated. Accordingly, we will record a charge of approximately $6 million in the second quarter 2007.

In addition, LSP Kendall Holding LLC, one of the entities transferred to Dynegy by the LS Contributing Entities pursuant to the Merger Agreement, was party to a power tolling contract with another of our subsidiaries. This power tolling agreement had a fair value of approximately $50 million as of April 2, 2007, representing a liability from the perspective of LSP Kendall Holding LLC. Upon completion of the Merger Agreement, this power tolling agreement was effectively settled, which will result in a second quarter 2007 gain equal to the fair value of this contract, in accordance with EITF Issue 04-01, “Accounting for Pre-existing Contractual Relationships Between the Parties to a Purchase Business Combination” (“EITF Issue 04-1”). We expect to record a second quarter 2007 pre-tax gain of approximately $50 million, which will be included as a reduction to cost of sales on our unaudited condensed consolidated statements of operations.

Note 3—Discontinued Operations

Calcasieu. On January 31, 2007, we entered into an agreement to sell our interest in the Calcasieu power generation facility to Entergy Gulf States, Inc. (“Entergy”) for approximately $57 million, subject to regulatory approval and other closing conditions. The transaction is expected to close in early 2008. Beginning in the first quarter 2007, Calcasieu met the held for sale classification requirements of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”), and is classified as such on our unaudited condensed consolidated balance sheet. The major classes of current and long-term assets classified as assets held for sale at March 31, 2007 are $57 million of Property, Plant and Equipment, Net, and $1 million of Inventory.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

SFAS No. 144 also requires that long-lived assets not be depreciated or amortized while they are classified as held for sale. As a result, we discontinued depreciation and amortization of Calcasieu’s property, plant and equipment during the first quarter 2007. Depreciation and amortization expense related to Calcasieu totaled less than $1 million in the three-month period ended March 31, 2007, compared to approximately $1 million in the three-month period ended March 31, 2006. Also pursuant to SFAS No. 144, we are reporting the results of Calcasieu’s operations as a discontinued operation. Accordingly, the facility’s results have been included in discontinued operations for all periods presented.

Natural Gas Liquids. On October 31, 2005, we completed the sale of DMSLP, which comprised substantially all remaining operations of our NGL segment, to Targa Resources Inc. (“Targa”) and two of its subsidiaries for $2.44 billion in cash.

Other. We sold or liquidated some of our operations during 2003, including our U.K. CRM business, which have been accounted for as discontinued operations under SFAS No. 144.

The following table summarizes information related to all of our discontinued operations, including the NGL operations discussed above:


	Calcasieu			U.K. CRM		NGL		Total
	(in millions)
Three Months Ended March 31, 2007
Revenues	$	1		$	—	$	—	$	1
Three Months Ended March 31, 2006
Income from operations before taxes		(1	)		1		1		1
Income from operations after taxes		(1	)		—		1		—

Note 4—Restructuring Charges

2005 Restructuring. In December 2005, in order to better align our corporate cost structure with a single line of business and as part of a comprehensive effort to reduce on-going operating expenses, we announced a restructuring plan (the “2005 Restructuring Plan”). The 2005 Restructuring Plan resulted in a reduction of approximately 40 positions and was substantially complete by March 31, 2006. We recognized a pre-tax charge of $11 million in the fourth quarter 2005. We recognized approximately $2 million of charges in the first quarter 2006, when transitional services were completed by certain affected employees. These charges related entirely to severance costs.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

2002 Restructuring. 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 2007 activity for the liabilities recorded in connection with this restructuring:


	Severance		Cancellation Fees and Operating Leases			Total
	(in millions)
Balance at December 31, 2006	$	3	$	7		$	10
Cash payments		—		(2	)		(2	)

Balance at March 31, 2007	$	3	$	5		$	8

We expect the $5 million accrual as of March 31, 2007 associated with cancellation fees and operating leases to be paid by the end of 2007, when the leases expire.

In addition to the $5 million accrual above, we have a $1 million accrual for operating leases made in connection with the sale of DMSLP. We expect this amount to be paid by the end of 2007 when the leases expire. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Natural Gas Liquids beginning on page F-23 of our Form 10-K for further information.

Note 5—Risk Management Activities and Accumulated Other Comprehensive Income (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 6—Risk Management Activities and Financial Instruments beginning on page F-32 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 business 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, 2007, we recorded a $5 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, 2006, there was no 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, 2007 and 2006, no amounts were reclassified to earnings in connection with forecasted transactions that were considered probable of not occurring.

The balance in cash flow hedging activities, net at March 31, 2007 is expected to be reclassified to future earnings, contemporaneously with the related purchases of fuel, sales of electricity and payments of interest, as applicable to each type of hedge. Of this amount, after-tax gains of approximately $3 million are currently estimated to be reclassified into earnings over the 12-month period ending March 31, 2008. 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.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

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, 2007 and 2006, 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, 2007 and 2006, 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 have remaining investments in foreign subsidiaries, the net assets of which are exposed to currency exchange-rate volatility. As of March 31, 2007, we had no net investment hedges in place.

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


	March 31, 2007			December 31, 2006
	(in millions)
Cash flow hedging activities, net	$	2		$	76
Foreign currency translation adjustment		23			23
Unrecognized prior service cost and actuarial loss		(42	)		(43	)
Available for sale securities		11			11

Accumulated other comprehensive income (loss), net of tax	$	(6	)	$	67

Note 6—Variable Interest Entities

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 hydroelectric generation facilities in Pennsylvania. The entities owning these facilities meet the definition of VIEs. In accordance with the purchase agreement, Exelon Corporation, which we refer to as “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. 46(R), “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51”.

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, 2007, the equipment leases have remaining terms from one to fifteen years and involve a maximum aggregate obligation of $114 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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

purchase agreement. All 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 aggregate balance of the Tracking Accounts as of March 31, 2007, was approximately $332 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.

Note 7—Debt

Fifth Amended and Restated Credit Facility. On April 2, 2007, we entered into a fifth amended and restated credit agreement (the “Fifth Amended and Restated Credit Facility”) with Citicorp USA, Inc. and JPMorgan Chase Bank, N.A., as co-administrative agents, JPMorgan Chase Bank, N.A., as collateral agent, Citicorp USA Inc., as payment agent, J.P. Morgan Securities Inc. and Citigroup Global Markets Inc., as joint lead arrangers and joint book-runners, and the other financial institutions party thereto as lenders or letter of credit issuers.

The Fifth Amended and Restated Credit Facility amends DHI’s former credit facility (the Fourth Amended and Restated Credit Facility, which was last amended on July 11, 2006) by increasing the amount of the existing $470 million revolving credit facility (the “Revolving Facility”) to $850 million, increasing the amount of the existing $200 million term letter of credit facility (the “Term L/C Facility”) to $400 million and adding a $70 million senior secured term loan facility (“Term Loan B”).

Loans and letters of credit are available under the Revolving Facility and letters of credit are available under the Term L/C Facility for general corporate purposes. Letters of credit issued under DHI’s former credit facility will be continued under the Fifth Amended and Restated Credit Facility. The Term Loan B was available to pay a portion of the consideration under the Merger Agreement. In connection with the completion of the transactions contemplated by the Merger Agreement, an aggregate $275 million under the Revolving Facility, an aggregate $400 million under the Term L/C Facility (with the proceeds placed in a collateral account to support the issuance of letters of credit), and an aggregate $70 million under Term Loan B (representing all available borrowings under Term Loan B) were drawn.

The Fifth Amended and Restated Credit Facility is secured by certain assets of DHI and is guaranteed by Dynegy, Dynegy Illinois and certain subsidiaries of DHI. In addition, the obligations under the Fifth Amended and Restated Credit Facility and certain other obligations to the lenders thereunder and their affiliates are secured by substantially all of the assets of such guarantors. The Revolving Facility matures on April 2, 2012, and the Term L/C Facility and Term Loan B each mature on April 2, 2013. The principal amount of the Term L/C Facility is due in a single payment at maturity; the principal amount of Term Loan B is due in quarterly installments of $175,000 in arrears commencing December 31, 2007, with the unpaid balance due at maturity.

Borrowings under the Fifth Amended and Restated Credit Facility bear interest, at DHI’s option, at either the base rate, which is calculated as the higher of Citibank, N.A.’s publicly announced base rate and the federal funds rate in effect from time to time, plus 0.50% or the Eurodollar rate (which is based on rates in the London interbank Eurodollar market), in each case plus an applicable margin.

The applicable margin for borrowings under the Revolving Facility depends on the Standard & Poor’s Ratings Services (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”) credit ratings of the Revolving Facility, with higher credit ratings resulting in lower rates. The applicable margin for such borrowings will be either 0.125% or

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

0.50% per annum for base rate loans and either 1.125% or 1.50% per annum for Eurodollar loans, with the lower applicable margin being payable if the ratings for the Revolving Facility by S&P and Moody’s are BB+ and Ba1 or higher, respectively, and the higher applicable margin being payable if such ratings are less than BB+ and Ba1. The applicable margins for the Term L/C Facility and Term Loan B are 0.50% for base rate loans and 1.50% for Eurodollar loans.

An unused commitment fee of either 0.25% or 0.375% is payable on the unused portion of the Revolving Facility, with the lower commitment fee being payable if the ratings for the Revolving Facility by S&P and Moody’s are BB+ and Ba1 or higher, respectively, and the higher commitment fee being payable if such ratings are less than BB+ and Ba1.

The Fifth Amended and Restated Credit Facility contains mandatory prepayment provisions associated with specified asset sales and dispositions (including as a result of casualty or condemnation). The Fifth Amended and Restated Credit Facility also contains customary affirmative covenants and negative covenants and events of default. Subject to certain exceptions, DHI and its subsidiaries are subject to restrictions on incurring additional indebtedness, limitations on capital expenditures and limitations on dividends and other payments in respect of capital stock.

The Fifth Amended and Restated Credit Facility also contains certain financial covenants, including (i) a covenant (measured as of the last day of the relevant fiscal quarter as specified below) that requires DHI and certain of its subsidiaries to maintain a ratio of secured debt to adjusted earnings before interest, taxes, depreciation and amortization (“EBITDA”) for DHI and its relevant subsidiaries of no greater than 3.0:1 (June 30, 2007); 2.75:1 (September 30, 2007 and thereafter through and including March 31, 2009); and 2.5:1 (June 30, 2009 and thereafter); and (ii) a covenant that requires DHI and certain of its subsidiaries to maintain a ratio of adjusted EBITDA to consolidated interest expense for DHI and its relevant subsidiaries as of the last day of the measurement periods ending June 30, 2007 and thereafter through and including December 31, 2008 of no less than 1.5:1; ending March 31, 2009 and June 30, 2009 of no less than 1.625:1; and ending September 30, 2009 and thereafter of no less than 1.75:1.

Repayments. On January 2, 2007, we made a $19 million principal payment on the Sithe Energies debt.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

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 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:


	Three Months Ended March 31,
	2007		2006
	(in millions, except per share amounts)
Income from continuing operations	$	14	$	—
Convertible preferred stock dividends		—		(5	)

Income (loss) from continuing operations for basic loss per share		14		(5	)
Effect of dilutive securities:
Interest on convertible subordinated debentures		—		2
Dividends on Series C convertible preferred stock		—		5

Income from continuing operations for diluted earnings (loss) per share	$	14	$	2

Basic weighted-average shares		496		400
Effect of dilutive securities:
Stock options and restricted stock		2		2
Convertible subordinated debentures		—		55
Series C convertible preferred stock		—		69

Diluted weighted-average shares		498		526

Earnings (loss) per share from continuing operations:
Basic	$	0.03	$	(0.01	)

Diluted (1)	$	0.03	$	(0.01	)

(1)

When an entity has a net loss from continuing operations, SFAS No. 128, “Earnings per Share”, prohibits the inclusion of potential common shares in the computation of diluted per-share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three months ended March 31, 2006.

Note 9—Commitments and Contingencies

Set forth below is a summary of certain ongoing legal proceedings. In accordance with SFAS No. 5, “Accounting for Contingencies”, we record reserves for contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. In addition, we disclose matters for which management believes a material loss is at least reasonably possible. In all instances, management has assessed the matters below based on current information and made a judgment concerning their potential outcome, giving due

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

consideration to the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may prove materially inaccurate and such judgment is made subject to the known uncertainty of litigation.

In addition to the matters discussed below, we are party to numerous legal proceedings arising in the ordinary course of business or related to discontinued business operations. In management’s opinion, the disposition of these matters will not materially adversely affect our financial condition, results of operations or cash flows.

Illinova Arbitration. In May 2007, we received an adverse arbitration decision relating to a legacy litigation matter. In June 2000, our Illinova Generating Company (“IGC”) subsidiary sold a minority interest it held in a Cleburne, Texas generating plant to Ponderosa Pine Energy (“PPE”). Brazos Electric Cooperative, Inc. (“Brazos”), the party to an offtake agreement from the plant, brought legal action against PPE alleging that PPE’s purchase did not comply with the terms of Brazos’ offtake agreement. Brazos received a favorable arbitration award against PPE, which in turn sought recovery from IGC and the other former owners of the plant for indemnification. The panel in PPE’s arbitration action recently ruled that IGC and the other former owners of the plant must indemnify PPE for the Brazos arbitration award, with IGC’s portion being defined as approximately $17 million. We recognized a legal and settlement charge of approximately $17 million for the first quarter 2007 relating to this adverse ruling. We are considering whether to appeal the award; absent appeal, payment is required within 30 days.

Gas Index Pricing Litigation. We and our former joint venture affiliate West Coast Power are named defendants in numerous lawsuits in state and federal court claiming damages resulting from alleged price manipulation and false reporting of natural gas prices. The cases are pending in California, Nevada, Alabama, Wisconsin and Missouri. 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 natural gas index publications. All of the complaints rely heavily on prior FERC and CFTC investigations into and reports concerning index-reporting manipulation in the energy industry. Except as specifically mentioned below, the cases are actively engaged in discovery.

During the last year, several cases pending in Nevada federal court were dismissed on defendants’ motions. Certain plaintiffs have appealed to the Court of Appeals for the Ninth Circuit, which coordinated the cases before the same appellate panel. A decision from the Court of Appeals is expected sometime in 2007. In February 2007, a Tennessee state court case was also dismissed on defendants’ motion.

Pursuant to various motions, the cases pending in California state court have been coordinated before a single judge in San Diego (“Coordinated Gas Index Cases”). In August 2006, we entered into an agreement to settle the class action claims in the Coordinated Gas Index Cases for $30 million. The settlement does not include similar claims filed by individual plaintiffs in the Coordinated Gas Index Cases, which we continue to defend vigorously. In December 2006, the court granted final approval of the settlement and dismissed the class action claims. Also in August 2006, we entered into an agreement to settle the class action claims by California natural gas re-sellers and co-generators (to the extent they purchased natural gas to generate electricity for re-sale) pending in Nevada federal court for $2.4 million. The court granted preliminary approval of this settlement in May 2007. Both settlements are without admission of wrongdoing, and Dynegy and West Coast Power continue to deny class plaintiffs’ allegations.

We are analyzing the remaining natural gas index cases and are vigorously defending 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.

California Market Litigation. We and various other power generators and marketers were defendants in numerous lawsuits alleging rate and market manipulation in California’s wholesale electricity market during the California energy crisis several years ago. The complaints generally alleged unfair, unlawful and deceptive trade practices in violation of the California Unfair Business Practices Act and sought injunctive relief, restitution and unspecified actual and treble damages. All of these cases have been dismissed on grounds of federal preemption except for one remaining action that is pending in federal court.

We believe that we have meritorious defenses to the remaining federal court claims and are vigorously defending against them. We cannot predict with certainty whether we will incur any liability in connection with the remaining lawsuit. Given the nature of the claims, however, an adverse result in the pending action could have a material adverse effect on our financial condition, results of operations and cash flows.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

Illinois Auction Complaints. On March 15, 2007, as amended on March 16, the Attorney General of the State of Illinois (the “IAG”) filed a complaint at the Federal Energy Regulatory Commission (“FERC”) against 16 electricity suppliers engaged in wholesale power sales, challenging the results of the Illinois reverse power procurement auction conducted in September 2006. The complaint alleges that the prices charged under supply contracts resulting from the auction process are not just and reasonable. The complaint also requests that FERC investigate purported price manipulation by the wholesale suppliers in the auction process. The complaint names DPM among the respondents. The public version of the complaint served upon DPM is heavily redacted resulting in substantial uncertainty regarding the specific allegations against DPM and the specific relief sought by the IAG against DPM. The ICC has intervened in the proceeding before FERC and has stated in its pleading that it has not found any evidence of collusive behavior or other anticompetitive actions by bidders in the Illinois Auction.

Shortly after the IAG’s filing at FERC, two civil class action complaints against 21 wholesale electricity suppliers and utilities, including DPM, were filed in Illinois state court. The complaints largely mirror the IAG’s filing and seek unspecified actual and punitive damages. In late April 2007, the defendants filed notices of removal to federal court in both cases. We believe that plaintiffs’ claims in these matters are without merit and intend to defend against them vigorously.

We believe that the claims of the IAG and the civil plaintiffs are without merit and we intend to defend against them vigorously. However, given the gravity of their claims, an adverse ruling in some or all of these proceedings could have a material adverse effect on our financial condition, results of operations and cash flows.

Danskammer State Pollutant Discharge Elimination System Permit. In January 2005, the New York State Department of Environmental Conservation (“NYSDEC”) issued a Draft SPDES Permit renewal for the Danskammer plant, and an adjudicatory hearing was scheduled for the fall of 2005. Three environmental groups sought to impose a permit requirement that the Danskammer plant install a closed cycle cooling system in order to reduce the volume of water withdrawn from the Hudson River, thus reducing aquatic organism mortality. The petitioners claim that only a closed cycle cooling system meets the Clean Water Act’s requirement that the cooling water intake structures reflect best technology available (“BTA”) for minimizing adverse environmental impacts.

A formal evidentiary hearing was held in November and December 2005. The Deputy Commissioner’s decision directing that the NYSDEC staff issue the revised Draft SPDES Permit was issued in May 2006. In June 2006, the NYSDEC issued the revised SPDES Permit with conditions generally favorable to us. While the revised SPDES Permit does not require installation of a closed cycle cooling system, it does require aquatic organism mortality reductions resulting from NYSDEC’s determination of BTA requirements under its regulations. In July 2006, two of the petitioners filed suit in the Supreme Court of the State of New York seeking to vacate the Deputy Commissioner’s decision and the revised Danskammer SPDES Permit. On March 26, 2007, the Court transferred the lawsuit to the Third Department Appellate Division. The case will now proceed as a normal appeal from a final agency decision and the decision will be based on whether there is substantial evidence in the record to support the agency decision. We believe that the decision of the Deputy Commissioner is well reasoned and will be affirmed. However, in the event the decision is not affirmed and we ultimately are required to install a closed cycle cooling system, this could have a material adverse effect on our financial condition, results of operations and cash flows.

Roseton State Pollutant Discharge Elimination System Permit. In April 2005, the NYSDEC issued to DNE a draft SPDES Permit renewal (the “Draft SPDES Permit”) for the Roseton plant. The Draft SPDES Permit requires the facility to actively manage its water intake to substantially reduce mortality of aquatic organisms.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

In July 2005, a public hearing was held to receive comments on the Draft SPDES Permit. Three environmental organizations filed petitions for party status in the permit renewal proceeding. The petitioners are seeking to impose a permit requirement that the Roseton plant install a closed cycle cooling system in order to reduce the volume of water withdrawn from the Hudson River, thus reducing aquatic organism mortality. The petitioners claim that only a closed cycle cooling system meets the Clean Water Act’s requirement that the cooling water intake structures reflect the BTA for minimizing adverse environmental impacts. In September 2006, the administrative law judge issued a ruling admitting the petitioners to full party status and setting forth the issues to be adjudicated in the permit renewal hearing. Various holdings in the ruling have been appealed to the Commissioner of NYSDEC by DNE, NYSDEC staff, and the petitioners. We expect that the adjudicatory hearing on the Draft SPDES Permit will occur in 2007. We believe that the petitioners’ claims are without merit, and we plan to oppose those claims vigorously. Given the high cost of installing a closed cycle cooling system, an adverse result in this proceeding could have a material adverse effect on our financial condition, results of operations and cash flows.

Guarantees and Indemnifications

In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be remote.

WCP Indemnities. In connection with the sale of our 50% interest in West Coast Power to NRG on March 31, 2006, we, NRG and NRG West Coast Power LLC entered into an agreement to allocate responsibility for managing certain litigation and provide for certain indemnities with respect to such litigation. Subject to conditions and limitations specified in that agreement, the parties agreed that we would manage the Gas Index Pricing Litigation described above for which NRG could suffer a loss subsequent to the closing and that we would indemnify NRG for all costs or losses resulting from such litigation, as well as from other proceedings based on similar acts or omissions which formed the basis of such litigation. Further, the parties agreed that we would manage the California Market Litigation described above for which NRG could suffer a loss subsequent to the closing, and that we and NRG would each be responsible for 50% of any costs or losses resulting from that power litigation, as well as from other proceedings based on similar acts or omissions which formed the basis of such litigation. The agreement also provides that NRG will manage other active litigation and indemnify us for any resulting losses, subject to certain conditions. Maximum recourse under these matters is not limited by the agreement or by the passage of time with the exception of the California Department of Water Resources matter in which NRG has a specified indemnity obligation. The damages claimed by the various plaintiffs in these matters are unspecified as of March 31, 2007.

Targa Indemnities. During 2005, as part of our sale of DMSLP, we agreed to indemnify Targa against losses it may incur under indemnifications DMSLP provided to purchasers of Hackberry and certain other assets, properties and businesses disposed of by DMSLP prior to our sale of DMSLP. We have incurred no significant expense under these prior indemnities and deem their value to be insignificant. We have recorded an accrual in association with the cleanup of groundwater contamination at the Breckenridge Gas Processing Plant. The indemnification provided by DMSLP to the purchaser of the plant has a limit of $5 million. We have also indemnified Targa for certain tax matters arising from periods prior to our sale of DMSLP. We have recorded a reserve associated with this indemnification.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

Illinois Power Indemnities. As a condition of our 2004 sale of Illinois Power and our interest in Joppa, we provided indemnifications to third parties regarding environmental, tax, employee and other representations. These indemnifications are limited to a maximum recourse of $400 million. Additionally, we have indemnified third parties against losses resulting from possible adverse regulatory actions taken by the ICC that could prevent Illinois Power from recovering costs incurred in connection with purchased natural gas and investments in specified items. Although there is no limitation on our liability under this indemnity, our indemnity is limited to 50% of any such losses. On July 27, 2005, we made a payment of $8 million to Ameren in settlement of Ameren’s indemnification claims with respect to an ICC Order disallowing items relating to one of Illinois Power’s natural gas storage fields resulting in a negative revenue requirement impact to Ameren. In anticipation of similar cases, we recognized a pre-tax charge of $12 million in 2005, which is included in general and administrative expense on our consolidated statements of operations. As anticipated, we paid Ameren for an additional amount disallowed in a similar ICC Order in the third quarter of 2006. We have adjusted the amount reserved for the various ongoing cases in light of these and other developments in the cases. Further disallowances and other events which fall within the scope of the indemnity may still occur; however, we are not required to accrue a liability in connection with these indemnifications, as management cannot reasonably estimate a range of outcomes or at this time considers the probability of an adverse outcome as only reasonably possible. We intend to contest any proposed disallowances.

Northern Natural and Other Indemnities. During 2003, as part of our sale of Northern Natural, the Rough and Hornsea natural gas storage facilities and certain natural gas liquids assets, we provided indemnities to third parties regarding environmental, tax, employee and other representations. Maximum recourse under these indemnities is limited to $209 million, $857 million and $28 million for the Northern Natural, Rough and Hornsea natural gas storage facilities and natural gas liquids assets, respectively. We also entered into similar indemnifications regarding environmental, tax, employee and other representations when completing other asset sales such as, but not limited to, Hackberry LNG Project, SouthStar Energy Services, various Canadian assets, Michigan Power, Oyster Creek, Hartwell, Commonwealth, Sherman, and Indian Basin. We have recorded reserves for existing environmental, tax and employee liabilities and have incurred no other expense relating to these indemnities.

Through one of our subsidiaries, we hold a 50% ownership interest in Black Mountain (Nevada Cogeneration) (“Black Mountain”), in which our partner is a Chevron subsidiary. Black Mountain owns the Black Mountain power generation facility and has a power purchase agreement with a third party that extends through April 2023. In connection with the power purchase agreement, pursuant to which Black Mountain receives payments which decrease in amount over time, we agreed to guarantee 50% of certain payments that may be due to the power purchaser under a mechanism designed to protect it from early termination of the agreement. At March 31, 2007, if an event of default due to early termination had occurred under the terms of the mortgage on the facility entered into in connection with the power purchase agreement, we could have been required to pay the power purchaser approximately $61 million under the guarantee. While there is a question of interpretation regarding the existence of an obligation to make payments calculated under this mechanism upon the scheduled termination of the agreement, management does not expect that any such payments would be required.

Note 10—Regulatory Issues

We are subject to regulation by various federal, state and local 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.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

The matters discussed below are material developments since the filing of our Form 10-K. Please see Note 18—Regulatory Issues beginning on page F-53 of our Form 10-K for further discussion.

Illinois Resource Procurement Auction. In January 2006, the ICC approved a reverse power procurement auction as the process by which utilities will procure power beginning in 2007. The auction occurred in September 2006, and we subsequently entered into two supplier forward contracts with subsidiaries of Ameren Corporation to provide capacity, energy and related services. There continue to be challenges to the auction process, including an action filed by the IAG at FERC. The ICC has intervened in the proceeding before FERC and has stated in its pleading that it has not found any evidence of collusive behavior or other anticompetitive actions with bidders in the Illinois Auction.

Further, there is a possibility of political, legislative, judicial and/or regulatory actions over the next several months that could substantially alter the parties’ rights and obligations under or relating to the SFCs. Numerous parties have appealed various aspects of the ICC Orders approving the auctions to the state intermediate appellate courts. The appellate court cases have been consolidated and are in the briefing stage; we anticipate a ruling this year, with the possibility of further review by the Illinois Supreme Court. There is also the possibility that the Illinois General Assembly will consider legislation regarding retail rates and the use of an auction by electric utilities for procuring power and energy. Please see Note 9—Commitments and Contingencies—Illinois Auction Complaints for further discussion.

Separately, the ICC has opened a docket to consider changes to the auction and auction process prior to the next auction being held. We have intervened in that docket. Testimony has been filed and following briefing and other steps in the ICC process, we anticipate a final Order in later this year.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

Note 11—Employee Compensation, Savings and Pension Plans

We have various defined benefit pension plans and post-retirement benefit plans in which our past and present employees participate, which are more fully described in Note 20—Employee Compensation, Savings and Pension Plans beginning on page F-61 of our Form 10-K.

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


	Pension Benefits						Other Benefits
	Quarter Ended March 31,
	2007			2006			2007		2006
	(in millions)
Service cost benefits earned during period	$	2		$	2		$	1	$	1
Interest cost on projected benefit obligation		3			2			1		1
Expected return on plan assets		(3	)		(2	)		—		—
Recognized net actuarial loss		1			1			—		—

Net periodic benefit cost	$	3		$	3		$	2	$	2
Additional cost due to curtailment		—			2			—		—

Total net periodic benefit cost	$	3		$	5		$	2	$	2

Exchange Transaction with Chairman and CEO. On March 17, 2006, we entered into an exchange transaction with our Chairman and CEO. Under the terms of the transaction, the purpose of which was to address uncertainties created by proposed regulations issued in late 2005 pursuant to Section 409A of the Internal Revenue Code (the “Code”), we cancelled all of the 2,378,605 stock options then held by our Chairman and CEO. As consideration for canceling these stock options, we granted our Chairman and CEO 967,707 stock options at an exercise price of $4.88, which equaled the closing price of our Class A common stock on the date of grant, and made a cash payment to him of approximately $6 million on January 15, 2007 based on the in-the-money value of the vested stock options that were cancelled.

Contributions. No contributions were made to our pension plans or to our postretirement benefits plans during the three months ended March 31, 2007. During the three months ended March 31, 2006, we made less than $1 million in contributions.

Note 12—Income Taxes

Effective Tax Rate. The income taxes included in continuing operations were as follows:


	Three Months Ended March 31,
	2007			2006
	(in millions, except rates)
Income tax expense	$	(5	)	$	(3	)
Effective tax rate		26	%		100	%

We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or loss, except for significant unusual or extraordinary transactions. Income taxes for significant unusual or extraordinary transactions are computed and recorded in the period that the specific transaction occurs. For the three months ended March 31, 2007, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to state income taxes and adjustments to our reserve for uncertain tax positions. For the three months ended March 31, 2006, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to a reduction of AMT credits due to the settlement of prior year tax audits and state income taxes.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

We recorded a $7 million decrease to our accumulated deficit as of January 1, 2007 to reflect the cumulative effect of adopting FIN No. 48. Please see Note 1—Accounting Policies—Accounting Principles Adopted—FIN No. 48 for further discussion.

Note 13—Segment Information

We report the results of our power generation business as three separate geographical segments in our consolidated financial statements: (i) the Midwest segment (“GEN-MW”); (ii) the Northeast segment (“GEN-NE”); and (iii) the South segment (“GEN-SO”). We also continue to separately report the results of our CRM business because of the diversity of its operations. Results associated with our former NGL segment are included in discontinued operations in Other and Eliminations due to the sale of this business. Our consolidated financial results also reflects corporate-level expenses such as general and administrative interest.

Pursuant to EITF Issue 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 02-3”), all gains and losses on third party energy trading contracts in the CRM segment, whether realized or unrealized, are presented net in the consolidated statements of operations. For the purpose of the segment data presented below, intersegment transactions between CRM and our other segments are presented net in CRM intersegment revenues but are presented gross in the intersegment revenues of our other segments, as the activities of our other segments are not subject to the net presentation requirements contained in EITF Issue No. 02-3. If transactions between CRM and our other segments result in a net intersegment purchase by CRM, the net intersegment purchases and sales are presented as negative revenues in CRM intersegment revenues. In addition, intersegment hedging activities are presented net pursuant to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133).

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the three months ended March 31, 2007 and 2006 is presented below:

Segment Data for the Quarter Ended March 31, 2007

(in millions)


	Power Generation									CRM			Other and Eliminations			Total
	GEN-MW			GEN-NE			GEN-SO			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	272		$	200		$	68		$	9		$	—		$	549
Other		—			24			—			—			—			24

		272			224			68			9			—			573
Intersegment revenues		—			—			—			—			—			—

Total revenues	$	272		$	224		$	68		$	9		$	—		$	573

Depreciation and amortization	$	(42	)	$	(6	)	$	(5	)	$	—		$	(3	)	$	(56	)
Operating income (loss)	$	100		$	42		$	(5	)	$	(2	)	$	(57	)	$	78
Other items, net		—			—			—			—			8			8
Interest expense																	(67	)

Income from continuing operations before income taxes																	19
Income tax expense																	(5	)

Income from continuing operations																	14
Income from discontinued operations, net of taxes																	—

Net income																$	14

Identifiable assets:
Domestic	$	4,577		$	1,329		$	593		$	325		$	264		$	7,088
Other		—			14			7			98			—			119

Total	$	4,577		$	1,343		$	600		$	423		$	264		$	7,207

Capital expenditures	$	(23	)	$	(3	)	$	(5	)	$	—		$	(3	)	$	(34	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

Segment Data for the Quarter Ended March 31, 2006

(in millions)


	Power Generation									CRM		Other and Eliminations			Total
	GEN-MW			GEN-NE			GEN-SO			CRM		Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	256		$	133		$	111		$	40	$	—		$	540
Other		—			60			—			—		—			60

		256			193			111			40		—			600
Intersegment revenues		—			(1	)		—			1		—			—

Total revenues	$	256		$	192		$	111		$	41	$	—		$	600

Depreciation and amortization	$	(40	)	$	(6	)	$	(5	)	$	—	$	(8	)	$	(59	)
Operating income (loss)	$	98		$	26		$	(12	)	$	14	$	(47	)	$	79
Earnings from unconsolidated investments		—			—			2			—		—			2
Other items, net		—			2			—			1		17			20
Interest expense																(98	)

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

Income from continuing operations																—
Income from discontinued operations, net of taxes																—
Cumulative effect of change in accounting principle, net of taxes																1

Net income															$	1

Identifiable assets:
Domestic	$	4,587		$	1,412		$	830		$	608	$	1,315		$	8,752
Other		—			15			5			98		—			118

Total	$	4,587		$	1,427		$	835		$	706	$	1,315		$	8,870

Unconsolidated investments	$	—		$	—		$	6		$	—	$	—		$	6
Capital expenditures	$	(11	)	$	(3	)	$	(3	)	$	—	$	(1	)	$	(18	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS–(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2007 and 2006

Note 14—Subsequent Events

On April 2, 2007, we completed the Merger Agreement and the transactions contemplated by the Merger Agreement, including the Merger and the establishment of the development joint venture with LS Associates represented by DLS Power Holdings and DLS Power Development. Please see Note 2—LS Power Business Combination for further discussion.

Also, on April 2, 2007, we entered into the Fifth Amended and Restated Credit Facility. The Fifth Amended and Restated Credit Facility amended DHI’s former credit facility by increasing the amount of the existing $470 million Revolving Facility to $850 million, increasing the amount of the existing $200 million Term L/C Facility to $400 million and adding a $70 million senior secured Term Loan B. Please see Note 7—Debt—Fifth Amended and Restated Credit Facility for further discussion.

In May 2007, we received an adverse arbitration decision relating to a legacy litigation matter. We recognized a legal and settlement charge of approximately $17 million relating to this adverse ruling. Please see Note 9—Commitments and Contingencies—Illinova Arbitration for further discussion.

DYNEGY INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended March 31, 2007 and 2006

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

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

GENERAL

We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry. Our power generation fleet is diversified by dispatch type, fuel source and geographic location. We report the results of our power generation business as three separate segments in our consolidated financial statements: (i) the Midwest segment (“GEN-MW”); (ii) the Northeast segment (“GEN-NE”); and (iii) the South segment (“GEN-SO”). We also separately report the results of our CRM business, which primarily consists of our remaining power tolling arrangement (excluding the Sithe toll which is in GEN-NE and is an intercompany agreement) as well as our physical gas supply contracts, gas transportation contracts and remaining gas, power and emission trading positions. Our consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization. In connection with the Merger Agreement discussed in Note 2—LS Power Business Combination, we will create a new operating segment, GEN-WE, comprised of our newly acquired portfolio of assets located in California and Arizona. In addition, effective April 2, 2007, in conjunction with the completion of the Merger Agreement, our existing GEN-SO segment was combined into the GEN-WE segment.

In addition to our operating generation facilities, we own an approximate 40% undivided interest in Plum Point, a new 665 MW coal-fired plant under construction in Arkansas. Through our interest in DLS Power Holdings, we also own a 50% interest in a portfolio of greenfield development projects totaling more than 7,600 MW of generating capacity and repowering and/or expansion opportunities representing approximately 2,500 MW of generating capacity.

Recent Developments

LS Power. On September 14, 2006, we entered into the Merger Agreement with the LS Contributing Entities, Merger Sub and Dynegy Illinois to, among other transactions, combine the LS Contributing Entities’ operating generation portfolio with our generation assets, acquire a 50 percent ownership interest in a development joint venture with LS Associates and merge Merger Sub with and into Dynegy Illinois pursuant to the Merger. On March 29, 2007, at a special meeting of the shareholders of Dynegy Illinois, the shareholders of Dynegy Illinois adopted the Merger Agreement and approved the Merger.

Pursuant to the transactions with the LS Contributing Entities contemplated by the Merger Agreement, which were completed on April 2, 2007, the LS Contributing Entities received 340 million shares of our Class B common stock (which are convertible, under the circumstances described in our amended and restated certificate of incorporation, into shares of our Class A common stock), $100 million in cash and a promissory note in the aggregate principal amount of $275 million (which was simultaneously issued and repaid in full without interest or prepayment penalty) in exchange for their contribution of their entire operating generation portfolio and the 50 percent interest in each of DLS Power Holdings and DLS Power Development (together comprising the development joint venture with LS Associates). Dynegy also, via its indirect wholly owned subsidiary Griffith Holdings, LLC, simultaneously issued to the LS Contributing Entities, and repaid in full without interest or prepayment penalty and cancelled, an additional $70 million of project-related debt (the “Griffith Debt”) in

connection with the completion of the Merger Agreement transactions. We also assumed approximately $1.8 billion in net debt (debt less restricted cash and investments) from the LS Contributing Entities, and utilized $100 million of cash on hand and borrowings by DHI (and subsequent permitted distributions to Dynegy) of (i) an aggregate $275 million under the Revolving Facility and (ii) an aggregate $70 million under the new Term Loan B in connection with the completion of the Merger Agreement.

Pursuant to the Merger, which was also completed on April 2, 2007, Merger Sub, our then-wholly owned subsidiary, merged with and into Dynegy Illinois. As a result of the Merger, Dynegy Illinois became our wholly owned subsidiary, the then-shareholders of Dynegy Illinois became our stockholders and each Dynegy Illinois shareholder, including Chevron U.S.A. Inc. (Dynegy Illinois’ then-largest shareholder) (“Chevron”), received one share of our Class A common stock for each share of Class A common stock or Class B common stock of Dynegy Illinois held by it.

As part of the transactions contemplated by the Merger Agreement, LS Associates transferred its interests in certain power generation development projects to DLS Power Holdings, and contributed 50% of the membership interests in DLS Power Holdings to Dynegy. In addition, immediately after the completion of the Merger, LS Associates and Dynegy each contributed $5 million to DLS Power Holdings as their initial capital contributions, and also contributed their respective interests in certain additional power generation development projects to DLS Power Holdings. LS Associates and Dynegy each now own 50% of the membership interests in DLS Power Development.

In addition, in connection with the completion of the Merger and the other transactions contemplated by the Merger Agreement, our name was changed from Dynegy Acquisition, Inc. to Dynegy Inc. Please see Note 2—LS Power Business Combination for further discussion.

Fifth Amended and Restated Credit Facility. On April 2, 2007, we entered into the Fifth Amended and Restated Credit Facility which amends DHI’s former credit facility (the Fourth Amended and Restated Credit Facility, which was last amended on July 11, 2006) by increasing the amount of the existing $470 million revolving credit facility (the “Revolving Facility”) to $850 million, increasing the amount of the existing $200 million term letter of credit facility (the “Term L/C Facility”) to $400 million and adding a $70 million senior secured term loan facility (“Term Loan B”). Please see Note 7—Debt—Fifth Amended and Restated Credit Facility for further discussion.

Calcasieu Sale. On January 31, 2007, we entered into an agreement to sell our interest in the Calcasieu power generation facility to Entergy for approximately $57 million, subject to regulatory approval. The transaction is expected to close in early 2008. Please read Note 3—Discontinued Operations—Calcasieu for further discussion.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In this section, we describe our liquidity and capital requirements and our internal and external liquidity and capital resources. Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, collateral requirements, contractual obligations, capital expenditures, regulatory and legal settlements and working capital needs. Examples of working capital needs include prepayments or cash collateral associated with purchases of commodities, particularly natural gas and coal, facility maintenance costs (including required environmental expenditures) and other costs such as payroll. Our liquidity and capital resources are primarily derived from cash flows from operations, cash on hand, borrowings under our financing agreements, asset sale proceeds and proceeds from capital market transactions to the extent we engage in these activities.

Debt Obligations

On April 2, 2007, in connection with the completion of the transactions contemplated by the Merger Agreement, an aggregate $275 million under the Revolving Facility, an aggregate $400 million under the Term L/C Facility (with the proceeds placed in a collateral account to support the issuance of letters of credit) and an aggregate $70 million under Term Loan B (representing all available borrowings under Term Loan B) were drawn. Please read Note 7—Debt—Fifth Amended and Restated Credit Facility for further discussion. We assumed approximately $1.8 billion of net debt on April 2, 2007 upon completion of the Merger. Please see Note 2—LS Power Business Combination for further discussion.

Collateral Postings

We continue to use a significant portion of our capital resources, in the form of cash and letters of credit, to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade credit ratings and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. The following table summarizes our consolidated collateral postings to third parties by segment at May 3, 2007, March 31, 2007 and December 31, 2006:


	May 3, 2007		March 31, 2007		December 31, 2006
	(in millions)
By Segment:
Generation	$	1,012	$	158	$	134
Customer risk management business		32		45		54
Other		8		8		7

Total	$	1,052	$	211	$	195

By Type:
Cash (1)	$	54	$	41	$	38
Letters of Credit		998		170		157

Total	$	1,052	$	211	$	195

(1)	Cash collateral consists of either cash deposits to cover physical deliveries or liabilities on mark-to-market positions or prepayments for commodities or services that are in advance of normal payment terms.

The increase in collateral postings from December 31, 2006 to March 31, 2007 is primarily due to increased pricing and additional positions of approximately $33 million partially offset by $17 million of collateral returns. The significant increase in collateral postings from March 31, 2007 to May 3, 2007 is primarily due to the completion of the Merger Agreement and incorporation of the letters of credit posted for the collateral requirements of the assets and associated hedges acquired from the LS Contributing Entities.

Going forward, we expect counterparties’ collateral demands to continue to reflect changes in commodity prices, including seasonal changes in weather-related demand, as well as their views of our creditworthiness. Considering our credit ratings, current commodity price estimates, specifically as prices relate to fuel purchases and power hedging activities, and the recently completed Merger Agreement, we estimate that collateral requirements will be approximately $1.0 billion at year-end 2007. We believe that we have sufficient capital resources to satisfy counterparties’ collateral demands, including those for which no collateral is currently posted, for the foreseeable future.

Tax Attributes

For accounting purposes, at January 1, 2007, our NOL deferred tax asset attributable to our previously incurred federal NOL carry-forwards was valued at approximately $695 million. These NOL carry-forwards will begin to expire in the year 2022. As a result of the application of the provisions of Section 382 of the Code, if substantial changes in our ownership should occur there could be annual limitations on our ability to use the NOL carry-forwards to offset our future taxable income. The LS Power combination constituted a substantial change in ownership, although the transaction itself did not result in a limitation on the future use of the NOL carry-forwards.

The magnitude of any such limitation and its effect on us is difficult to assess and depends in part on the market value of our stock at the time of any such ownership change and then-prevailing interest rates. However, we do not expect that any ownership change during the next few months and the resulting annual limitation would have a material impact on our tax liability, due to the application of the built-in gain provisions of Section 382. The ultimate realization of our NOL carry-forwards will be affected, in part, by the tax law in effect at the time.

Disclosure of Contractual Obligations and Contingent Financial Commitments

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

There have been no material changes to our contractual obligations and contingent financial commitments since December 31, 2006 through March 31, 2007.

On April 2, 2007, we assumed certain contractual obligations in conjunction with the completion of the Merger Agreement. Further, upon completion of the Merger Agreement, our obligations under our power tolling arrangement related to the Kendall facility became intercompany obligations. Please see Note 2—LS Power Business Combination for further discussion.

Dividends on Common Stock

Dividend payments on our common stock are at the discretion of our Board of Directors. We did not declare or pay a dividend on our common stock for the first quarter 2007 and do not foresee a declaration of dividends in the near term.

Internal Liquidity Sources

Our primary internal liquidity sources are cash flows from operations, cash on hand and available capacity under our Fifth Amended and Restated Credit Facility, which is scheduled to mature in April 2012.

Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at May 3, 2007, March 31, 2007 and December 31, 2006:


	May 3, 2007(1)			March 31, 2007			December 31, 2006
	(in millions)
Total revolver capacity	$	950		$	470		$	470
Borrowings against revolver capacity		(275	)		—			—
Total additional letter of credit capacity		1,125			194			194
Outstanding letters of credit under revolving credit facility		(998	)		(170	)		(157	)

Unused credit facility capacity		802			494			507
Cash		271	(2)(3)		369	(2)		371	(2)

Total available liquidity	$	1,073		$	863		$	878

(1)

In April 2007, we amended and restated the credit facility. Please see Note 7—Debt—Fifth Amended and Restated Credit Facility for further discussion. In April 2007, we completed the Merger Agreement and acquired revolver capacity of $100 million and additional letter of credit capacity of $737 million.

(2)	The May 3, 2007, March 31, 2007 and December 31, 2006 amounts include approximately $41 million, $40 million and $46 million, respectively, of cash that remains in Europe and $11 million, $10 million and $10 million, respectively, of cash that remains in Canada.

(3)	The decrease in cash balance since March 31, 2007 was primarily due to cash paid in connection with the Merger Agreement and interest payments of approximately $68 million.

Cash Flows from Operations. We had operating cash inflows of $44 million for the three months ended March 31, 2007. This consisted of $140 million in operating cash flows from our power generation business, offset by $6 million of cash outflows relating to our customer risk management business and $90 million of cash outflows relating to corporate-level expenses. Please read “—Results of Operations—Operating Income” and “—Results of Operations —Cash Flow Disclosures” for further discussion of factors impacting our operating cash flows for the periods presented.

Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of natural gas and its correlation to power prices, the cost of coal and fuel oil and the value of ancillary services. Additionally, the availability of our plants during peak demand periods will be required to allow us to capture attractive market prices when available. Over the longer term, our operating cash flows also will be impacted by, among other things, our ability to tightly manage our operating costs, including maintenance costs. Our ability to achieve targeted cost savings in the face of industry-wide increases in labor and benefits costs, together with changes in commodity prices, will impact our future operating cash flows. Please read “—Results of Operations—2007 Outlook” for further discussion.

Cash on Hand. At May 3, 2007 and March 31, 2007, we had cash on hand of $271 million and $369 million, respectively, as compared to $371 million at the end of 2006. The decrease in cash balance on May 3, 2007 from March 31, 2007 was primarily due to cash paid in connection with the Merger Agreement and interest payments on our debt of approximately $68 million.

Revolver Capacity. On April 2, 2007, we entered into the Fifth Amended and Restated Credit Facility which replaced our former Fourth Amended and Restated Credit Facility. Please read Note 12—Debt beginning on page F-36 of our Form 10-K for further discussion of our former Fourth Amended and Restated Credit Facility. This Fifth Amended and Restated Credit Facility is our primary credit facility. Please read Note 7—Debt—Fifth Amended and Restated Credit Facility for further discussion.

External Liquidity Sources

Our primary external liquidity sources are proceeds from asset sales and other types of capital-raising transactions, including potential debt and equity issuances.

Asset Sale Proceeds. On January 31, 2007, we entered into an agreement to sell our interest in the Calcasieu power generation facility to Entergy for approximately $57 million, subject to regulatory approval. The transaction is expected to close in early 2008. Please read Note 3—Discontinued Operations—Calcasieu for further discussion.

Consistent with industry practice, we regularly evaluate our generation fleet based primarily on geographic location, fuel supply, market structure and market recovery expectations, and consider divestitures of non-core generation assets where the balance of these factors suggests that such assets’ earnings potential is limited or that the value that can be captured through a divestiture outweighs the benefits of continuing to own and operate such assets. In connection with this review, we are considering options to potentially sell our 614 MW Cogen Lyondell generation facility, our 576 MW Bluegrass generation facility and our 539 MW Heard County generation facility. Although no sale of one or all of these facilities can be guaranteed, market interest in assets of this type has been significant. Moreover, dispositions of one or more other generation facilities could occur in 2007 or beyond. Were any such sale or disposition to be consummated, the disposition could result in accounting charges related to the affected asset(s), and our earnings and cash flows could be affected in 2007 and beyond.

Capital-Raising Transactions. As part of our ongoing efforts to maintain a capital structure that is closely aligned with the cash-generating potential of our asset-based business, which is subject to cyclical changes in commodity prices, we will continuously explore additional sources of external liquidity both in the near- and long-term. The timing of any transaction may be impacted by events, such as strategic growth opportunities, legal judgments or regulatory requirements, which could require us to pursue additional capital in the near-term.

In particular, in connection with the recently completed acquisition of assets from LS Power, we are evaluating various opportunities to streamline our capital structure. These opportunities may include capital markets transactions. The receptiveness of the capital markets to an offering of debt or equity securities cannot be assured and may be negatively impacted by, among other things, our non-investment grade credit ratings, significant debt maturities, long-term business prospects and other factors beyond our control. Any issuance of equity likely would have other effects as well, including shareholder dilution. Our ability to issue equity securities is limited by restrictions contained in certain registration rights agreements. Further, our ability to issue debt securities is limited by our financing agreements, including our Fifth Amended and Restated Credit Facility. Please read Note 7—Debt for further discussion.

In addition, we continually review opportunities to grow our company and to participate in what we believe will be continuing consolidation of the power generation industry. No definitive transaction has been agreed to and none can be guaranteed to occur; however, we have successfully executed on similar opportunities in the past and could do so again in the future. Depending on the terms and structure of any such transaction, we could issue significant debt and/or equity securities for capital-raising purposes. We also could be required to assume substantial debt securities and the underlying payment obligations.

Please read “Uncertainty of Forward-Looking Statements and Information” for additional factors that could impact our future operating results and financial condition.

RESULTS OF OPERATIONS

Overview. In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the three-month periods ended March 31, 2007 and 2006. At the end of this section, we have included our 2007 outlook for each segment.

We report the results of our power generation business as three separate segments in our unaudited condensed consolidated financial statements: (i) the Midwest segment (“GEN-MW”); (ii) the Northeast segment (“GEN-NE”); and (iii) the South segment (“GEN-SO”). We also separately report results of our CRM business, which primarily consists of our remaining power tolling arrangement as well as the physical gas supply contracts, gas transportation contracts and gas, power and emission trading positions that remain from the third-party trading business that was substantially exited in 2002. The Sithe toll is reported in GEN-NE and is an intercompany agreement. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.

Summary Financial Information. The following tables provide summary financial data regarding our consolidated and segmented results of operations for the three-month periods ended March 31, 2007 and 2006, respectively:

Quarter Ended March 31, 2007


	Power Generation									CRM			Other and Eliminations			Total
	GEN-MW			GEN - NE			GEN-SO			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	272		$	224		$	68		$	9		$	—		$	573
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(130	)		(176	)		(68	)		(11	)		(1	)		(386	)
Depreciation and amortization expense		(42	)		(6	)		(5	)		—			(3	)		(56	)
General and administrative expense		—			—			—			—			(53	)		(53	)

Operating income (loss)	$	100		$	42		$	(5	)	$	(2	)	$	(57	)	$	78
Other items, net		—			—			—			—			8			8
Interest expense																	(67	)

Income from continuing operations before income taxes																	19
Income tax expense																	(5	)

Income from continuing operations																	14
Income from discontinued operations, net of taxes																	—
Net income																$	14

Quarter Ended March 31, 2006


	Power Generation									CRM			Other and Eliminations			Total
	GEN-MW			GEN –NE			GEN-SO			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	256		$	192		$	111		$	41		$	—		$	600
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(118	)		(160	)		(118	)		(12	)		(1	)		(409	)
Depreciation and amortization expense		(40	)		(6	)		(5	)		—			(8	)		(59	)
General and administrative expense		—			—			—			(15	)		(36	)		(51	)
Impairment and other charges		—			—			—			—			(2	)		(2	)

Operating income (loss)	$	98		$	26		$	(12	)	$	14		$	(47	)	$	79
Earnings from unconsolidated investments		—			—			2			—			—			2
Other items, net		—			2			—			1			17			20
Interest expense																	(98	)

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

Income from continuing operations																	—
Income from discontinued operations, net of taxes																	—
Cumulative effect of change in accounting principle, net of taxes																	1

Net income																$	1

The following table provides summary segmented operating statistics for the three months ended March 31, 2007 and 2006, respectively:


	Quarter Ended March 31,
	2007		2006
GEN-MW
Million Megawatt Hours Generated (1)		5.7		5.4
Average Actual On-Peak Market Power Prices ($/MWh):
Cinergy (Cin Hub)	$	56	$	49
Commonwealth Edison (NI Hub)	$	54	$	50

GEN-NE
Million Megawatt Hours Generated		2.0		1.0
Average Actual On-Peak Market Power Prices ($/MWh):
New York— Zone G	$	85	$	76
New York— Zone A	$	63	$	60

GEN-SO
Million Megawatt Hours Generated (1)		0.8		1.1
Average Actual On-Peak Market Power Prices ($/MWh):
Southern	$	54	$	55
ERCOT	$	57	$	56
Average natural gas price—Henry Hub ($/MMBtu) (2)	$	7.16	$	7.75

(1)

Includes our ownership percentage in the MWh generated by our GEN-SO investment in Black Mountain for the three months ended March 31, 2007 and includes the MWh generated by our GEN-SO investments in West Coast Power and Black Mountain and our GEN-MW investment in Rocky Road for the three months ended March 31, 2006.

(2)	Calculated as the average of the daily gas prices for the period.

The following table summarizes significant items on a pre-tax basis, affecting net loss for the periods presented.


	Quarter Ended March 31, 2007
	Power Generation
	GEN-MW		GEN-NE		GEN-SO		CRM			Other & Eliminations			Total
	(in millions)
Legal and settlement charges	$	—	$	—	$	—	$	—		$	(17	)	$	(17	)

Total	$	—	$	—	$	—	$	—		$	(17	)	$	(17	)


	Quarter Ended March 31, 2006
	Power Generation
	GEN-MW		GEN-NE		GEN-SO		CRM			Other & Eliminations			Total
	(in millions)
Legal and settlement charges	$	—	$	—	$	—	$	(15	)	$	—		$	(15	)

Total	$	—	$	—	$	—	$	(15	)	$	—		$	(15	)

Operating Income

Operating income was $95 million for the three months ended March 31, 2007, compared to $79 million for the three months ended March 31, 2006.

Power Generation—Midwest Segment. Operating income for GEN-MW was $100 million for the three months ended March 31, 2007, compared to $98 million for the three months ended March 31, 2006.

Results for the three months ended March 31, 2007 improved by $23 million as a result of higher volumes, increased market prices, and improved pricing as a result of the Illinois reverse power procurement auction compared with the three months ended March 31, 2006. However, this improvement was largely offset by $14 million additional net mark-to market losses, a $5 million increase in operating expense, and $2 million of additional depreciation expense.

Generated volumes increased by 6%, up from 5.4 million MWh for the first quarter 2006 to 5.7 million MWh for the same period in 2007. Average actual on-peak prices in the NI Hub/ComEd pricing region increased from $50 per MWh in first quarter 2006 to $54 per MWh for the first quarter 2007.

Beginning January 1, 2007, we began operating under two new energy product supply agreements with subsidiaries of Ameren Corporation through our participation in the Illinois reverse power procurement auction in 2006. Under these new agreements, we provide up to 1,400 MWh around the clock for prices of approximately $65 per MWh.

GEN-MW’s results for the first three months of 2007 include mark-to-market losses of $11 million related to forward sales, compared to $3 million of mark-to-market gains for the first three months of 2006. At March 31, 2007, market prices have risen from our original strike prices. Included in the mark-to-market losses of $11 million is a $3 million charge related to hedge ineffectiveness, as price movements at our facilities’ delivery points were not sufficiently correlated with price movements at the Cinergy hub.

Operating expense increased $5 million for the three months ended March 31, 2007 compared with the same period 2006, largely as a result of the timing of maintenance projects and our 2006 acquisition of NRG’s 50% ownership interest in Rocky Road Power LLC.

Depreciation expense increased from $40 million in 2006 to $42 million in 2007 as a result of capital projects placed into service in 2006. This was primarily due to major maintenance projects completed at our Baldwin and Havana facilities in 2006.

Power Generation—Northeast Segment. Operating income for GEN-NE increased significantly to $42 million for the three months ended March 31, 2007, compared to $26 million for the three months ended March 31, 2006.

On peak market prices in New York Zone G and Zone A increased by 12% and 5%, respectively. Spark spreads widened due to higher power prices coupled with lower fuel costs. In addition, cooler weather led to greater run times than the prior year.

Results for our Roseton and Danskammer facilities increased by $13 million to $32 million for the first quarter 2007 compared to $19 million for the first quarter 2006, or 68% period over period, as a result of higher generation volumes due to colder weather, higher on-peak power prices and lower average fuel costs. Generated volumes increased approximately 97% to 1.4 million MWh for the first quarter 2007 compared to 0.7 million MWh for the first quarter 2006. Average on-peak prices for Zone G, the market served by these two facilities, increased 12% from $76 per MWh in 2006 to $85 per MWh in 2007. In the three months ended March 31, 2006, Roseton and Danskammer results were favorably impacted by $10 million by an opportunistic sale of emissions credits that were not required for near-term operations of our facilities. This sale was not repeated in the three months ended March 31, 2007 as the facilities experienced greater run-time.

Independence contributed results of $16 million for the first quarter 2007, compared with $12 million for the first quarter 2006. Generated volumes increased 133% to 0.7 million MWh for the first quarter 2007 compared to 0.3 million MWh for the first quarter of 2006, primarily the result of colder weather period over period.

A net mark-to-market loss of $2 million is included in the results discussed above for the first quarter 2007, related to financial transactions not designated as cash flow hedges. First quarter 2006 results included no significant mark-to-market losses.

Depreciation expense for GEN-NE was $6 million for the three months ended March 31, 2007 and 2006.

Power Generation—South Segment. Operating loss for GEN-SO was $5 million for the three months ended March 31, 2007, compared to a loss of $12 million for the three months ended March 31, 2006.

Results from our ERCOT facility increased by $9 million, from a loss of $10 million for the three months ended March 31, 2006 to a loss of $1 million for the three months ended March 31, 2007. Results for the three-month period ended March 31, 2006 were significantly negatively impacted by higher natural gas prices on an electricity and steam contract at our CoGen Lyondell cogeneration facility. We entered into a new 15-year agreement with our customer, Lyondell, effective January 1, 2007. This new contract provides full cost recovery and a market-based margin. Additionally, on peak power prices increased from $56 in 2006 to $57 in 2007.

Our southeast peaker assets contributed $1 million to results for the three months ended March 31, 2006 and 2007. Southeast peaker results are primarily the result of capacity sales from our Heard County facility in 2007 and Rockingham and Heard County facilities in 2006.

Depreciation expense was $5 million for both the periods ended March 31, 2007 and 2006.

CRM. Operating loss for the CRM business was $2 million for the three months ended March 31, 2007, compared to operating income of $14 million for the three months ended March 31, 2006. CRM results for the three months ended March 31, 2007 were primarily from the roll off of legacy power, gas and emissions positions. Income for 2006 was driven primarily by mark-to-market gains on our legacy emissions positions, partially offset by a $15 million increase in legal reserves resulting from additional activities during the period that negatively affected management’s assessment of the probable and estimable losses associated with the applicable proceedings.

Other. Other operating loss was $57 million for the quarter ended March 31, 2007, compared to a loss of $47 million for the quarter ended March 31, 2006. The increased operating loss is primarily the result of a $17 million legal reserve offset partially by a decrease in depreciation expense for 2007. General and administrative expense increased to $53 million for the three months ended March 31, 2007 from $36 million for 2006 as a result of the legal charge.

Earnings from Unconsolidated Investments

For the three months ended March 31, 2007 and 2006, results of zero and $2 million primarily relate to the GEN-SO investment in Black Mountain.

Other Items, Net

Other items, net totaled $8 million of income for the three months ended March 31, 2007, compared to $20 million of income for the three months ended March 31, 2006. The decrease is primarily associated with lower interest income from lower cash balances in 2007.

Interest Expense

Interest expense totaled $67 million for the three months ended March 31, 2007, compared to $98 million for the three months ended March 31, 2006. The decrease is primarily attributable to lower principal amounts outstanding as a result of our 2006 liability management program.

Income Tax Expense

We reported an income tax expense from continuing operations of $5 million for the three months ended March 31, 2007, compared to an income tax expense from continuing operations of $3 million for the three months ended March 31, 2006. The 2007 effective tax rate was 26%, compared to 100% in 2006. Our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to state income taxes and adjustments to our reserve for uncertain tax positions in 2007 and due primarily to a reduction of AMT credits due to the settlement of prior year tax audits and state income taxes in 2006.

Discontinued Operations

Income From Discontinued Operations Before Taxes. Discontinued operations include our Calcasieu generating facility in our GEN-SO segment, DMSLP in our former NGL segment and our U.K. CRM business in the CRM segment. During the three months ended March 31, 2007, we recorded no significant income from discontinued operations. During the three months ended March 31, 2006, pre-tax income from discontinued operations of $1 million (zero after-tax) included $1 million in pre-tax income attributable to NGL.

Income Tax Expense From Discontinued Operations. We recorded an income tax expense from discontinued operations of less than $1 million during the three months ended March 31, 2007, compared to an income tax expense from discontinued operations of $1 million during the three months ended March 31, 2006. These amounts reflect effective rates of zero and 100%, respectively. FIN No. 18, “Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28” (“FIN No. 18”), prescribes a detailed methodology of allocating income taxes between continuing and discontinued operations. This methodology often results in an effective rate for discontinued operations significantly different from the statutory rate of 35%.

2007 Outlook

Our recently completed combination with LS Power represents the transition from our previous era of self-restructuring to a period of expanded, more diverse operations that provides greater scale and scope in our key markets and stronger positioning for future growth opportunities. As a result of the combination, our generation portfolio is diversified by dispatch type, fuel source and geographic location. Our operating fleet consists of 29 owned or leased power generation facilities, with approximately 19,500 MW of generating capacity, operating in 13 states (excluding the 351 MW Calcasieu facility). We are considering the potential sale of three of these facilities: our 614 MW CoGen Lyondell generation facility, our 576 MW Bluegrass generation facility and our 539 MW Heard County generation facility.

In addition to our operating generation facilities, we own an approximate 40% undivided interest in Plum Point, a new, 665 MW coal-fired plant under construction in Arkansas. Through our interest in DLS Power Holdings and DLS Power Development, we also own a 50% interest in a portfolio of greenfield development

projects totaling more than 7,600 MW of generating capacity and repowering and/or expansion opportunities, representing approximately 2,500 MW of generating capacity, thus providing us with meaningful organic growth prospects.

The majority of our generating facilities are located in areas served by Independent System Operators (“ISOs”) including the Midwest Independent System Operator (“MISO”), PJM Interconnection Association (“PJM”), the California Independent System Operator (“CAISO”), the Energy Reliability Council of Texas (“ERCOT”), the New York Independent System Operator (“NYISO”) and the New England Independent System Operator (“ISO-NE”). Certain of our facilities are in areas which are not served by ISOs or regional transmission organizations (“RTOs”). These include our Arizona facilities which are in the Rocky Mountain/Desert Southwest region of the Western Electricity Coordinating Council (“WECC”), and our Calcasieu, Heard and Bluegrass facilities that are located in the Entergy, Southern and TVA sub regions, respectively, of the Southeastern Electric Reliability Council (“SERC”).

Including volumes committed under the contracts resulting from the Illinois resource procurement auction and power and steam delivery commitments from our Independence and ERCOT facilities, a substantial portion of the output from our fleet of power generation facilities is contracted for the balance of 2007, or will be subject to “reliability-must-run” (“RMR”) arrangements. The remaining output from our facilities is available for other forward sales opportunities to capture attractive market prices when they are available. To the extent that we choose not to enter into forward sales, the gross margin from our assets is a function of price movements in the coal, natural gas, fuel oil and power commodity markets.

Generally, we expect that our future financial results will continue to reflect sensitivity to fuel and emissions commodity prices, market structure and prices for electric energy, ancillary services and capacity, transportation and transmission logistics, weather conditions and in-market asset availability (“IMA”). Our commercial team actively manages commodity price risk associated with our unsold power production by entering into forward sales typically for terms of six to twelve months. To the extent we do not choose to forward sell energy from our generation fleet, changes in commodity prices will affect our earnings based on the direction and significance of the commodity price movement.

Our results will also continue to be impacted by environmental regulations and their impact on our financial condition and results of operations. In addition to RGGI, various state and federal programs have been initiated or are being discussed. It is difficult to predict with certainty the precise outcome of these various initiatives and discussions or the resulting impact on our results of operations and financial condition. If some or all of the initiatives are adopted and implemented, Dynegy and similarly situated power generators could incur additional costs to develop, construct and operate power generation facilities, with the magnitude of any such cost increases to be influenced by, among other things:

•

the structure and scope of final rules and regulations;

•

the ability to recover any associated increases in operating and/or capital costs;

•

the demonstration of carbon sequestration and capture technologies and any associated costs; and

•

the risk of litigation and related adversary proceedings, particularly with respect to development projects and associated permitting activities.

The following summarizes our outlook for our power generation business by reportable segment.

GEN- MW. We expect our results to continue to be impacted by power prices, fuel prices, fuel availability and unit availability.

In 2007, GEN-MW results will be affected by the delivery obligations resulting from our participation in the Illinois resource procurement auction. The power commodity price under the auction-related agreements is higher than existed under our previous contract. The price Dynegy will receive under the auction contract in 2007 is approximately $65/MWh. Under the auction contract, Dynegy assumes increased costs and penalty risks associated with managing delivered power volumes. The price received by Dynegy under the previous contract averaged

approximately $42/MWh in 2006, and was a function of the amount of power called on by IP under the previous contract. We anticipate that the revenues generated by our Midwest facilities will continue to benefit in 2007 from the implementation of contracts resulting from the auction and the sale of additional volumes into the MISO wholesale markets at prevailing market prices.

Another factor impacting our results in the Midwest in 2007 will be the regulatory environment in Illinois. Within the Illinois political arena, there continue to be challenges to the auction process. There is a possibility of political, legislative, judicial and/or regulatory actions over the next several months that could alter the auction results substantially. Please read Note 10—Regulatory Issues—Illinois Resource Procurement Auction for further discussion.

In 2005, DMG entered into a comprehensive, Midwest system-wide settlement with the EPA and other parties, resolving the environmental litigation related to our Baldwin Energy Complex in Illinois. The settlement involves substantial emission reductions from our Illinois coal-fired power plants and the completion of several supplemental environmental projects in the Midwest. Through March 31, 2007, DMG had achieved all of the emission reductions scheduled to date and was developing plans to install additional emission control equipment to meet future, more stringent emission limits. DMG is in the process of constructing a mercury control project at the Vermilion Power Station that is scheduled for operation by June 30, 2007. Our estimated costs associated with the consent decree projects, which we expect to incur through 2012, are approximately $775 million. This reflects a $100 million increase over our previous estimate of $675 million largely driven by higher costs and increased quantities of materials.

Through 2010, 97% of our Midwest coal requirements are contracted. Additionally, 98% of our coal requirements for 2007 and 2008 are contracted at a fixed price. Our longer term results are sensitive to changes in coal prices to the extent that our current fixed price arrangements expire or are adjusted through contract re-openers or related provisions.

Our results will continue to be affected by IMA. We use IMA to monitor fleet performance over time. This measure quantifies the percentage of generation for each of our 14 major steam units that were available when market prices were favorable for participation. Through our focus on safe and efficient operations, we seek to maximize our IMA and, as a result, our revenue generating opportunities. The IMA for our coal-fired fleet for the three months ended March 31, 2007 was approximately 91%, compared to 86% for the comparable period of 2006. (In 2007, we modified the way we calculate IMA to better reflect the capabilities of the units due to seasonal variations. These changes had minimal effects on the year over year comparison in the first quarter, but could have more pronounced effects as the summer season approaches.) We attempt to schedule maintenance and repair work to minimize downtime during peak demand periods, but only to the extent doing so does not compromise a safe working environment for our employees and contractors.

In connection with the Merger discussed in Note 2—LS Power Business Combination, we acquired assets in Illinois and Pennsylvania. These assets include the 1,200 MW Kendall natural gas-fired facility in Minooka, IL and the 580 MW Ontelaunee natural gas-fired facility in Ontelaunee township, PA. With respect to the Kendall facility, 275 MW of the facility’s capacity is committed to a subsidiary of Constellation Energy (“Constellation”) under a power purchase agreement that extends through 2017. An additional 550 MW of capacity is committed under another agreement with Constellation, which extends through November 2008. These power purchase agreements provide us with predictable contracted revenues, and mitigate the effects of fluctuating market prices for electricity.

The Ontelaunee facility sells its energy, capacity and other ancillary services to wholesale electricity customers directly on the spot market. However, exposure to the market prices of energy has been hedged under a call-option agreement.

Our 576 MW Bluegrass generation facility is being considered for a potential sale. Please read “Asset Sale Proceeds” for further discussion.

GEN-NE. We expect our results to continue to be impacted by power prices, fuel prices, fuel availability and unit availability. Spreads between power and fuel costs are expected to remain volatile as fuel prices change based on demand and weather. This volatility has significant impact on the run-time for the Roseton unit. All of our coal supply requirements for 2007 are contracted at a fixed price. We continue to maintain sufficient coal and oil inventories and contractual commitments to provide us with a stable fuel supply.

Additionally, our results could be affected by potential changes in New York state environmental regulations, as well as our ability to obtain permits necessary for the operation of our facilities. Please see Note 9—Commitments and Contingencies—Danskammer State Pollutant Discharge Elimination System Permit and Note 9—Commitments and Contingencies—Roseton State Pollutant Discharge Elimination System Permit, respectively, for further discussion.

In connection with the Merger discussed in Note 2—LS Power Business Combination, we acquired assets in Connecticut and Maine. These assets include the 527 MW Bridgeport natural gas-fired facility in Bridgeport, CT and the 540 MW Casco Bay natural gas-fired facility in Veazie, ME.

The prior owners of the Bridgeport power plant initiated proceedings before the FERC to obtain an RMR agreement with ISO-NE, under which Bridgeport would receive cost-of-service rates from ISO-NE in exchange for selling all of its energy into ISO-NE. The proposed Bridgeport RMR agreement would be in effect commencing on June 1, 2005, and, unless earlier terminated, ending on the earlier of May 31, 2010, or the implementation of ISO-NE’s Forward Capacity Market. Bridgeport has been operating pursuant to the terms of the Bridgeport RMR agreement subject to the outcome of ongoing proceedings before the FERC to resolve the question of whether Bridgeport is eligible for an RMR agreement. We estimate the range of potential refund for the period from contract inception through March 2007 would be between approximately $10 million and $29 million, in the event Bridgeport fails to establish eligibility for an RMR.

Effective April 2, 2007, we issued termination notices to General Electric (“GE”) for LTSA contracts for the Casco Bay, Arlington Valley and Moss Landing facilities. The parties have been addressing issues relating to the termination of the LTSAs, and have entered into a Standstill and Tolling Agreement dated April 16, 2007 which tolls the effective date of the LTSA termination notices, and all related issues between the parties regarding the LTSAs. The parties are currently negotiating new arrangements during this standstill period, which would resolve all issues between the parties related to the LTSAs. If no new arrangements are agreed to, we will seek other parties to provide the services currently covered by the LTSAs and will actively address any other issues that arise in connection with the terminations.

GEN-SO. Our results at the CoGen Lyondell facility will be affected by our contract with Lyondell Chemical Company (“Lyondell”) which became effective on January 1, 2007. Under this contract, we sell up to approximately 80 MW of energy and 1.5 million pounds per hour of steam from our CoGen Lyondell cogeneration facility to Lyondell for an initial term from January 2007 through December 2021 and subsequent automatic rollover terms of two years each thereafter through December 2046.

Our peaking facilities in the South continue to contribute revenue from sales of capacity mainly to local load-serving entities or wholesale buyers. We currently have the majority of the portfolio capacity committed in the near-term, and a portion of our portfolio capacity committed on an annual basis through 2015.

Our 614 MW CoGen Lyondell and our 539 MW Heard County generation facilities are being considered for a potential sale. Please read “Asset Sale Proceeds” for further discussion.

In connection with the Merger discussed in Note 2—LS Power Business Combination, we acquired a portfolio of assets in California and Arizona. These assets include six facilities located in California (Moss Landing, Morro Bay, South Bay and Oakland) and Arizona (Arlington Valley and Griffith), with a total capacity of 5,545 MW. Moss Landing, Morro Bay, Oakland and Griffith are subject to certain power purchase agreements under which the buyer pays the power generation facility a fixed monthly payment for the right to call energy, capacity and ancillary services from the power generation facility. The South Bay and Oakland facilities operate under RMR agreements with the CAISO.

Moss Landing, Arlington Valley and Griffith sell energy, capacity and/or other ancillary services to wholesale electricity customers directly in the spot market. Several financially-settled heat rate call-option agreements are in effect that mitigate the exposure of these facilities to changes in the market price of energy.

Subsequent to completion of the Merger, these assets will be included in our GEN-SO business segment, which we will rename as our power generation business – West segment, or GEN-WE.

Cash Flow Disclosures

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


	Quarters Ended March 31,
	2007			2006
	(in millions)
Operating cash flows from our generation business	$	140		$	192
Operating cash flows from our customer risk management business		(6	)		(368	)
Other operating cash flows		(90	)		(135	)

Net cash provided by (used in) operating activities	$	44		$	(311	)

Operating Cash Flow. Our cash flow provided by operations totaled $44 million for the quarter ended March 31, 2007. During the quarter, our power generation business provided positive cash flow from operations of $140 million due to positive earnings for the period. Our customer risk management business used approximately $6 million in cash. Other and Eliminations includes a net use of approximately $90 million in cash primarily due to interest payments to service debt and general and administrative expenses.

Our cash flow used in operations totaled $311 million for the quarter ended March 31, 2006. During the quarter, our power generation business provided positive cash flow from operations of $192 million due to positive earnings for the period and changes in working capital primarily due to return of collateral. Our customer risk management business used approximately $368 million in cash primarily due to a $370 million termination payment on our Sterlington tolling contract, offset by other changes in working capital. Other and Eliminations includes a use of approximately $135 million in cash primarily due to interest payments to service debt and general and administrative expenses, partially offset by interest income on cash balances and the receipt of approximately $20 million associated with the resolution of a legal dispute.

Capital Expenditures and Investing Activities. Cash used in investing activities during the quarter ended March 31, 2007 totaled $26 million. Capital spending of $34 million was primarily comprised of $23 million, $3 million, and $5 million in the GEN-MW, GEN-NE, and GEN-SO segments, respectively. The capital spending for the GEN-MW and GEN-SO segments primarily related to maintenance and environmental capital projects. Capital spending in our GEN-NE segment primarily related to maintenance. The remainder of our first quarter capital spending related to corporate information technology projects. Cash outflows associated with capital spending were partly offset by a $9 million decrease in the Independence restricted cash balance.

Cash provided by investing activities during the quarter ended March 31, 2006 totaled $469 million. Capital spending of $18 million was primarily comprised of $11 million, $3 million, and $3 million in the GEN-MW, GEN-NE, and GEN-SO segments, respectively. The capital spending for the GEN-MW segment primarily related to maintenance capital projects, as well as $1 million in development capital associated with the completion of the Vermilion PRB conversion. Capital spending in our GEN-NE and GEN-SO segments primarily related to maintenance and environmental projects. The cost to acquire NRG’s 50% ownership interest in Rocky Road, net of cash proceeds, totaled $40 million. The decrease in restricted cash of $322 million related primarily to the return of our $335 million deposit associated with our former cash collateralized facility, offset by a $13 million increase in the Independence restricted cash balance. Net cash proceeds from asset sales of $205 million was due to the sale of our 50% ownership interest in West Coast Power to NRG.

Financing Activities. Cash used in financing activities during the quarter ended March 31, 2007 totaled $20 million, resulting primarily from a principal payment on the Sithe Energies debt.

Cash used in financing activities during the quarter ended March 31, 2006 totaled $16 million, primarily due to a semi-annual dividend payment of $11 million on our then-outstanding Series C convertible preferred stock.

RISK-MANAGEMENT DISCLOSURES

The following table provides a reconciliation of the risk-management data on the unaudited condensed consolidated balance sheets:


	As of and for the Quarter Ended March 31, 2007
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2007	$	53
Risk-management losses recognized through the income statement in the period, net		(16	)
Cash received related to risk-management contracts settled in the period, net		(9	)
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other (2)		(91	)

Fair value of portfolio at March 31, 2007	$	(63	)

(1)	Our modeling methodology has been consistently applied.

(2)	This amount consists of changes in value associated with cash flow hedges on forward power sales and fair value hedges on debt.

The net risk management liability of $63 million is the aggregate of the following line items on our condensed consolidated balance sheets: Current Assets—Assets from risk-management activities, Other Assets—Assets from risk-management activities, Current Liabilities—Liabilities from risk-management activities and Other Liabilities—Liabilities from risk-management activities.

Risk-Management Asset and Liability Disclosures. The following tables depict the mark-to-market value and cash flow components of our net risk-management assets and liabilities at March 31, 2007 and December 31, 2006. As opportunities arise to monetize positions that we believe will result in an economic benefit to us, we may receive or pay cash in periods other than those depicted below:

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


	Total			2007(3)			2008			2009		2010		2011		Thereafter
	(in millions)
March 31, 2007 (2)	$	(41	)	$	(37	)	$	(9	)	$	—	$	—	$	1	$	4
December 31, 2006 (2)		(44	)		(45	)		(3	)		—		—		1		3

(Increase) decrease	$	3		$	8		$	(6	)	$	—	$	—	$	—	$	1

(1)

The table reflects the fair value of our risk-management asset position, which considers time value, credit, price and other reserves necessary to determine fair value. These amounts exclude the fair value associated with certain derivative instruments designated as hedges. The net risk-management liabilities at March 31, 2007 of $63 million on the unaudited condensed consolidated balance sheets include the $41 million herein as well as hedging instruments. Cash flows have been segregated between periods based on the delivery date required in the individual contracts.

(2)	Our mark-to-market values at March 31, 2007 and December 31, 2006 were derived solely from market quotations.

(3)	Amounts represent April 1 to December 31, 2007 values in the March 31, 2007 row and January 1 to December 31, 2007 values in the December 31, 2006 row.

Cash Flow Components of Net Risk-Management Asset


	Three Months Ended March 31, 2007		Nine Months Ended December 31, 2007			Total 2007			2008			2009		2010		2011		Thereafter
	(in millions)
March 31, 2007 (1)	$	14	$	(37	)	$	(23	)	$	(9	)	$	—	$	—	$	1	$	6
December 31, 2006							(45	)		(4	)		—		—		1		5

(Increase) decrease						$	22		$	(5	)	$	—	$	—	$	—	$	1

(1)

The cash flow values for 2007 reflect realized cash flows for the three months ended March 31, 2007 and anticipated undiscounted cash inflows and outflows by contract based on the tenor of individual contract position for the remaining periods. These anticipated undiscounted cash flows have not been adjusted for counterparty credit or other reserves. These amounts exclude the cash flows associated with certain derivative instruments designated as hedges.

Accounting rules give us the option to designate derivative transactions that meet certain criteria as cash flow hedges. We enter into commodity transactions, including swaps, options and futures, which meet the criteria to be designated as cash flow hedges. Historically, we designated such transactions as cash flow hedges, and changes in value of these transactions were deferred until the underlying transaction being hedged came to term. Beginning on April 2, 2007, we chose to cease designating the transactions as cash flow hedges, and thus apply mark-to-market accounting treatment prospectively. This creates consistent accounting methodologies between our existing commodity derivative transactions and those we assumed upon completion of the Merger. Therefore, beginning with the second quarter 2007, such transactions will no longer be designated as cash flow hedges. Instead, these transactions will receive mark-to-market accounting treatment. Accordingly, as values fluctuate due to market price volatility, value changes will be reflected on the income statement. This change in accounting has no impact on our current commercial strategy.

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-Q includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements”. All statements included or incorporated by reference in this quarterly report, other than statements of historical fact, that address activities, events or developments that we or our management expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements represent our reasonable judgment on the future based on various factors and using numerous assumptions and are subject to known and unknown risks, uncertainties and other factors that could cause our actual results and financial position to differ materially from those contemplated by the statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate”, “project”, “forecast”, “plan”, “may”, “will”, “should”, “expect” and other words of similar meaning. In particular, these include, but are not limited to, statements relating to the following:

•

anticipated benefits and expected synergies resulting from the completion of the Merger Agreement and related transactions with the LS Contributing Entities and beliefs associated with the integration of operations of the various entities;

•

projected operating or financial results, including anticipated cash flows from operations, revenues and profitability;

•

expectations regarding capital expenditures, interest expense and other payments;

•

beliefs and assumptions about economic conditions and the demand and prices for electricity;

•

beliefs about commodity pricing and generation volumes;

•

our focus on safety and our ability to efficiently operate our assets so as to maximize our revenue generating opportunities;

•

strategies to capture opportunities presented by rising commodity prices and strategies to manage our exposure to energy price volatility;

•

plans to achieve fuel-related, general and administrative, and other targeted cost savings;

•

beliefs and assumptions relating to liquidity, including the ability to satisfy or refinance debt maturities and other obligations before or as they come due;

•

strategies to address our substantial leverage, to access the capital markets, or to obtain additional financing on more favorable financing terms;

•

measures to compete effectively with industry participants;

•

beliefs and assumptions about market competition, fuel supply, power demand, generation capacity and regional supply and demand characteristics of the wholesale power generation market;

•

sufficiency of coal, fuel oil and natural gas inventories and transportation, including strategies to deploy coal supplies;

•

beliefs about the outcome of legal, regulatory and administrative matters;

•

expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations;

•

expectations and estimates regarding the DMG consent decree and the associated costs; and

•

efforts to position our power generation business for future growth and pursuing and executing acquisition, disposition or combination opportunities.

Any or all of our forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors, many of which are beyond our control, including those set forth under Part II–Other Information, Item 1A-Risk Factors.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1 to the unaudited condensed consolidated financial statements for a discussion of recently issued accounting pronouncements affecting us.

CRITICAL ACCOUNTING POLICIES

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

Item 3—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Please read Item 7A. Quantitative and Qualitative Disclosures About Market Risk beginning on page 81 of our Form 10-K for a discussion of our exposure to commodity price variability and other markets risks, including foreign currency exchange rate risk. Following is a discussion of the more material of these risks and our relative exposures as of March 31, 2007.

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

Daily and Average VaR for Risk-Management Portfolios

As a result of our decision to mark-to-market all commodity related derivative securities, we expect that our reported VaR amounts will increase in future periods. In many cases, future production from our generating assets offsets the incremental VaR exposure.

Credit Risk. The following table represents our credit exposure at March 31, 2007 associated with the mark-to-market portion of our risk-management portfolio, on a net basis.

Credit Exposure Summary


	Investment Grade Quality
	(in millions)
Type of Business:
Financial Institutions	$	51
Utility and Power Generators		15
Other		1

Total	$	67

Interest Rate Risk. We are exposed to fluctuating interest rates related to variable rate financial obligations. As of March 31, 2007, our fixed rate debt instruments as a percentage of total debt instruments was approximately 78%. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of March 31, 2007, it is estimated that a one percentage point interest rate movement in the average market interest rates (either higher or lower) over the 12 months ended March 31, 2008 would either decrease or increase income before taxes by approximately $7 million. Hedging instruments that impact such interest rate exposure are included in the sensitivity analysis. Over time, we may seek to reduce the percentage of fixed rate financial obligations in our debt portfolio through the use of swaps or other financial instruments. Effective April 2, 2007, we assumed additional debt due to the completion of the Merger Agreement.

Derivative Contracts. The notional financial contract amounts associated with our commodity risk-management, interest rate and foreign currency exchange contracts were as follows at March 31, 2007 and December 31, 2006, respectively:

Absolute Notional Contract Amounts


	March 31, 2007		December 31, 2006
Natural Gas (Trillion Cubic Feet)		0.238		0.309
Electricity (Million Megawatt Hours)		148.083		138.705
Emission Credits (Million Tons) (1)		0.0155		0.0155
Fuel Oil (Million Barrels)		1.635		1.620
Value Hedge Interest Rate Swaps (In Millions of U.S. Dollars)	$	525	$	525
Fixed Interest Rate Received on Swaps (%)		4.331		4.331
Rate Risk-Management Contract (In Millions of U.S. Dollars)	$	231	$	231
Fixed Interest Rate Paid (%)		5.35		5.35
Interest Rate Risk-Management Contract (In Millions of U.S. Dollars)	$	206	$	206
Fixed Interest Rate Received (%)		5.28		5.28

(1)	These amounts represent emission credit contracts that we are required to account for as derivatives under SFAS No. 133. These amounts do not include the emission credits that we have recorded in our inventory related to allowances that we utilize in running our power generation fleet.

Item 4—CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). This evaluation included consideration of the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified by the SEC. This evaluation also considered the work completed as of the end of the first quarter 2007 relating to our compliance with Section 404 of the Sarbanes-Oxley Act of 2002. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of March 31, 2007.

Changes in Internal Controls Over Financial Reporting

There were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting during the first quarter of 2007.

DYNEGY INC.

PART II. OTHER INFORMATION

Item 1—LEGAL PROCEEDINGS

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

Item 1A—RISK FACTORS

Additional Risks Related to our Business

Covenants in our financing agreements impose significant restrictions on us. Failure to comply with these covenants may have a material adverse impact on our business, financial condition, results of operations or cash flows.

Financing agreements governing our debt obligations require us to meet specific financial tests in order to issue debt and make restricted payments, among other things. Our ability to comply with the covenants in our financing agreements, as they currently exist or as they may be amended, may be affected by many events beyond our control, and our future operating results may not allow us to comply with the covenants or, in the event of a default, to remedy that default. Our failure to comply with those financial covenants or to comply with the other restrictions in our financing agreements could result in a default, causing our debt obligations under such financing agreements (and by reason of cross-default or cross-acceleration provisions, our other indebtedness) to become immediately due and payable, which could have a material adverse impact on our business, financial condition, results of operations or cash flows. If we are unable to repay those amounts or to otherwise cure the default, the holders of the indebtedness under our secured debt obligations could proceed against the collateral granted to them to secure that indebtedness. If those lenders accelerate the payment of such indebtedness, we cannot assure you that we could pay or refinance that indebtedness immediately and continue to operate our business.

We may not have adequate liquidity to post required amounts of additional collateral.

We use a portion of our capital resources, in the form of cash and letters of credit, to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade credit ratings and the counterparties’ views of our creditworthiness, as well as changes in commodity prices. If commodity prices change substantially, our liquidity could be severely strained by requirements under our commodity agreements to post additional collateral. In certain cases, our counterparties have elected to not require the posting of collateral to which they are otherwise entitled under those agreements. However, those counterparties retain the right to request the posting of such collateral. Factors that could trigger increased demands for collateral include additional adverse changes in our industry, negative regulatory or litigation developments, adverse events affecting us, changes in our credit rating or liquidity and changes in commodity prices for power and fuel. In addition, to the extent we do hedge against volatility in commodity prices and, as a result, our cash flow is less than anticipated, a source of our liquidity resources may be depleted. An increase in demands from our counterparties to post letters of credit or cash collateral may have a material adverse effect on our financial condition, results of operations and cash flows.

Plum Point, which is currently under construction, may not be completed, and the construction of other development projects in which we have an ownership interest via DLS Power Holdings and DLS Power Development may never be initiated or completed.

Pursuant to the Merger Agreement, we acquired all of the LS Power Group’s ownership interest in Plum Point, which is currently in the construction phase, with an expected completion date in 2010. We also acquired a 50% ownership interest in DLS Power Holdings and DLS Power Development, which owns the various “greenfield” projects and expansion and replacement projects contributed to DLS Power Holdings and DLS Power Development by us and the LS Power Group; additional development projects will be contributed to DLS Power Holdings and DLS Power Development from time to time by us and the LS Power Group.

As a result of economic and other conditions, Plum Point may not be completed, and the development projects may not be pursued or completed, and higher costs than those that are anticipated may be incurred with respect to any of the projects. These projects also generally require various governmental and other approvals, which may not be received. Our inability to complete the Plum Point project, or DLS Power Holdings and DLS Power Development’s inability to complete a development project on time or within budget, may adversely affect our financial condition, results of operations and cash flows.

In addition, the development and construction of power generation facilities may be adversely affected by one or more factors commonly associated with large infrastructure projects, including, but not limited to, changes in the forecasted financial viability of new-build generation in a region, shortages of equipment, materials and labor, delays in delivery of equipment and materials, labor disputes, litigation, failure to obtain necessary governmental and regulatory approvals and permits, adverse weather conditions, unanticipated increases in costs, natural disasters, accidents, local and political opposition, unforeseen engineering, design, environmental or geological problems and other unforeseen events or circumstances. Any one of these events could result in delays in, or even the abandonment of, the development of the affected power generation facility. Such events may also result in cost overruns, payments under committed contracts associated with the affected project, and/or the write-off of equity investment in the project. Any such development may materially and adversely affect our financial condition, results of operations and cash flows.

The future operation and performance of the various development projects owned by DLS Power Holdings and DLS Power Development, if completed, are subject to a wide variety of factors and cannot be predicted with certainty at this time.

If a development project is successfully completed by DLS Power Holdings and DLS Power Development, the operation and performance of the completed facility could be affected by many factors, including start-up problems, the breakdown or failure of equipment or processes, the performance of the completed facility below expected levels of output or efficiency, failure to operate at design specifications, labor disputes, changes in law, failure to obtain necessary permits or to meet permit conditions, government exercise of eminent domain power or similar events and catastrophic events including fires, explosions, earthquakes and droughts. The occurrence of such events could significantly reduce or eliminate the revenues from, or significantly increase the expenses associated with, any such completed facility and, as a result, negatively impact our financial condition, results of operations and cash flows.

If we issue a material amount of our common stock in the future or certain of our stockholders, such as Chevron or any of the LS Contributing Entities or their affiliates, sell a material amount of our common stock, our ability to use our federal net operating losses to offset our future taxable income may be limited under Section 382 of the Internal Revenue Code.

Our ability to utilize previously incurred federal net operating losses (“NOLs”) to offset our future taxable income would be limited if we were to undergo an “ownership change” within the meaning of Section 382 of the Code. In general, an “ownership change” occurs whenever the percentage of the stock of a corporation owned by “5-percent shareholders” (within the meaning of Section 382 of the Code) increases by more than 50 percentage points over the lowest percentage of the stock of such corporation owned by such “5-percent shareholders” at any time over the preceding three years.

Under certain circumstances, sales or other dispositions of our common stock by certain of our stockholders could trigger such an “ownership change”. Specifically, sales or other dispositions pursuant by any of the selling stockholders of our Class A common stock issuable upon the conversion of our Class B common stock could trigger an “ownership change”. Moreover, sales or other dispositions of our Class A common stock by Chevron pursuant to a prospectus and any prospectus supplement forming a part of a Registration Statement on Form S-3 that we have filed with the SEC for the benefit of Chevron could also trigger such an “ownership change”. We will have limited control over the timing of any such sales or dispositions of our common stock. Any such future ownership change could result in limitations, pursuant to Section 382 of the Code, on our utilization of our federal NOLs to offset our future taxable income.

More specifically, depending on then-prevailing interest rates and the market value of our stock at the time of such future ownership change, an ownership change under Section 382 of the Code would establish an annual limitation which might prevent full utilization of the deferred tax assets attributable to our previously incurred federal NOLs against our total future taxable income for a given year. If such an ownership change were to occur, our ability to raise additional equity capital may be limited.

The magnitude of such limitations and their effect on us is difficult to assess and depends in part on the market value of our stock at the time of any such ownership change and then-prevailing interest rates, as well as the availability of built-in gains which may reduce any such effects. For accounting purposes, at March 31, 2007, our deferred tax asset attributable to our previously incurred federal NOLs was valued at approximately $243 million.

Additional Risks Related to our Class A Common Stock

The stock price of our predecessor, Dynegy Illinois, was volatile, and the trading price of our Class A common stock may also fluctuate significantly.

The trading price of the Class A common stock of Dynegy Illinois was volatile, and our stock price may also be volatile. From January 1, 2004 through March 30, 2007 (i.e., the trading day immediately prior to the completion of the Merger Agreement), the closing price of Dynegy Illinois’ Class A common stock on the NYSE ranged from $3.23 to $9.58 per share. The trading price of our Class A common stock may fluctuate in response to a number of events and factors, such as quarterly variations in operating or financial results, actions by various regulatory agencies, litigation, market perceptions of our financial reporting, changes in financial estimates and recommendations by securities analysts, the operating and stock price performance of other companies that investors may deem comparable to us, news reports relating to us or trends in our industry or general economic conditions.

Provisions of the General Corporation Law of the State of Delaware and our organizational documents may discourage an acquisition of us.

Our organizational documents and the General Corporation Law of the State of Delaware both contain provisions that will impede the removal of our directors and may discourage a third party from making a proposal to acquire us. For example, our board may, without the consent of our stockholders, issue preferred stock with greater voting rights than our Class A common stock. The existence of these provisions may have a negative impact on the price of our Class A common stock.

The interests of the LS Control Group may conflict with your interests and, with respect to DLS Power Holdings and DLS Power Development, our interests.

The LS Control Group (as defined in the Merger Agreement) owns approximately 40% of our voting power and has the right to nominate up to three members of our 11-member board of directors. By virtue of such stock ownership and board representation, the LS Control Group has, as described in the risk factor immediately below, the power to influence our affairs and the outcome of matters required to be submitted to our stockholders for approval. Moreover, by virtue of such stock ownership and board representation and its 50 percent membership interest (via LS Associates) in DLS Power Holdings and DLS Power Development, the LS Control Group has the power to influence the affairs of DLS Power Holdings and DLS Power Development.

The LS Control Group may have interests that differ from those of holders of our Class A common stock, and these relationships could give rise to conflicts of interest, including:

•

conflicts between the LS Control Group and our other stockholders, whose interests may differ with respect to the strategic direction or significant corporate transactions of the company; and

•

conflicts related to corporate opportunities that could be pursued by us, on the one hand, or by the LS Control Group, on the other hand.

Likewise, with respect to DLS Power Holdings and DLS Power Development, the LS Control Group may have interests that differ from our interests (as the owner of the remaining 50% membership interest in DLS Power Holdings and DLS Power Development), which may give rise to conflicts of interests.

Further, our amended and restated certificate of incorporation renounces any interest in, and waives, any claim that a corporate or business opportunity taken by the LS Control Group constitutes a corporate opportunity of the company, unless such corporate or business opportunity is expressly offered to one of our directors or officers.

The LS Control Group’s significant interest in us could be determinative in matters submitted to a vote by our stockholders. In addition, the rights granted to the LS Shareholders (as defined in the Merger Agreement) under the Shareholder Agreement (as defined in the Merger Agreement) and our amended and restated bylaws provide them significant influence over us. Such influence could result in us either taking actions that our other stockholders do not support or failing to take actions that our other stockholders do support.

The LS Control Group’s ownership interest in us, together with its rights under the Shareholder Agreement and our amended and restated bylaws, provides it with significant influence over the conduct of our business. Unless substantially all of our public stockholders vote together on matters presented to our stockholders from time to time, the LS Control Group may have the power to determine the outcome of matters submitted to a vote of all of our stockholders.

Rights granted to the LS Control Group under the Shareholder Agreement and our amended and restated bylaws that provide it with significant influence over our business include:

•

the ability to nominate up to three directors to our board of directors based on its percentage ownership interest in us; and

•

the requirement that we not pursue any of the following actions if all directors nominated by the LS Control Group present at the relevant board meeting vote against such action:

•

any amendment of our amended and restated certificate of incorporation or amended and restated bylaws;

•

any merger or consolidation of us and certain dispositions of our assets or businesses, certain acquisitions, binding capital commitments, guarantees and investments and certain joint ventures with an aggregate value in excess of a specified amount;

•

our payment of dividends or similar distributions;

•

our engagement in new lines of business;

•

our liquidation or dissolution, or certain bankruptcy-related events with respect to us;

•

our issuance of any equity securities, with certain exceptions for issuances of our Class A common stock;

•

our incurrence of any indebtedness in excess of a specified amount;

•

the hiring, or termination of the employment of, our Chief Executive Officer (other than Bruce A. Williamson);

•

our entry into any agreement or other action that limits the activities of any holder of our Class B common stock or any of such holder’s affiliates; and

•

our entry into other material transactions with a value in excess of a specified amount.

Such influence could result in us either taking actions that our other stockholders do not support or failing to take actions that our other stockholders do support.

Our stockholders may be adversely affected by the expiration of the transfer restrictions in the Shareholder Agreement, which would enable the LS Control Group to, among other things, transfer a significant percentage of our common stock to a third party.

The transfer provisions in the Shareholder Agreement, subject to specified exceptions, restrict the LS Control Group from transferring shares of our common stock. These restrictions will expire upon the earlier of:

•

April 2, 2009;

•

the date the stockholders party to the Shareholder Agreement cease to own at least 15% of the total combined voting power of our outstanding securities; and

•

subject to certain conditions, the date a third party offer is made to acquire more than 25% of our assets or voting securities.

In addition, if the transfer restrictions in the Shareholder Agreement are terminated, the LS Control Group will be free to sell their shares of our common stock, subject to certain exceptions, to any person on the open market, in privately negotiated transactions or otherwise in accordance with law. These sales or transfers, as well as sales or other dispositions, could create a substantial decline in the price of shares of our common stock, including our Class A common stock.

Item 2—UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Upon vesting of restricted stock awarded by the company to employees, shares are withheld to cover the employees’ withholding taxes. Information on the company’s purchases of equity securities during the quarter follows:


Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
January	297	6.02	—	N/A
February	196,055	7.47	—	N/A
March	77,733	8.51	—	N/A

These were the only repurchases of equity securities made by us during the three months ended March 31, 2007. We do not have a repurchase program.

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

A special meeting of the shareholders of Dynegy Illinois was held on March 29, 2007. The purpose of the special meeting was to consider and vote on a proposal to adopt the Merger Agreement and to approve the Merger of Merger Sub with and into Dynegy Illinois. The following votes were cast with respect to the proposal, which passed. There were no broker non-votes.

Class A Common Stock (Dynegy Inc., an Illinois corporation)


FOR	AGAINST	ABSTAIN
312,718,633	2,126,935	3,119,106

Class B Common Stock (Dynegy Inc., an Illinois corporation)


FOR	AGAINST	ABSTAIN
96,891,014	0	0

Class A and Class B Common Stock voting together as a single class


FOR	AGAINST	ABSTAIN
409,609,647	2,126,935	3,119,106

Item 6—EXHIBITS

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


Exhibit Number		Description
3.1		Amended and Restated Certificate of Incorporation of Dynegy Inc. (formerly named Dynegy Acquisition, Inc.) (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

3.2		Amended and Restated Bylaws of Dynegy Inc. (formerly named Dynegy Acquisition, Inc.) (incorporated by reference to Exhibit 4.2 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

10.1		First Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan), dated as of October 17, 2003. (incorporated by reference to Exhibit 4.24 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

10.2		Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan), dated as of December 23, 2003 (incorporated by reference to Exhibit 4.25 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).


Exhibit Number		Description
10.3		Second Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan), dated as of March 31, 2004 (incorporated by reference to Exhibit 4.26 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

10.4		Fourth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan), dated as of September 29, 2004 (incorporated by reference to Exhibit 4.27 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

10.5		Fifth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan), dated as of May 31, 2005 (incorporated by reference to Exhibit 4.28 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

10.6		Sixth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan), dated as of June 7, 2006 (incorporated by reference to Exhibit 4.29 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

10.7		Seventh Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan), dated as of December 15, 2006 (incorporated by reference to Exhibit 4.30 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

10.8		Eighth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.40 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.9		First Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered under a Collective Bargaining Agreement), dated as of October 17, 2003 (incorporated by reference to Exhibit 4.33 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

10.10		Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered under a Collective Bargaining Agreement), dated as of December 23, 2003 (incorporated by reference to Exhibit 4.34 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).


Exhibit Number		Description
10.11		Second Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered under a Collective Bargaining Agreement), dated as of March 31, 2004 (incorporated by reference to Exhibit 4.35 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

10.12		Fourth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered under a Collective Bargaining Agreement), dated as of September 29, 2004 (incorporated by reference to Exhibit 4.36 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

10.13		Fifth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered under a Collective Bargaining Agreement), dated as of May 31, 2005 (incorporated by reference to Exhibit 4.37 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

10.14		Sixth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered under a Collective Bargaining Agreement), dated as of June 7, 2006 (incorporated by reference to Exhibit 4.38 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

10.15		Seventh Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered under a Collective Bargaining Agreement), dated as of December 15, 2006 (incorporated by reference to Exhibit 4.39 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

10.16		Eighth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered Under a Collective Bargaining Agreement, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.41 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.17		Fifth Amended and Restated Credit Agreement, dated as of April 2, 2007, by and among Dynegy Holdings Inc., as borrower, Dynegy Inc. (formerly named Dynegy Acquisition, Inc.) and Dynegy Inc., as parent guarantors, the other guarantors party thereto, the lenders party thereto and various other parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.17		Second Amended and Restated Security Agreement, dated April 2, 2007, by and among Dynegy Holdings Inc., as Borrower, the initial grantors party thereto, Wilmington Trust Company, as corporate trustee, and John M. Beeson, Jr., as individual trustee (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).


Exhibit Number		Description
10.18		First Lien Credit Agreement, dated as of May 4, 2006, by and among LSP Gen Finance Co, LLC, as borrower, and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.19		Second Lien Credit Agreement, dated as of May 4, 2006, by and among LSP Gen Finance Co, LLC, as borrower, and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.20		$500,000,000 Special Letter of Credit Facility Agreement, dated as of May 4, 2006, by and among LSP Gen Finance Co, LLC, as borrower, and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.21		$150,000,000 First Lien Letter of Credit Facility Agreement, dated as of August 3, 2006, by and among LSP Gen Finance Co, LLC, as borrower, and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.22		Credit Agreement, dated as of October 7, 2005, by and among LSP-Kendall Energy, LLC, as borrower, and the lenders and other parties thereto (incorporated by reference to Exhibit 10.7 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.23		Amended and Restated First Lien Credit Agreement, dated as of May 5, 2006, by and among Ontelaunee Power Operating Company, LLC, as borrower, and the lenders and other parties thereto (incorporated by reference to Exhibit 10.8 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.24		Second Lien Credit Agreement, dated as of May 5, 2006, by and among Ontelaunee Power Operating Company, LLC, as borrower, and the lenders and other parties thereto (incorporated by reference to Exhibit 10.9 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.25		Credit Agreement, dated as of March 29, 2007, by and among Plum Point Energy Associates, LLC, as borrower, and the lenders and other parties thereto (incorporated by reference to Exhibit 10.10 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.26		Collateral Agency and Intercreditor Agreement, dated as of March 29, 2007, by and among Plum Point Energy Associates, LLC, as borrower, PPEA Holding Company, LLC, as pledgor, The Bank of New York, as collateral agent, The Royal Bank of Scotland, as administrative agent, AMBAC Assurance Corporation, as loan insurer and the other parties thereto (incorporated by reference to Exhibit 10.11 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.27		Loan Agreement, dated as of April 1, 2006, by and between the City of Osceola, Arkansas and Plum Point Energy Associates, LLC (incorporated by reference to Exhibit 10.12 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).


Exhibit Number		Description
10.28		Trust Indenture, dated as of April 1, 2006, by and between the City of Osceola, Arkansas and Regions Bank, as trustee (incorporated by reference to Exhibit 10.13 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.29		Amended and Restated Limited Liability Company Agreement of DLS Power Holdings, LLC, dated April 2, 2007, by and between LS Power Associates, L.P. and Dynegy Inc. (formerly named Dynegy Acquisition, Inc.) (incorporated by reference to Exhibit 10.14 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.30		Limited Liability Company Agreement of DLS Power Development Company, LLC, dated April 2, 2007, by and between LS Power Associates, L.P. and Dynegy Inc. (formerly named Dynegy Acquisition, Inc.) (incorporated by reference to Exhibit 10.15 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.31		Fourth Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan, dated as of March 30, 2007 (incorporated by reference to Exhibit 10.16 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.32		Third Amendment to the Dynegy Inc. Executive Severance Pay Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.17 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.33		Second Amendment to the First Supplemental Plan to the Dynegy Inc. Severance Pay Plan, dated as of March 30, 2007 (incorporated by reference to Exhibit 10.18 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.34		Second Amendment to Dynegy Inc. Severance Pay Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.19 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.35		Second Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan, dated as of December 5, 2005 (incorporated by reference to Exhibit 10.20 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.36		Third Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan, dated as of June 7, 2006 (incorporated by reference to Exhibit 10.21 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.37		Fourth Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan, dated as of December 15, 2006 (incorporated by reference to Exhibit 10.22 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.38		Fifth Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of January 28, 2005 (incorporated by reference to Exhibit 10.23 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).


Exhibit Number		Description
10.39		Sixth Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of February 28, 2005 (incorporated by reference to Exhibit 10.24 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.40		Seventh Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of May 31, 2005 (incorporated by reference to Exhibit 10.25 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.41		Eighth Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of December 18, 2006 (incorporated by reference to Exhibit 10.26 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.42		Ninth Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of June 7, 2006 (incorporated by reference to Exhibit 10.27 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.43		Ninth Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of December 21, 2006 (incorporated by reference to Exhibit 10.28 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.44		Eleventh Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.30 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.45		Ninth Amendment to the Dynegy Inc. Retirement Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.29 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.46		Sixth Amendment to the Dynegy Inc. Comprehensive Welfare Benefits Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.31 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.47		First Amendment to the Dynegy Inc. Incentive Compensation Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.32 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.48		First Amendment to the Dynegy Inc. 1999 Long Term Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.33 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.49		Second Amendment to the Dynegy Inc. 2000 Long Term Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.34 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.50		First Amendment to the Dynegy Inc. 2001 Non-Executive Stock Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.35 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.51		Second Amendment to the Dynegy Inc. 2002 Long Term Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.36 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).


Exhibit Number		Description
10.52		Third Amendment to the Dynegy Inc. Deferred Compensation Plan for Certain Directors, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.37 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.53		Amendment to the Dynegy Inc. Deferred Compensation Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.38 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.54		Sixth Amendment to the Dynegy Midwest Generation, Inc. Retirement Income Plan for Employees Covered Under a Collective Bargaining Agreement, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.39 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.55		Seventh Amendment to the Dynegy Northeast Generation, Inc. Retirement Income Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.42 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.56		Fifth Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.43 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.57		Eighth Amendment to the Extant, Inc. 401(k) Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.44 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.58		Master Trust Agreement, dated as of January 1, 2002 (Vanguard) (incorporated by reference to Exhibit 10.45 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.59		Agreement and Amendment to Master Trust Agreement, dated as of December 31, 2003 (Vanguard) (incorporated by reference to Exhibit 10.46 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.60		Amendment No. 2 to The Master Trust Agreement, dated as of September 29, 2004 (Vanguard) (incorporated by reference to Exhibit 10.47 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.61		Amendment to Master Trust Agreement, dated as of January 1, 2006 (Vanguard) (incorporated by reference to Exhibit 10.48 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.62		Amendment to Trust Agreement - DMG 401(k) Savings Plan (Vanguard), dated as of September 29, 2004 (incorporated by reference to Exhibit 10.49 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.63		Amendment to Trust Agreement - DMG 401(k) Savings Plan (Vanguard), dated as of January 1, 2006 (incorporated by reference to Exhibit 10.50 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).


Exhibit Number		Description
10.64		Amendment to Trust Agreement - DMG 401(k) Savings Plan (Vanguard), dated as of April 2, 2007 (incorporated by reference to Exhibit 10.51 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.65		Amendment to Trust Agreement - Dynegy Inc. 401(k) Savings Plan (Vanguard), dated as of January 1, 2006 (incorporated by reference to Exhibit 10.52 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.66		Amendment to Trust Agreement - Dynegy Inc. 401(k) Savings Plan (Vanguard), dated as of April 2, 2007 (incorporated by reference to Exhibit 10.53 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.67		Amendment to Dynegy Inc. Deferred Compensation Plan Trust Agreement (Vanguard), dated as of April 2, 2007 (incorporated by reference to Exhibit 10.54 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.68		Amendment to Master Trust Agreement, dated as of April 2, 2007 (Vanguard) (incorporated by reference to Exhibit 10.55 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.69		Asset Purchase Agreement dated January 31, 2007 by and between Dynegy Holdings Inc., Calcasieu Power, LLC and Entergy Gulf States, Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on February 2, 2007, File No. 333-139221).

**10.70		Form of Non-Qualified Stock Option Award Agreement Between Dynegy Inc., all of its affiliates and Bruce A. Williamson.

**10.71		Form of Restricted Stock Award Agreement between Dynegy Inc., all of its affiliates and Bruce A. Williamson.

**10.72		Form of Performance Award Agreement between Dynegy Inc., all of its affiliates and Bruce A. Williamson.

**10.73		Form of Non-Qualified Stock Option Award Agreement.

**10.74		Form of Restricted Stock Award Agreement (Managing Director and Above).

**10.75		Form of Restricted Stock Award Agreement (Directors and Below).

**10.76		Form of Performance Award Agreement.

**31.1		Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

**31.2		Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

**	Filed herewith.

†

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

DYNEGY INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, the thereunto duly authorized.


	DYNEGY INC.

Date: May 9, 2007	By:	/s/ HOLLI C. NICHOLS
		Holli C. Nichols
		Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)