Edgar Filing: DYNEGY INC /IL/

September 30,
2006

December 31,
2005

(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

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 September 30, 2006

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

For the transition period from to

Commission file number: 1-15659

DYNEGY INC.

(Exact name of registrant as specified in its charter)


Illinois		74-2928353
(State 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, no par value per share, 401,197,702 shares outstanding as of November 3, 2006; Class B common stock, no par value per share, 96,891,014 shares outstanding as of November 3, 2006.

DYNEGY INC.

TABLE OF CONTENTS


		Page
PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS:

Condensed Consolidated Balance Sheets:
September 30, 2006 and December 31, 2005		4
Condensed Consolidated Statements of Operations:
For the three and nine months ended September 30, 2006 and 2005		5
Condensed Consolidated Statements of Cash Flows:
For the nine months ended September 30, 2006 and 2005		6
Condensed Consolidated Statements of Comprehensive Income (Loss):
For the three and nine months ended September 30, 2006 and 2005		7
Notes to Condensed Consolidated Financial Statements		8

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		45
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		71
Item 4. CONTROLS AND PROCEDURES		72

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS		75
Item 1A. RISK FACTORS		75
Item 6. EXHIBITS		78

DEFINITIONS

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


APB		Accounting Principles Board
APIC		Additional paid-in-capital
ARO		Asset retirement obligation
CDWR		California Department of Water Resources
CEO		Chief Executive Officer
CFO		Chief Financial Officer
CFTC		Commodity Futures Trading Commission
CRM		Our customer risk management business segment
CUSA		Chevron U.S.A. Inc., a wholly owned subsidiary of Chevron Corporation
DGC		Dynegy Global Communications
DHI		Dynegy Holdings Inc., our primary financing subsidiary
DMG		Dynegy Midwest Generation, Inc.
DMSLP		Dynegy Midstream Services Limited Partnership
DMT		Dynegy Marketing and Trade
DNE		Dynegy Northeast Generation, Inc.
DPM		Dynegy Power Marketing, Inc.
EBITDA		Earnings Before Interest, Taxes, Depreciation and Amortization
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
HSR		Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended
ICC		Illinois Commerce Commission
IGC		Illinova Generating Company
ISO		Independent System Operator
LNG		Liquefied natural gas
LSP		LS Power
LTIP		Long-term incentive plan
MISO		Midwest Independent Transmission System Operator, Inc.
MMBtu		Millions of British thermal units
MW		Megawatts
MWh		Megawatt hour
NGL		Our former natural gas liquids business segment
NNG		Northern Natural Gas Company
NOL		Net operating loss
NRG		NRG Energy, Inc.
NYSDEC		New York State Department of Environmental Conservation
PRB		Powder River Basin coal
PUHCA		Public Utility Holding Company Act of 1935, as amended
SAB		SEC Staff Accounting Bulletin
SEC		U.S. Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
SPDES		State Pollutant Discharge Elimination System
SPN		Second Priority Senior Secured Notes
VaR		Value at Risk
VIE		Variable Interest Entity

DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)


	September 30, 2006			December 31, 2005
ASSETS
Current Assets
Cash and cash equivalents	$	388		$	1,549
Restricted cash		277			397
Accounts receivable, net of allowance for doubtful accounts of $70 and $103, respectively		284			611
Accounts receivable, affiliates		1			29
Inventory		197			214
Assets from risk-management activities		343			665
Deferred income taxes		26			14
Prepayments and other current assets		99			227
Assets held for sale (Note 3)		1			—

Total Current Assets		1,616			3,706

Property, Plant and Equipment		6,422			6,515
Accumulated depreciation		(1,417	)		(1,192	)

Property, Plant and Equipment, Net		5,005			5,323
Other Assets
Unconsolidated investments		7			270
Restricted investments		82			85
Assets from risk-management activities		103			165
Intangible assets		362			392
Deferred income taxes		3			3
Other long-term assets		135			182
Assets held for sale (Note 3)		194			—

Total Assets	$	7,507		$	10,126

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	215		$	504
Accounts payable, affiliates		—			46
Accrued interest		91			159
Accrued liabilities and other current liabilities		194			649
Liabilities from risk-management activities		339			687
Liabilities held for sale (Note 3)		1			—
Notes payable and current portion of long-term debt		48			71

Total Current Liabilities		888			2,116

Long-term debt		3,162			4,028
Long-term debt, affiliates		200			200

Long-Term Debt		3,362			4,228
Other Liabilities
Liabilities from risk-management activities		112			255
Deferred income taxes		440			558
Other long-term liabilities		391			429

Total Liabilities		5,193			7,586

Commitments and Contingencies (Note 10)
Redeemable Preferred Securities, redemption value of $400 at December 31, 2005		—			400
Stockholders’ Equity
Class A Common Stock, no par value, 900,000,000 shares authorized at September 30, 2006 and December 31, 2005; 402,895,968 and 305,129,052 shares issued and outstanding at September 30, 2006 and December 31, 2005, respectively		3,366			2,949
Class B Common Stock, no par value, 360,000,000 shares authorized at September 30, 2006 and December 31, 2005; 96,891,014 shares issued and outstanding at September 30, 2006 and December 31, 2005		1,006			1,006
Additional paid-in capital		37			51
Subscriptions receivable		(8	)		(8	)
Accumulated other comprehensive income, net of tax		59			4
Accumulated deficit		(2,077	)		(1,793	)
Treasury stock, at cost, 1,786,224 shares at September 30, 2006 and 1,714,026 shares at December 31, 2005		(69	)		(69	)

Total Stockholders’ Equity		2,314			2,140

Total Liabilities and Stockholders’ Equity	$	7,507		$	10,126

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Revenues	$	581		$	770		$	1,620		$	1,691
Cost of sales, exclusive of depreciation shown separately below		(387	)		(572	)		(1,103	)		(1,482	)
Depreciation and amortization expense		(57	)		(56	)		(174	)		(165	)
Impairment and other charges		(96	)		—			(107	)		(6	)
Gain (loss) on sale of assets, net		—			(1	)		3			(1	)
General and administrative expenses		(59	)		(76	)		(160	)		(421	)

Operating income (loss)		(18	)		65			79			(384	)
Earnings from unconsolidated investments		4			7			6			14
Interest expense		(105	)		(99	)		(310	)		(284	)
Debt conversion costs		(2	)		—			(249	)		—
Other income and expense, net		11			—			41			9

Loss from continuing operations before income taxes		(110	)		(27	)		(433	)		(645	)
Income tax benefit (Note 13)		39			13			154			228

Loss from continuing operations		(71	)		(14	)		(279	)		(417	)
Income from discontinued operations, net of tax benefit (expense) of $(6), $(26), $(5) and $54, respectively (Notes 3 and 13)		2			43			3			209

Income (loss) before cumulative effect of change in accounting principle		(69	)		29			(276	)		(208	)
Cumulative effect of change in accounting principle, net of tax expense of zero		—			—			1			—

Net income (loss)		(69	)		29			(275	)		(208	)
Less: preferred stock dividends		—			6			9			17

Net income (loss) applicable to common stockholders	$	(69	)	$	23		$	(284	)	$	(225	)

Earnings (Loss) Per Share (Note 9):
Basic earnings (loss) per share:
Loss from continuing operations	$	(0.14	)	$	(0.05	)	$	(0.65	)	$	(1.13	)
Income from discontinued operations		—			0.11			0.01			0.54
Cumulative effect of change in accounting principle		—			—			—			—

Basic earnings (loss) per share	$	(0.14	)	$	0.06		$	(0.64	)	$	(0.59	)

Diluted earnings (loss) per share:
Loss from continuing operations	$	(0.14	)	$	(0.05	)	$	(0.65	)	$	(1.13	)
Income from discontinued operations		—			0.11			0.01			0.54
Cumulative effect of change in accounting principle		—			—			—			—

Diluted earnings (loss) per share	$	(0.14	)	$	0.06		$	(0.64	)	$	(0.59	)

Basic shares outstanding		495			390			446			383
Diluted shares outstanding		497			516			512			509

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)


	Nine Months Ended September 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(275	)	$	(208	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization		206			207
Impairment and other charges		107			(1	)
(Earnings) losses from unconsolidated investments, net of cash distributions		(6	)		47
Risk-management activities		(70	)		(11	)
Gain on sale of assets, net		(3	)		(9	)
Deferred income taxes		(147	)		(284	)
Cumulative effect of change in accounting principle, net of tax (Note 1)		(1	)		—
Legal and settlement charges		14			110
Independence toll settlement costs		—			169
Sithe Subordinated Debt exchange charge		36			—
Debt conversion costs		249			—
Other		39			11
Changes in working capital:
Accounts receivable		353			(199	)
Inventory		12			(9	)
Prepayments and other assets		119			101
Accounts payable and accrued liabilities		(817	)		(113	)
Changes in non-current assets		11			(4	)
Changes in non-current liabilities		(7	)		15

Net cash used in operating activities		(180	)		(178	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(92	)		(132	)
Proceeds from asset sales, net		18			106
Business acquisitions, net of cash acquired		—			(120	)
Proceeds from exchange of unconsolidated investments, net of cash acquired (Note 2 and Note 3)		165			—
Decrease (increase) in restricted cash and restricted investments		125			(26	)
Other investing		(3	)		—

Net cash provided by (used in) investing activities		213			(172	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net		1,071			—
Repayments of long-term borrowings		(1,780	)		(40	)
Debt conversion costs		(249	)		—
Redemption of Series C Preferred (Note 8)		(400	)		—
Proceeds from issuance of capital stock		183			2
Dividends and other distributions, net		(17	)		(22	)
Other financing, net		(2	)		(13	)

Net cash used in financing activities		(1,194	)		(73	)

Net decrease in cash and cash equivalents		(1,161	)		(423	)
Cash and cash equivalents, beginning of period		1,549			628
Less: Cash classified as held for sale at end of period (Note 3)		—			(18	)

Cash and cash equivalents, end of period	$	388		$	187

Other non-cash financing activity:
Conversion of Convertible Subordinated Debentures due 2023 (Note 7)	$	225		$	—
Sithe Subordinated Debt exchange, net (Note 7)		122			—

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)


	Three Months Ended September 30,
	2006			2005
Net income (loss)	$	(69	)	$	29
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		38			(60	)
Reclassification of mark-to-market losses to earnings, net		2			50

Changes in cash flow hedging activities, net (net of tax benefit (expense) of ($23) and $5, respectively)		40			(10	)
Foreign currency translation adjustments		(1	)		5

Other comprehensive income (loss), net of tax		39			(5	)

Comprehensive income (loss)	$	(30	)	$	24


	Nine Months Ended September 30,
	2006			2005
Net loss	$	(275	)	$	(208	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		63			(81	)
Reclassification of mark-to-market (gains) losses to earnings, net		(10	)		61

Changes in cash flow hedging activities, net (net of tax benefit (expense) of ($31) and $12, respectively)		53			(20	)
Foreign currency translation adjustments		2			5

Other comprehensive income (loss), net of tax		55			(15	)

Comprehensive loss	$	(220	)	$	(223	)

See the notes to condensed consolidated financial statements.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Note 1—Accounting Policies

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. The year-end condensed consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2005, which we refer to as our “Form 10-K,” and our Form 10-K for the year ended December 31, 2005, as amended on May 1, 2006, which we refer to as our “Form 10-K/A.”

The unaudited condensed consolidated financial statements contained in this report include all material adjustments of a normal and recurring nature 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 (1) developing fair value assumptions, including estimates of future cash flows and discount rates, (2) analyzing tangible and intangible assets for possible impairment, (3) estimating the useful lives of our assets, (4) assessing future tax exposure and the realization of tax assets, (5) determining amounts to accrue for contingencies, guarantees and indemnifications and (6) estimating various factors used to value our pension assets and liabilities. Actual results could differ materially from any such estimates. Certain reclassifications have been made to prior period amounts in order to conform to current year presentation.

Asset Retirement Obligations. At December 31, 2005, our ARO liabilities were $48 million for our GEN-MW segment and $8 million for our GEN-NE segment. These AROs related to activities such as ash pond and landfill capping, dismantlement of power generation facilities, closure and post-closure costs, environmental testing, remediation, monitoring and land and equipment lease obligations. We continue to follow the provisions for disclosure and accounting for these AROs under SFAS No. 143, “Asset Retirement Obligations.” During the three and nine months ended September 30, 2006, we recorded additional AROs of zero and $5 million, respectively, no material AROs were settled, and revisions to estimated cash flows were not material. During the three and nine months ended September 30, 2006, our accretion expenses were approximately $2 million and $5 million, respectively, which are included in cost of sales on our unaudited condensed consolidated statements of operations. During the three and nine months ended September 30, 2005, there were no material additional AROs recorded or settled, and our accretion expenses and revisions to estimated cash flows were not material. At September 30, 2006, our ARO liabilities were $52 million for our GEN-MW segment and $14 million for our GEN-NE segment.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Accounting Principles Adopted

SFAS No. 123(R). In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation,” and provides alternative methods of transition (prospective, modified prospective or retroactive) for entities that voluntarily change to the fair value-based method of accounting for stock-based employee compensation in a fiscal year beginning before December 16, 2003. SFAS No. 148 requires prominent disclosure about the effects on reported net income of an entity’s accounting policy decisions with respect to stock-based employee compensation. We transitioned to a fair value-based method of accounting for stock-based compensation in the first quarter 2003 and used the prospective method of transition as described under SFAS No. 148.

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment,” which revises SFAS No. 123. SFAS No. 123(R) requires all companies to expense the fair value of employee stock options and other forms of stock-based compensation. We adopted SFAS No. 123(R) effective January 1, 2006, using the modified prospective transition method permitted under this pronouncement. Our cumulative effect of implementing this standard, which consists entirely of a forfeiture adjustment recorded in the first quarter 2006, was less than $1 million after tax. The application of SFAS 123(R) had no material impact on the unaudited condensed consolidated statements of cash flows and basic and diluted loss per share for the three and nine months ended September 30, 2006, compared to amounts that would have been reported pursuant to our previous accounting.

In November 2005, the FASB issued FSP No. 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards.” We have adopted the short-cut method to calculate the beginning balance of the APIC pool of the excess tax benefit, and to determine the subsequent impact on the APIC pool and unaudited condensed consolidated statements of cash flows of the tax effects of employee stock-based compensation awards that were outstanding upon our adoption of FAS 123(R). Utilizing the short-cut method, we have determined that we have a “Pool of Windfall” tax benefits that can be utilized to offset future shortfalls that may be incurred.

Under SFAS No. 148’s prospective method of transition, all stock options granted after January 1, 2003 are accounted for on a fair value basis. Options granted prior to January 1, 2003 continue to be accounted for using the intrinsic value method. Accordingly, for options granted prior to January 1, 2003, compensation expense is not reflected for employee stock options unless they were granted at an exercise price lower than market value on the grant date. We have granted in-the-money options in the past and have recognized compensation expense over the applicable vesting periods. No in-the-money stock options have been granted since 1999.

Had compensation cost for all stock options granted prior to 2003 been determined on a fair value basis consistent with SFAS No. 123(R), our net loss and basic and diluted loss per share amounts would not have been impacted for the three and nine months ended September 30, 2006 and 2005, respectively.

Please read Note 12—Employee Compensation, Savings and Pension Plans for further discussion of our share-based compensation.

SFAS No. 154. In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections—A Replacement of APB Opinion No. 20 and FASB Statement No. 3.” SFAS No. 154 changes the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. SFAS No. 154 requires retrospective

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

application to prior periods' financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The provisions of SFAS No. 154 are effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The adoption of this standard on January 1, 2006 did not have a material effect on our results of operations, financial position or cash flows.

Accounting Principles Not Yet Adopted

FIN No. 48. On July 12, 2006, the FASB issued FIN No. 48, “Accounting for Uncertainty in Income Taxes.” FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 prescribes a recognition threshold and measurement attributes for the financial statement recognition and measurement of an income tax position taken or expected to be taken in an income tax return. FIN No. 48 is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the impact of this statement on our financial statements.

SFAS No. 157. On September 15, 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” 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 for some entities the application of SFAS No. 157 will change current practice. 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. 158. On September 29, 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132 (R).” SFAS No. 158 requires employers to recognize the overfunded or underfunded status of a defined benefit or other postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position, and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. In addition, SFAS No. 158 requires employers to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. The provisions of SFAS 158 are effective for fiscal years ending after December 15, 2006 for employers with publicly traded equity securities and retrospective application is not permitted. The disclosure and recognition provisions are required to be adopted as of December 31, 2006. We are currently evaluating the impact of this statement on our financial statements. We estimate our pre-tax cumulative effect of implementing this standard, which will be reflected as a reduction to the ending balance of accumulated other comprehensive income, will be approximately $65 million upon adoption at December 31, 2006.

SAB 108. On September 13, 2006, the SEC released SAB 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” SAB 108 states that a registrant’s materiality evaluation of an identified unadjusted error should quantify the effects of the identified unadjusted error on each financial statement and related financial statement disclosure. SAB 108 also states that registrants electing not to restate prior periods should reflect the effects of initially applying SAB 108 in their annual financial statements covering the first fiscal year ending after November 15, 2006. We do not believe the impact of this SAB will have a material effect on our results of operations, financial position or cash flows.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Note 2—Business Combinations

LS Power. On September 14, 2006, we entered into a Plan of Merger, Contribution and Sale Agreement (the “Merger Agreement”) by and among Dynegy Inc., Dynegy Acquisition, Inc., a Delaware corporation (“New Dynegy”), Falcon Merger Sub Co., an Illinois corporation and a wholly owned subsidiary of New Dynegy (“Merger Sub”), LSP Gen Investors, L.P., LS Power Partners, L.P., LS Power Equity Partners PIE I, L.P., LS Power Associates, L.P., and LS Power Equity Partners, L.P. (collectively, the “LS Entities”), pursuant to which Merger Sub will be merged with and into us, as a result of which we and DHI will become wholly-owned subsidiaries of New Dynegy.

We will combine our current assets and operations with the LS Entities’ generation portfolio, and will acquire a 50 percent ownership interest in a development company that is currently controlled by the LS Entities. In the merger, each share of our Class A Common Stock and our Class B Common Stock will be converted into the right to receive one share of New Dynegy Class A Common Stock, par value $0.01 per share (“New Dynegy Class A Common Stock”).

In the transaction, the LS Entities will contribute certain interests in power generation assets to New Dynegy in exchange for (i) 340 million shares of New Dynegy Class B Common Stock, par value $0.01 per share (“New Dynegy Class B Common Stock” and, together with New Dynegy Class A Common Stock, the “New Dynegy Common Stock”), (ii) $100 million in cash and (iii) $275 million in aggregate principal amount of notes to be issued by New Dynegy.

Under the terms of the Merger Agreement, we and the LS Entities agreed not to (i) solicit proposals relating to alternative business combination transactions or (ii) subject to certain exceptions, enter into discussions or an agreement concerning or provide confidential information in connection with any proposals for alternative business combination transactions. The Merger Agreement provides certain termination rights to both us and the LS Entities, and further provides that, upon termination of the Merger Agreement under certain circumstances, (i) we may be required to pay the LS Entities or (ii) the LS Entities may be required to pay us, an aggregate termination fee of $100 million, as described in the Merger Agreement. The affirmative vote of two-thirds of the (i) issued and outstanding shares of our Class A Common Stock voting as a class, (ii) issued and outstanding shares of our Class B Common Stock voting as a class and (iii) issued and outstanding shares of our Common Stock voting together as a class is required to approve the merger. The consummation of the merger is subject to various other conditions, including: (i) the expiration or termination of applicable waiting periods under the HSR, (ii) approval from the FERC, (iii) registration of the shares of New Dynegy Class A Common Stock to be issued to our shareholders in the merger under the Securities Act of 1933, as amended (the “Securities Act”), (iv) approval from the New York State Public Service Commission and (v) satisfaction of certain other conditions. Assuming all necessary conditions are satisfied, which cannot be guaranteed, the transaction is expected to close in early 2007.

On September 14, 2006, the LS Entities and Kendall Power LLC (“Kendall Power”), a newly formed wholly owned subsidiary of Dynegy, entered into a Limited Liability Company Membership Interests and Stock Purchase Agreement (the “Kendall Agreement”) pursuant to which Kendall Power agreed to acquire all of the outstanding interests in LSP Kendall Holdings, LLC for $200 million in cash, as adjusted for certain changes in working capital. The closing of the Kendall Agreement will occur only if closing does not occur with respect to the transactions contemplated by the Merger Agreement. We have agreed to guarantee certain of Kendall Power’s obligations under the Kendall Agreement. The consummation of the Kendall Agreement is subject to various conditions, including: (i) the termination of the Merger Agreement; (ii) the expiration or termination of applicable waiting periods under

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

the HSR; and (iii) satisfaction of certain other conditions. Please read Note 10—Commitments and Contingencies—Guarantees and Indemnifications—Kendall Guarantee for further discussion.

Rocky Road. On March 31, 2006, contemporaneous with our sale of our interest in WCP (Generation) Holdings LLC (“West Coast Power”) (please read Note 3— Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—West Coast Power), we completed our acquisition of NRG’s 50% ownership interest in Rocky Road Power, LLC (“Rocky Road”), the entity that owns the Rocky Road power plant, a 364-megawatt natural gas-fired peaking facility near Chicago (of which we already owned 50%), for net proceeds of $165 million, net of cash acquired. As a result of the transaction, we became the primary beneficiary of the entity as provided under the guidance in FIN No. 46(R), “Consolidation of Variable Interest Entities an interpretation of ARB No. 51” and thus consolidated the assets and liabilities of the entity at March 31, 2006. Please read Note 6—Unconsolidated Investments—Variable Interest Entities for further discussion.

Note 3—Dispositions, Contract Terminations and Discontinued Operations

Dispositions and Contract Terminations

Rockingham. On May 21, 2006, we entered into an agreement with Duke Energy Carolinas, LLC (a subsidiary of Duke Energy) for the sale of our Rockingham facility, a peaking facility in North Carolina, which is included in our GEN-SO segment, for $195 million in cash. The transaction is expected to close in the fourth quarter 2006, subject to obtaining certain regulatory approvals and satisfaction of customary closing conditions. A portion of the proceeds from the sale will be used to repay our borrowings under the $150 million Term Loan, with the remaining proceeds used as an additional source of liquidity. Please read Note 7—Debt—Senior Secured Credit Facility for further discussion of the Term Loan.

Beginning in the second quarter 2006, Rockingham met the held for sale classification requirements of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” and is classified as such on our unaudited condensed consolidated balance sheet. The major classes of current and long-term assets and liabilities classified as assets and liabilities held for sale at September 30, 2006 are $194 million of Property, Plant and Equipment, Net, $1 million of Inventory and $1 million of Accrued liabilities and other current liabilities.

SFAS No. 144 also requires that long-lived assets not be depreciated or amortized while they are classified as held for sale. As such, we discontinued depreciation and amortization of Rockingham's property, plant and equipment during the second quarter 2006. Depreciation and amortization expense related to Rockingham totaled zero and $2 million in the three- and nine-month periods ended September 30, 2006, compared to $1 million and $4 million in the three- and nine-month periods ended September 30, 2005. In addition, SFAS No. 144 requires a loss to be recognized if assets held for sale less liabilities held for sale are in excess of fair value less costs to sell. Accordingly, we recorded pre-tax impairments of zero and $9 million in the three and nine months ended September 30, 2006, respectively, which are included in Impairment and other charges on our unaudited condensed consolidated statements of operations.

West Coast Power. On March 31, 2006, contemporaneous with our purchase of Rocky Road (please read Note 2—Business Combinations—Rocky Road), we completed our sale to NRG of our 50% ownership interest in West Coast Power, a joint venture between us and NRG which has ownership in the West Coast Power power plants in southern California totaling approximately 1,800 megawatts, for net proceeds of approximately $165 million, net of cash acquired. We did not recognize a material gain or loss on the sale. Pursuant to our divestiture of West

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Coast Power, we no longer maintain a significant variable interest in the entity as provided by the guidance in FIN No. 46(R). Please read Note 6—Unconsolidated Investments—Variable Interest Entities for further discussion.

Sterlington Contract Termination. In December 2005, we entered into an agreement to terminate the Sterlington long-term wholesale power tolling contract with Quachita Power LLC (“Quachita”), a joint venture of GE Energy Financial Services and Cogentrix Energy, Inc. Under the terms of the agreement, we paid Quachita approximately $370 million in March 2006 to eliminate approximately $449 million in capacity payment obligations through 2012 and avoid approximately $295 million in additional capacity payment obligations that would arise if Quachita exercised its option to extend the contract through 2017. We recognized a pre-tax charge of approximately $364 million ($229 million after-tax) in the fourth quarter 2005 related to this transaction.

Discontinued Operations

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. At closing, we received $2.35 billion in cash proceeds. As of September 30, 2006, we received a substantial majority of the balance of the sales proceeds from Targa, which represented our cash collateral related to DMSLP. Targa assumed responsibility for approximately $47 million in letters of credit provided by us for the benefit of DMSLP, and those letters of credit were all replaced by December 31, 2005.

Pursuant to SFAS No. 144, we are reporting the results of NGL’s operations as a discontinued operation. Accordingly, the results of operations of our NGL segment have been included in discontinued operations for all periods presented. EITF Issue 87-24, “Allocation of Interest to Discontinued Operations,” requires that interest expense on debt that was required to be repaid upon the sale of DMSLP should be reclassified to discontinued operations. Therefore, interest expense on our former term loan and our former generation facility debt was allocated to discontinued operations, as the respective debt instruments were paid upon the sale of DMSLP. Such interest expense, inclusive of amortization of debt issuance costs, totaled zero and $15 million for the three months ended September 30, 2006 and 2005, respectively, and zero and $40 million for the nine months ended September 30, 2006 and 2005, respectively.

Additionally, results from NGL’s operations include revenues and cost of sales arising from intersegment transactions, which ceased after the sale of DMSLP. NGL processed natural gas and sold this natural gas to CRM for resale to third parties. NGL also purchased natural gas from CRM and electricity from GEN. As the intersegment revenues and cost of sales included in NGL’s results were reclassified to discontinued operations, the effects of these intersegment transactions eliminated in consolidation, including the ultimate third-party settlement, previously recorded in other segments, were also reclassified to discontinued operations.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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

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


	U.K. CRM			DGC			NGL		Total
	(in millions)
Three Months Ended September 30, 2006
Income from operations before taxes	$	6		$	—		$	2	$	8
Income (loss) from operations after taxes		(2	)		—			4		2

Three Months Ended September 30, 2005
Revenues	$	—		$	—		$	1,193	$	1,193
Income (loss) from operations before taxes		(2	)		—			71		69
Income (loss) from operations after taxes		(4	)		(2	)		49		43

	U.K. CRM			DGC			NGL		Total
	(in millions)
Nine Months Ended September 30, 2006
Income from operations before taxes	$	5		$	—		$	3	$	8
Income (loss) from operations after taxes		(1	)		—			4		3

Nine Months Ended September 30, 2005
Revenues	$	—		$	—		$	3,172	$	3,172
Income from operations before taxes		3			—			152		155
Income (loss) from operations after taxes		(1	)		—			210		209

In the three and nine months ended September 30, 2006, we recognized approximately $6 million of pre-tax income associated with a receivable previously reserved that is now expected to be collected. In the nine months ended September 30, 2005, we recognized $3 million of pre-tax income primarily associated with U.K. CRM’s receipt of a third party bankruptcy settlement.

Note 4—Restructuring and Impairment Charges

Asset Impairment. At September 30, 2006, we tested the Bluegrass generation facility for impairment based on the FERC's recent approval and Louisville Gas and Electric’s (“LG&E”) completion of various compliance steps to allow it to withdraw from participation in the MISO market as of September 1, 2006. The Bluegrass facility has historically sold power into the MISO market through transmission provided by LG&E. This change will limit our ability or increase the cost to deliver power to the MISO market. After testing, we recorded a pre-tax impairment charge of $96 million ($61 million after-tax) in the GEN-MW segment. This charge is included in impairment and other charges in our unaudited condensed consolidated statement of operations. We determined the fair value of the facility using the expected present value technique.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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 implemented a restructuring plan (the “2005 Restructuring Plan”). The 2005 Restructuring Plan resulted in a reduction of approximately 40 positions and was complete by June 30, 2006. We recognized a pre-tax charge, primarily in our Other segment, of $11 million in the fourth quarter 2005. We recognized approximately zero and $2 million of charges in the three and nine months ended September 30, 2006, respectively, when transitional services were completed by certain affected employees. These charges related entirely to severance costs.

The following is a schedule of 2006 activity for the severance liabilities recorded in connection with this restructuring (in millions):


Balance at December 31, 2005	$	9
2006 adjustments to liability		2
Cash payments		(11	)

Balance at September 30, 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 2006 activity for the liabilities recorded in connection with this restructuring:


	Severance		Cancellation Fees and Operating Leases			Total
	(in millions)
Balance at December 31, 2005	$	3	$	16		$	19
Cash payments		—		(7	)		(7	)

Balance at September 30, 2006	$	3	$	9		$	12

Including the $2 million accrual for operating leases made in connection with the sale of DMSLP (for further information, please read Note 3—Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations— Natural Gas Liquids), we have an aggregate accrual of $11 million as of September 30, 2006, associated with operating leases. We expect this amount to be paid by the end of 2007, when the leases expire.

Note 5—Risk Management Activities and Accumulated Other Comprehensive Income

The nature of our business 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/A.

Cash Flow Hedges. We enter into financial derivative instruments that qualify and are designated 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 commodity prices we consider favorable under the circumstances. Interest rate swaps have been used to convert floating interest-rate obligations to fixed-rate obligations.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

During the three and nine months ended September 30, 2006, we recorded $3 million and $7 million, respectively, of income related to ineffectiveness from changes in fair value of cash flow hedge positions, and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. During the three and nine months ended September 30, 2005, we recorded $10 million and $4 million of income, respectively, related to ineffectiveness from changes in fair value of hedge positions, and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. During the three and nine months ended September 30, 2006 and 2005, no amounts were reclassified to earnings in connection with forecasted transactions that were probable of not occurring.

The balance in cash flow hedging activities, net at September 30, 2006, 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 $34 million are currently estimated to be reclassified into earnings over the 12-month period ending September 30, 2007. The actual amounts that will be reclassified to earnings over this period and beyond could vary materially from this estimated amount as a result of changes in market conditions and other factors.

Fair Value Hedges. We also enter into derivative instruments that qualify and are designated 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 and nine months ended September 30, 2006 and 2005, there was no ineffectiveness from changes in the fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. During the three and nine months ended September 30, 2006 and 2005, 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 September 30, 2006, we had no net investment hedges in place.

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


	September 30, 2006			December 31, 2005
	(in millions)
Cash flow hedging activities, net	$	51		$	(2	)
Foreign currency translation adjustment		26			24
Minimum pension liability		(18	)		(18	)

Accumulated other comprehensive income, net of tax	$	59		$	4

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Note 6—Unconsolidated Investments

A summary of our unconsolidated investments is as follows:


	September 30, 2006		December 31, 2005
	(in millions)
Equity affiliates:
GEN – MW	$	—	$	60
GEN – SO		7		210

Total unconsolidated investments	$	7	$	270

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


	Three Months Ended September 30,
	2006				2005
	Total		Equity Share		Total		Equity Share
	(in millions)
Revenues	$	16	$	8	$	162	$	70
Operating income		6		3		36		16
Net income		6		3		34		16

	Nine Months Ended September 30,
	2006				2005
	Total		Equity Share		Total		Equity Share
	(in millions)
Revenues	$	76	$	38	$	510	$	212
Operating income		16		8		64		27
Net income		13		6		63		27

Earnings from unconsolidated investments for the three months ended September 30, 2006 were $3 million. Earnings from unconsolidated investments of $16 million for the three months ended September 30, 2005 includes $1 million of earnings from NGL investments, which are included in income from discontinued operations on our unaudited condensed consolidated statements of operations. Earnings in 2005 were offset by an impairment of $8 million in our investment in West Coast Power.

Earnings from unconsolidated investments of $6 million for the nine months ended September 30, 2006, were offset by a $1 million impairment of our investment in Panama. Earnings from unconsolidated investments of $27 million for the nine months ended September 30, 2005, includes $5 million of earnings from NGL investments which are included in income from discontinued operations on our unaudited condensed consolidated statements of operations. Earnings in 2005 were offset by an impairment of $8 million in our investment in West Coast Power.

On May 15, 2006, we sold our interests in our power generating facility located in Panama. Net proceeds associated with the sale were approximately $3 million, and we did not recognize a gain or loss on the sale.

On March 31, 2006, we completed the sale to NRG of our 50% ownership interest in our unconsolidated investment in West Coast Power as well as our acquisition of NRG’s ownership interest in Rocky Road. As a result

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

of the transactions, we received cash proceeds of approximately $165 million, net of cash acquired, from NRG. Under the terms of this agreement, we did not recognize a material gain or loss on the sale of West Coast Power. For further discussion, please read Note 2—Business Combinations—Rocky Road and Note 3—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—West Coast Power.

Variable Interest Entities. In conjunction with our prior adoption of FIN No. 46(R), Rocky Road LLC was identified as a variable interest entity. At the time of adoption, we were not the primary beneficiary of, and therefore did not consolidate Rocky Road. We did not absorb a majority of the entity’s expected losses, nor receive a majority of the expected residual returns.

On March 31, 2006, we completed our acquisition of NRG’s 50% ownership interest in Rocky Road and the sale to NRG of our 50% ownership interest in West Coast Power. We paid approximately $45 million for NRG’s ownership interest in Rocky Road, including $5 million of cash on hand, and received approximately $205 million for our ownership interest in West Coast Power, resulting in the receipt of proceeds of approximately $165 million, net of cash acquired, from NRG. As we now own 100% of the outstanding equity interests in Rocky Road, we are subjected to a majority of the entity’s expected losses and expected residual returns, and are therefore considered the primary beneficiary of the entity. Thus, we consolidated the assets and liabilities of the entity at March 31, 2006, in accordance with the guidance provided in FIN No. 46(R), which requires that the assets and liabilities of the newly consolidated entity be measured and recorded at their fair values on the date we became the primary beneficiary. Those assets and liabilities primarily consisted of $9 million of working capital, a $29 million intangible asset related to a contract to provide capacity and energy, and $50 million of property, plant, and equipment at the facility’s location.

In conjunction with acquiring the remaining outstanding equity interest in Rocky Road, we divested our interest in West Coast Power. Based on that transaction, we no longer maintain a variable interest in West Coast Power. For further discussion, please read Note 2— Business Combinations—Rocky Road and Note 3—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—West Coast Power.

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 VIEs. Exelon is obligated to reimburse ExRes for certain 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. Exelon is not required to reimburse ExRes and the entities owning these facilities for lease payments or other costs not incurred in the ordinary course of business. 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).

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 September 30, 2006, the equipment leases have remaining terms from one to fifteen years and involve a maximum aggregate obligation of $120 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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

difference between (i) the facility’s fixed price revenues under the power purchase agreement and (ii) a percentage of the respective utility’s Public Utility Commission approved avoided costs associated with those power purchases plus accumulated interest on the balance. Each power purchase agreement calls for the hydroelectric facility to return to the utility the balance in the Tracking Account before the end of the facility’s life through decreased pricing under the respective power purchase agreement. If the decreased pricing does not reduce the tracking account to zero, a lump sum payment for the remainder of the balance will be due. Two of the four hydroelectric facilities are currently in the Tracking Account repayment period of the contract, whereby balances are repaid through decreased pricing. This pricing cannot be decreased below a level sufficient to allow the facilities to recover their operating costs. The remaining two facilities are anticipated to begin reducing the Tracking Accounts in 2006. The aggregate balance of the Tracking Accounts as of September 30, 2006, was approximately $309 million, and the obligations with respect to each Tracking Account are secured by the assets of the respective facility. 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.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Note 7—Debt

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


	September 30, 2006		December 31, 2005
	(in millions)
Dynegy Holdings Inc.
Term Loan, floating rate due 2012	$	150	$	—
Term Facility, floating rate due 2012		200		—
Senior Notes, 7.45% due 2006		—		22
Senior Notes, 6.875% due 2011		494		499
Senior Notes, 8.75% due 2012		488		491
Senior Unsecured Notes, 8.375% due 2016		1,047		—
Senior Debentures, 7.125% due 2018		173		175
Senior Debentures, 7.625% due 2026		173		174
Second Priority Senior Secured Notes, floating rate due 2008		—		225
Second Priority Senior Secured Notes, 9.875% due 2010		11		625
Second Priority Senior Secured Notes, 10.125% due 2013		—		900
Subordinated Debentures payable to affiliates, 8.316%, due 2027		200		200

Sithe Energies
Subordinated Debt, 7.0% due 2034		—		419
Senior Notes, 8.5% due 2007		39		57
Senior Notes, 9.0% due 2013		409		409

Dynegy Inc.
Convertible Subordinated Debentures, 4.75% due 2023		—		225

		3,384		4,421

Unamortized premium (discount) on debt, net		26		(122	)

		3,410		4,299
Less: Amounts due within one year, including non-cash amortization of basis adjustments		48		71

Total Long-Term Debt	$	3,362	$	4,228

Aggregate debt maturities for the remainder of 2006, the next four years and thereafter of the principal amounts of all long-term indebtedness as of September 30, 2006 are as follows:


	Total		2006		2007		2008		2009		2010		Thereafter
	(in millions)
Dynegy Holdings Inc.	$	2,929	$	2	$	—	$	—	$	—	$	11	$	2,916
Sithe Energies		481		22		44		44		57		62		252

Total	$	3,410	$	24	$	44	$	44	$	57	$	73	$	3,168

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Senior Secured Credit Facility. On April 19, 2006, we entered into a fourth amended and restated credit agreement (the “Fourth Senior Secured 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, Citigroup Global Markets Inc. and JPMorgan Securities Inc., as joint lead arrangers, and the other financial institutions parties thereto as lenders. The Fourth Senior Secured Credit Facility amends our former credit facility (last amended on March 6, 2006) by increasing the amount of the existing $400 million revolving credit facility to $470 million and adding a $200 million term letter of credit facility. The revolving facility, which is currently undrawn, is available for general corporate purposes and for letters of credit. The term facility has been fully drawn and the proceeds placed in a collateral account to support the issuance of letters of credit. Letters of credit issued under the former credit facility were continued under the Fourth Senior Secured Credit Facility.

The Fourth Senior Secured Credit Facility is secured by substantially all of the assets of DHI, as borrower, and certain of its subsidiaries, as subsidiary guarantors, and certain of our assets, as parent guarantor. The revolving credit facility portion of the Fourth Senior Secured Credit Facility matures April 19, 2009 and the term letter of credit portion matures on January 31, 2012. Borrowings for both the revolving and term portions under the Fourth Senior Secured Credit Facility bear interest at the relevant Eurodollar rate plus a ratings-based margin of 175 basis points or the relevant base rate plus a ratings-based margin of 75 basis points. Letters of credit can be issued under the revolving portion of the facility at a ratings-based rate of 175 basis points. An unused commitment fee of 50 basis points is payable on the unused portion of the revolving credit facility. The margin payable for borrowing, the rate payable for letters of credit and the unused commitment fee will decrease upon meeting specified improvements in Standard and Poor’s and Moody’s credit ratings for the facility.

The Fourth Senior Secured Credit Facility contains mandatory prepayment provisions associated with specified asset sales and dispositions (including as a result of casualty or condemnation) and the receipt of proceeds by DHI and certain of its subsidiaries of any permitted additional non-recourse indebtedness. Commencing in 2008 with respect to the fiscal year ending December 31, 2007, each year DHI will be required to apply toward the prepayment of the loans and the permanent reduction of the commitments under the revolving credit facility (or post cash collateral in lieu thereof) a portion of its excess cash flow as calculated under the Fourth Senior Secured Credit Facility for the prior fiscal year. This portion will be 50% initially and will fall to 25% when and if DHI’s leverage ratio is less than or equal to 3.50:1.00.

The Fourth Senior Secured Credit Facility 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 Fourth Senior Secured Credit Facility also contains certain financial covenants, including (1) a covenant (measured at the last day of the fiscal quarter as specified below) that requires DHI and certain of its subsidiaries to maintain a ratio of secured debt to adjusted EBITDA no greater than 3.5:1 (September 30, 2006); 3.0:1 (December 31, 2006); 2.75:1 (March 31, 2007); 2.5:1 (June 30, 2007); 2.25:1 (September 30, 2007) and 2.0:1 (December 31, 2007 and thereafter) and (2) a covenant that requires DHI and certain of its subsidiaries to maintain an interest coverage ratio as of the last day of the measurement periods ending September 30, 2006 of no less than 1.4:1; ending December 31, 2006 of no less than 1.50:1; ending March 31, June 30, September 30 and December 31, 2007 and March 31, 2008 of no less than 1.625:1, and ending June 30, 2008 and thereafter of no less than 1.75:1. We are in compliance with these covenants as of September 30, 2006.

On May 26, 2006, we closed a $150 million term loan (the “Term Loan”), of which $50 million was used to make a one-time cash dividend from DHI to Dynegy (the “DHI Dividend”) and the remainder used for working capital and general corporate purposes (please read Note 8—Related Party Transaction—Series C Convertible

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Preferred Stock). The Term Loan, which will be repaid with proceeds from the sale of Rockingham, was structured as a new tranche under the Fourth Senior Secured Credit Facility. The Term Loan will mature on the earlier of five business days after the consummation of the pending sale of the Rockingham facility or January 31, 2012. Please read Note 3—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Rockingham for further discussion of the sale.

Second Priority Senior Secured Notes. On April 12, 2006, we completed a cash tender offer and consent solicitation (the “SPN Tender Offer”), in which we purchased $151 million of our $225 million Second Priority Senior Secured Floating Rate Notes due 2008 (the “2008 Notes”), $614 million of our $625 million 9.875% Second Priority Senior Secured Notes due 2010 (the “2010 Notes”) and all $900 million of our 10.125% Second Priority Senior Secured Notes due 2013 (the “2013 Notes” and collectively with the “2008 Notes” and the “2010 Notes,” the “Second Priority Notes”). In connection with the SPN Tender Offer, we amended the indenture under which the Second Priority Notes were issued to eliminate or modify substantially all of the restrictive covenants, certain events of default and related provisions and release certain liens securing the obligations of DHI and the guarantors of the Second Priority Notes.

Total cash paid to repurchase the $1,664 million of Second Priority Notes, including consent fees and accrued interest, was $1,904 million. We recorded a charge of approximately $228 million in the second quarter 2006 associated with this transaction, of which $202 million is included in debt conversion costs and $26 million of acceleration of amortization of financing costs and write-offs of discounts and premiums is included in interest expense on our unaudited condensed consolidated statements of operations.

On July 15, 2006, we redeemed the remaining $74 million of our 2008 Notes, at a redemption price of 103% of the principal amount, plus accrued and unpaid interest to the redemption date. The interest rate on the 2008 Notes was based on three-month LIBOR plus 650 basis points. We recorded a charge of approximately $2 million in the third quarter 2006 associated with this transaction, which is included in debt conversion costs on our unaudited condensed consolidated statements of operations. The remaining outstanding 2010 Notes are redeemable at our option on or after July 15, 2007 in accordance with the terms of the indenture governing the Second Priority Notes.

Senior Unsecured Notes. On April 12, 2006, DHI issued $750 million aggregate principal amount of our 8.375% Senior Unsecured Notes due 2016 (the “New Senior Notes”) in a private offering (the “Senior Notes Offering”). The New Senior Notes are not redeemable at our option prior to maturity. The New Senior Notes are our senior unsecured obligations and rank equal in right of payment to all of our existing and future senior unsecured indebtedness, and are senior to all of our existing and any of our future subordinated indebtedness. We have not guaranteed the New Senior Notes, and the assets and operations that we own through subsidiaries other than DHI (principally our Independence plant) do not support the New Senior Notes. The proceeds from the Senior Notes Offering, together with cash on hand, were used to fund the SPN Tender Offer discussed above. On September 14, 2006, DHI exchanged the New Senior Notes for a new issue of substantially identical notes registered under the Securities Act of 1933. Please read “Senior Unsecured Notes Exchange Offer” below for further information.

Convertible Subordinated Debentures due 2023. On May 15, 2006, we converted all $225 million of our outstanding 4.75% Convertible Subordinated Debentures due 2023 into shares of our Class A common stock (the “Convertible Debenture Exchange”). In this transaction, we issued an aggregate of 54,598,369 shares of our Class A common stock and paid the debenture holders an aggregate of approximately $47 million in premiums and accrued and unpaid interest using cash on hand. We recorded a charge of approximately $44 million in the second quarter 2006 associated with this transaction, which is included in debt conversion costs on our unaudited condensed consolidated statements of operations.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Sithe Subordinated Debt Exchange. On July 21, 2006, DHI executed and consummated an exchange agreement (the “Exchange Agreement”), by and among DHI and RCP Debt, LLC and RCMF Debt, LLC (together, the “Reservoir Entities”). Pursuant to the Exchange Agreement, the Reservoir Entities exchanged approximately $419 million principal amount of the subordinated debt of Independence, together with all claims for accrued and unpaid interest thereon and all other rights and all obligations of the Reservoir Entities under the agreement pursuant to which the subordinated debt was issued (together, the “Sithe Debt”), for approximately $297 million principal amount of DHI’s 8.375% Senior Unsecured Notes due 2016 (the “Additional Notes”). The Additional Notes have terms and conditions identical to, and are fungible for trading and other purposes with, the $750 million aggregate principal amount of the New Senior Notes issued on April 12, 2006. On September 14, 2006, DHI exchanged the Additional Notes for a new issue of substantially identical notes registered under the Securities Act of 1933. We recorded a charge of approximately $36 million in the third quarter of 2006 associated with this transaction, which is included in interest expense on our unaudited condensed consolidated statements of operations. Please read “Senior Unsecured Notes Exchange Offer” below for further information.

Senior Unsecured Notes Exchange Offer. On September 14, 2006, pursuant to the registration rights agreements pertaining to the New Senior Notes and the Additional Notes, we completed an exchange offer of $1,047 million aggregate principal amount of DHI’s 8.375% Senior Unsecured Notes due 2016 registered under the Securities Act of 1933 for all $1,047 million aggregate principal amount of DHI’s outstanding 8.375% Senior Unsecured Notes due 2016.

Note 8—Related Party Transaction

Series C Convertible Preferred Stock. As discussed in Note 15—Redeemable Preferred Securities beginning on page F-55 of our Form 10-K/A, in August 2003, we issued to CUSA 8 million shares of our Series C Convertible Preferred Stock due 2033, which we refer to as our “Series C Preferred.” We accrued dividends on our Series C Preferred at a rate of 5.5% of the liquidation value per annum. We made a semi-annual dividend payment of $11 million in February 2006. On May 26, 2006, we redeemed all of the outstanding shares of our Series C Preferred, which were held by CUSA. In order to redeem the Series C Preferred, we paid CUSA $400 million in cash, plus accrued and unpaid dividends totaling approximately $6.3 million. We used approximately $178 million in net proceeds from an equity offering of 40.25 million shares of our Class A common stock that closed on the same day (includes net proceeds of $23 million from the underwriters' exercise of their option to purchase an additional 5.25 million shares), with the balance funded from cash on hand and the DHI Dividend. The redemption of the Series C Preferred eliminated the associated $22 million annual preferred dividend and reduced the number of diluted shares of our common stock outstanding.

Note 9—Loss Per Share

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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
	(in millions, except per share amounts)
Loss from continuing operations	$	(71	)	$	(14	)	$	(279	)	$	(417	)
Preferred stock dividends		—			(6	)		(9	)		(17	)

Loss from continuing operations for basic loss per share		(71	)		(20	)		(288	)		(434	)
Effect of dilutive securities:
Interest on convertible subordinated debentures		—			2			3			5
Dividends on Series C Preferred		—			6			9			17

Loss from continuing operations for diluted loss per share	$	(71	)	$	(12	)	$	(276	)	$	(412	)

Basic weighted-average shares		495			390			446			383
Effect of dilutive securities:
Stock options		2			2			2			2
Convertible subordinated debentures		—			55			27			55
Series C Preferred		—			69			37			69

Diluted weighted-average shares		497			516			512			509

Loss per share from continuing operations:
Basic	$	(0.14	)	$	(0.05	)	$	(0.65	)	$	(1.13	)

Diluted (1)	$	(0.14	)	$	(0.05	)	$	(0.65	)	$	(1.13	)

(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 and nine months ended September 30, 2006 and 2005.

Note 10—Commitments and Contingencies

Set forth below is a description of our material legal proceedings. In addition to the matters described below, we are party to legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not have a material adverse effect on our financial condition, results of operations or cash flows.

We record reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable under SFAS No. 5, “Accounting for Contingencies.” For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Please read Note 2—Accounting Policies—Contingencies, Commitments, Guarantees and Indemnifications beginning on page F-17 of our Form 10-K/A for further discussion of our reserve policies. Environmental reserves do not reflect management’s assessment of the insurance coverage that may be applicable to the matters at issue, whereas litigation reserves do reflect such potential coverage. We cannot make any assurances

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

that the amount of any reserves or potential insurance coverage will be sufficient to cover the cash obligations we might incur as a result of litigation or regulatory proceedings, payment of which could be material.

With respect to some of the items listed below, management has determined that a loss is not probable or that any such loss, to the extent probable, is not reasonably estimable. In some cases, management is not able to predict with any degree of certainty the range of possible loss that could be incurred. Notwithstanding these facts, management has assessed these matters based on current information and made a judgment concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may, as a result of facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.

Summary of Recent Developments. As described in greater detail below, the following significant developments involving our material legal proceedings occurred since the second quarter:

•

In October 2006, we entered into a settlement agreement with Enron and certain of its subsidiaries to resolve claims arising from or relating to the entry of the Master Netting Setoff Security Agreement in 2001. DHI paid Enron $44 million to resolve such claims and retained the right to pursue amounts owed by Enron Capital and Trade Resources Limited to Dynegy UK Limited.

•

In August 2006, we and our former affiliate, West Coast Power, entered into an agreement to settle class action claims by California purchasers and certain California natural gas resellers and co-generators alleging price manipulation and false reporting of natural gas trades. We agreed to pay approximately $32 million in total to settle these claims; however, the settlement does not include similar cases filed by individual plaintiffs, which we continue to defend vigorously. In September 2006, the San Diego state court granted preliminary approval of the settlement of claims by the California purchasers and we expect Plaintiffs to submit the settlement of claims by California natural gas resellers and co-generators to the Nevada federal court in the fourth quarter 2006.

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

Enron Trade Credit Litigation. On October 5, 2006, we, DHI and certain of our affiliates and subsidiaries (collectively the “Dynegy Parties”) entered into a Settlement Agreement and Mutual General Release (the “Settlement Agreement”) with Enron Corp. and certain of its subsidiaries and affiliates (collectively the “Enron Parties”). The Settlement Agreement provides for the settlement of all claims by either the Dynegy Parties or the Enron Parties against the others arising from or relating to the Master Netting Setoff and Security Agreement (the “MNSSA”) dated November 8, 2001. The MNSSA allowed certain amounts owed from the Dynegy Parties to the Enron Parties to be set off against other amounts owed from the Enron Parties to the Dynegy Parties as a result of the termination of commercial transactions between the parties.

On October 26, 2006 the settlement received final approval from the Bankruptcy Court. Under the Settlement Agreement, the Dynegy Parties and the Enron Parties agreed to the following in exchange for the final resolution and mutual release of all claims asserted by any of the parties in the adversary and arbitration proceedings and an action in Canada relating to an Enron Corp. Canadian subsidiary:

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

•

A settlement payment by DHI of $44 million, payable on the second business day after final Bankruptcy Court approval.

•

Through our subsidiary Dynegy UK Limited, we retain the right to pursue claims filed against Enron Capital and Trade Resources Limited (“ECTRL”) in ECTRL’s administration proceedings in the United Kingdom for amounts owed by ECTRL under or in connection with certain underlying commodities contracts.

In accordance with the payment terms, Dynegy funded the settlement on October 30, 2006. The Settlement Agreement further provides for a mutual release of any other claims that exist or could exist between the Dynegy Parties and the Enron Parties through the date payment is made. Neither the Dynegy Parties nor the Enron Parties admit any liability in connection with the Settlement Agreement. We recorded approximately $20 million and $28 million in pre-tax charges related to the settlement and associated legal expenses in the three and nine months ended September 30, 2006, respectively. We recognized approximately $4 million of pre-tax charges related to the settlement and associated legal expenses in the three and nine months ended September 30, 2005. These charges are recorded as general and administrative expenses on our unaudited condensed consolidated statements of operations.

Gas Index Pricing Litigation. We 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 and Tennessee. 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 not expected until 2007.

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. 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. In September 2006, the San Diego state court granted preliminary approval of the settlement of claims by the California purchasers. A motion to approve the re-seller and co-generator settlement is expected in the fourth quarter 2006. The 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. We have recorded reserves that we consider reasonable in connection with these matters.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

In connection with the sale of our interest in West Coast Power to NRG (which closed on March 31, 2006), we, NRG and NRG West Coast 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 natural 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.

California Market Litigation. We and various other power generators and marketers are defendants in lawsuits alleging rate and market manipulation in California’s wholesale electricity market during the California energy crisis several years ago. The complaints generally allege unfair, unlawful and deceptive trade practices in violation of the California Unfair Business Practices Act and seek injunctive relief, restitution and unspecified actual and treble damages. In addition, certain cases include allegations relating to the validity of the contracts between power generators, including West Coast Power, and the California Department of Water Resources (“CDWR”). A significant majority of these cases were dismissed on grounds of federal preemption. A motion to dismiss one remaining action on similar grounds is pending in federal court. Certain actions, however, in which plaintiffs have not exhausted the appellate process remain pending in either the California appellate court or the U.S. Court of Appeals for the Ninth Circuit.

In October 2004, an independent electric services provider in California filed suit against us and several other defendants alleging claims similar to those above and that it was forced out of business by the defendants’ conduct. Plaintiff seeks $5 million in compensatory damages, as well as treble damages. In June 2005, the case was removed to federal court where it remains pending.

Finally, there is a pending appeal in the Ninth Circuit Court of Appeals challenging a FERC Order affirming the validity of the former West Coast Power – CDWR long term contract. We are currently awaiting a ruling on this appeal and cannot predict its outcome.

We believe that we have meritorious defenses to these claims 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.

In connection with the sale of our interest in West Coast Power to NRG on March 31, 2006, we, NRG and NRG West Coast 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 power 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 further provides that NRG will manage the CDWR appeal described above and indemnify us for any resulting losses, subject to certain conditions. Please read “Guarantees and Indemnifications—WCP Indemnities” below.

ERISA/Illinois Power 401(k) Litigation. In January 2005, three DMG union employees who are participants in the DMG 401(k) Savings Plan for Employees Covered Under a Collective Bargaining Agreement (formerly known as the Illinois Power Company Incentive Savings Plan For Employees Covered Under a Collective Bargaining Agreement), which we refer to as the “DMG 401(k) Plan,” purporting to represent all DMG and Illinois

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Power employees who held Dynegy common stock through the DMG 401(k) Plan during the period from February 2000 through the present, filed a lawsuit in federal court in the Southern District of Illinois against us, Illinois Power, DMG and several individual defendants. The complaint alleges violations of ERISA in connection with the DMG 401(k) Plan that are similar to the claims made in the Dynegy Inc. ERISA litigation we settled in December 2004, including claims that certain of our former officers (who are past members of our Benefit Plans Committee) breached their fiduciary duties to plan participants and beneficiaries in connection with the plan’s investment in Dynegy common stock—in particular with respect to our financial statements, Project Alpha, alleged round trip trades and natural gas price index reporting. The lawsuit seeks unspecified damages for the losses to the plan, as well as attorney’s fees and other costs. In March 2006, an amended complaint was filed naming additional former officers and employees as defendants and amending the fraud claims. In June 2006, the court granted our motion to dismiss plaintiffs’ fraud claims for failing to plead those claims with particularity. The remaining counts in the March 2006 amended complaint remain pending.

Additionally, in September 2005, two former Illinois Power salaried employees who were participants in the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for salaried employees (formerly known as the Illinois Power Incentive Savings Plan), which we refer to as the “DMG Salaried Plan,” purporting to represent all DMG Salaried Plan participants who held Dynegy common stock through the DMG Salaried Plan during the period from January 1, 2002, through January 30, 2003, filed a lawsuit in federal court in the Southern District of Texas against us and several individual defendants. The complaint alleges violations of ERISA in connection with the DMG Salaried Plan that are similar to the claims made in the ERISA litigation referenced in the preceding paragraph. The lawsuit seeks unspecified damages for the losses to the plan, as well as attorney’s fees and other costs. In December 2005, we filed a motion to dismiss the complaint, in response to which plaintiffs’ counsel filed a second putative class action on behalf of three alleged plan participants that is materially identical to the original action. In March 2006, the original action was dismissed by the court with prejudice based on lack of standing and lack of subject matter jurisdiction, and the plaintiffs in that matter have appealed that dismissal. The second putative class action relating to the DMG Salaried Plan remains pending at the class discovery stage.

We believe that we have meritorious defenses to plaintiffs’ claims in these lawsuits and are vigorously defending against them. Although it is not possible to predict with certainty whether we will incur any liability in connection with these lawsuits, we do not believe that any liability we might incur as a result of these lawsuits would have a material adverse effect on our financial condition, results of operations or cash flows.

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.

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 best technology available for minimizing adverse environmental impacts. The requirements of the Draft SPDES Permit already exceed the best technology available requirements of the EPA regulations applicable to existing facilities. 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.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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.

Danskammer State Pollutant Discharge Elimination System Permit. In January 2005, the 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 for minimizing adverse environmental impacts. The requirements of the Draft SPDES Permit already exceed the best technology available requirements of the EPA regulations applicable to existing facilities.

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 in excess of those resulting from the best technology available requirements of the EPA regulations applicable to existing facilities. In July 2006, two of the petitioners filed suit in the Supreme Court of the State of New York, Westchester County seeking to vacate the Deputy Commissioner’s decision and the revised Danskammer SPDES Permit. 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.

Stumpf Litigation. We and two former subsidiaries are defendants in a lawsuit filed in New York by Stumpf AG and two of its affiliates stemming from the closure of our former Austrian subsidiary’s Vienna telecommunications office in the spring of 2001. The plaintiffs are seeking approximately $30 million in compensatory and unspecified punitive damages, alleging breach of contract, tortious interference and other similar claims primarily relating to the termination of real property leases to which our former Austrian subsidiary was a party. These claims are based on similar lawsuits filed in Austria against our former Austrian subsidiary, which was sold to a third party in January 2003. All of these lawsuits pending in Austria have been stayed. This former subsidiary is in liquidation and one of its liquidators admitted, for purposes of the liquidation, the plaintiffs’ claims in the amount of approximately $30 million. In December 2004, the plaintiffs filed a motion for partial summary judgment on issues of liability which was denied by the trial court in December 2005. Plaintiffs appealed the decision to the New York Appellate Division, which affirmed the trial court’s ruling in August 2006. Shortly thereafter, Plaintiffs sought re-argument from the intermediate court or permission to appeal to the New York Court of Appeals.

We continue to oppose these claims and believe we have meritorious defenses. Although it is not possible to predict with certainty whether we will incur any liability in connection with these lawsuits, we do not believe that any liability we might incur as a result of these lawsuits would have a material adverse effect on our financial condition, results of operations or cash flows. We have recorded a reserve that we consider reasonable relating to this matter.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

LS Power-Kendall Arbitration. In May 2005, DPM initiated an arbitration proceeding against LS Power-Kendall Energy, LLC. Due to the pending transaction between us and the LS Entities, the parties have agreed to dismiss the arbitration proceeding without prejudice.

Stand Energy Litigation (formerly Atlantigas Corp. Litigation). In October 2004, we were named as a defendant in a West Virginia federal court class action lawsuit alleging that interstate pipelines provided preferential storage and transportation services to their own unregulated marketing affiliates in return for a percentage of the profits. Plaintiffs contend that such conduct violated applicable FERC regulations and federal and state antitrust laws, and constituted common law tortious interference with contractual and business relations. In addition, the complaint claims the defendants conspired with the other market participants to receive preferential natural gas storage and transportation services at off-tariff prices. The complaint seeks unspecified compensatory and punitive damages. The parties are actively engaged in discovery.

We continue to analyze plaintiffs’ claims and intend to vigorously defend against them. We cannot predict with certainty whether we will incur any liability in connection with this lawsuit; however, we believe that any liability incurred as a result of this litigation would not have a material adverse effect on our financial condition, results of operations or cash flows.

Severance Arbitration. Our former CFO, Rob Doty, filed for arbitration pursuant to the terms of his employment/severance agreement following his departure from the Company in 2002. Mr. Doty seeks payment of up to approximately $3.4 million and additional amounts related to long-term incentive payments allegedly contemplated by his agreement. Mr. Doty’s agreement is subject to interpretation, and we maintain that any amount owed is lower than the amount sought. We have recorded a severance accrual that we consider reasonable relating to this proceeding.

U.S. Attorney—Texas. We are continuing to cooperate fully with the U.S. Attorney’s office in Houston in its ongoing investigation of the industry’s natural gas trade reporting practices.

In January 2003, one of our former natural gas traders was indicted on three counts of knowingly causing the transmission of false trade reports used to calculate the index price of natural gas and four counts of wire fraud. A second superseding indictment was returned in March 2006, recharging the original violations and adding additional charges. Following a five-week trial, in August 2006 the jury returned a verdict finding the former employee guilty on seven counts of wire fraud and not guilty on two counts of wire fraud and three counts of false reporting. The jury was unable to reach a verdict on the remaining counts, including one count of conspiracy and ten counts of false reporting. On November 3, 2006, the Court conducted a hearing on the Defendant’s motion for a new trial or acquittal and took the parties’ arguments under advisement.

We do not believe this investigation will have a material adverse effect on our financial condition, results of operations or cash flows.

U.S. Attorney—California. In November 2002, the U.S. Attorney’s office in the Northern District of California issued a Grand Jury subpoena requesting information related to our activities in the California energy markets. We continue to cooperate fully with the U.S. Attorney’s office in its investigation of these matters, including production of substantial documents responsive to the subpoena and other requests for information.

Department of Labor Investigation. In August 2002, the U.S. Department of Labor commenced an official investigation pursuant to Section 504 of ERISA with respect to the benefit plans we maintain and our ERISA affiliates. We cooperated with the Department of Labor throughout this investigation, which focused on a review of

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

plan documentation, plan reporting and disclosure, plan record keeping, plan investments and investment options, plan fiduciaries and third party service providers, plan contributions and other operational aspects of the plans. In February 2005, we received a letter from the Department of Labor indicating that, as a result of our December 2004 settlement in the Dynegy Inc. ERISA litigation, it intended to take no further action with respect to its investigation of the Dynegy Inc. 401(k) Plan. However, its investigation is ongoing as it relates to the Illinois Power 401(k) Plans and the litigation relating to those plans described above.

Guarantees and Indemnifications

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 losses related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such losses could be significant, in most cases management considers the probability of loss to be extremely remote.

Kendall Guarantee. On September 14, 2006, the LS Entities and Kendall Power entered into the Kendall Agreement pursuant to which Kendall Power agreed to acquire all of the outstanding interests in LSP Kendall Holdings, LLC for $200 million in cash, as adjusted for certain changes in working capital. The closing of the Kendall Agreement will occur only if closing does not occur with respect to the transactions contemplated by the Merger Agreement. We have agreed to guarantee certain of Kendall Power’s obligations under the Kendall Agreement. The consummation of the Kendall Agreement is subject to various conditions, including: (i) the termination of the Merger Agreement; (ii) the expiration or termination of applicable waiting periods under the HSR; and (iii) satisfaction of certain other conditions. Please read Note 2—Business Combinations—LS Power for further discussion.

WCP Indemnities. In connection with our sale to NRG of our 50% ownership interest in West Coast Power (please read Note 3—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—West Coast Power for further discussion), we entered into an agreement with NRG in which we agreed how certain litigation would be managed and allocated between the parties responsible for any loss suffered by the parties as a result of such litigation. Please read California Market Litigation and Gas Index Pricing Litigation above for further discussion.

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 also indemnified Targa for certain tax matters arising from periods prior to our sale of DMSLP. While we have incurred no expense in connection with this indemnification, we have recorded an accrual, which we deem to be the fair value of this indemnification as of September 30, 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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, the amount of our indemnity is limited to 50% of any such losses. Illinois Power had not sustained any material losses in recent years and, at the time of the sale of Illinois Power to Ameren, our management considered the probability of any material loss under this indemnity remote. Consequently, the value of the indemnification was initially deemed to be insignificant. In the second quarter 2005, however, the ICC rejected an Administrative Law Judge’s proposed order and entered an order in one of the proceedings covered by the scope of this indemnification that disallowed items relating to one of Illinois Power’s natural gas storage fields, resulting in a negative revenue requirement impact to Ameren. In July 2005, we made a payment of $8 million to Ameren in settlement of Ameren’s indemnification claims with respect to this ICC order. Although at that time the ICC had not issued an order in any other cases, there were other cases in which it was then probable, based on this recent action by the ICC, that some loss would occur and a liability could be reasonably estimated. As a result, in the second quarter 2005, we recognized a pre-tax charge of $12 million, which is included in general and administrative expense on our condensed consolidated statements of operations. In late June 2006, the Administrative Law Judge in one of the ongoing cases issued a Proposed Order adopting the disallowances recommended by the ICC Staff in that case. In September 2006, the ICC issued an Order that adopted the findings set forth by the Administrative Law Judge in the Proposed Order. 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 considers the probability of an adverse outcome remote.

Constellation Guarantee. During 2004, as part of entering into a “back-to-back” power purchase agreement with Constellation Energy Commodities Group, Inc. (“Constellation”), under which Constellation effectively received our rights to purchase approximately 570 MW of capacity and energy arising under our Kendall tolling contract, we guaranteed Constellation an aggregate $4 million in reactive power revenues over the four-year term of the power purchase agreement. Upon entering into this contract, we established a liability of less than $1 million reflecting the fair value of this guarantee. During the year ended December 31, 2005, we increased the liability by approximately $1 million, as it became probable that we will be obligated to make a greater payment to Constellation under the guarantee. Based on our continued evaluation and events which have occurred to date, as of September 30, 2006, we decreased the reserve to approximately $1 million.

Northern Natural and Other Indemnities. During 2003, as part of our sale of NNG, 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 NNG, 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, Indian Basin and PESA. We carry reserves for existing environmental, tax and employee liabilities and have incurred no other expense relating to these indemnities.

Black Mountain Guarantee. 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

that may be due to the power purchaser under a mechanism designed to protect it from early termination of the agreement. At September 30, 2006, if an event of default 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 $60 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 11—Regulatory Issues

We are subject to regulation by various federal, state, local and foreign agencies, including extensive rules and regulations governing transportation, transmission and sale of energy commodities as well as the discharge of materials into the environment or otherwise relating to environmental protection. Compliance with these regulations requires general and administrative, capital and operating expenditures including those related to monitoring, pollution control equipment, emission fees and permitting at various operating facilities and remediation obligations. In addition, the United States Congress has before it a number of bills that could impact regulations or impose new regulations applicable to us and our subsidiaries. We cannot predict the outcome of these bills or other regulatory developments or the effects that they might have on our business.

Energy Policy Act of 2005. The Energy Policy Act of 2005 (“EPACT”) was signed into law on August 8, 2005. Title XII of EPACT (Electricity) deals with various matters impacting the power industry, including reliability of the bulk power system; transmission congestion, and transmission structure siting and modernization; the repeal of PUHCA; and prohibition of energy market manipulation, with enhanced FERC authority to prohibit market manipulation, including enhanced penalty authority. FERC has implemented and is considering a number of related regulations to implement EPACT that may impact, among other things, requirements for reliability, Qualified Facilities, transmission information availability, transmission congestion, security constrained dispatch, energy market transparency, energy market manipulation and behavioral rules.

Illinois Resource Procurement Auction. In January 2006, the ICC approved a resource 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. The ICC did initiate an investigation into the Hourly Auction segment and we have intervened in that proceeding.

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 Supplier Forward Contracts. Numerous parties have appealed various aspects of the ICC Orders approving the auctions to the state intermediate appellate courts. The Illinois Attorney General has also filed for direct review by the state Supreme Court and a stay of the ICC Orders pending that review, which was denied. The appellate court cases have been consolidated and are in the briefing stage; we anticipate a ruling sometime next 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 in the fourth quarter 2006 either in its veto session or via a special session if called by the Governor.

Clean Air Mercury Rule. In March 2005, the Administrator of the EPA signed a final Clean Air Mercury Rule (“CAMR”) that will require mercury emission reductions to be achieved from existing coal-fired electric generating units. This rule requires all states to adopt either the EPA rule, or a state rule meeting the minimum requirements as outlined in CAMR. The Illinois EPA has proposed a state-specific rule (the Illinois Mercury Rule) that would require larger percentage reductions in mercury emissions on a significantly shorter timeframe than the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

CAMR would require. We, along with most other owners of Illinois coal-fired electric generating units, opposed the Illinois Mercury Rule in proceedings before the Illinois Pollution Control Board (“IPCB”). The first hearing was held in June 2006 and the second hearing began on August 14, 2006. The Illinois EPA and Ameren filed a Joint Statement with the IPCB in late July supporting a Multi-Pollutant Alternative to the Illinois Mercury Rule that significantly extends the schedule for compliance with the proposed new mercury standard while adding new requirements for the control of sulfur dioxide and nitrogen oxides emissions. DMG filed a Joint Statement with the Illinois EPA on August 21, 2006 supporting a Multi-Pollutant alternative to the Illinois Mercury Rule. On November 2, 2006 the IPCB adopted the Illinois Mercury Rule including the Multi-Pollutant Alternative and transmitted it to the Joint Committee on Administrative Rules ("JCAR"), which will ensure the proposed rule is consistent with state law and the views of the legislature. The extended schedule for compliance will only become effective if the JCAR approves the overall Illinois Mercury Rule, including the Multi-Pollutant Alternative, which we believe will be within the next 90 days. Other industry participants are actively opposing this proposal. It is possible that the rule could pass without the Multi-Pollutant Alternative, in which case we would be subject to the schedule and mercury reductions in the original Illinois Mercury Rule.

In May 2006, the Governor of New York announced plans to regulate mercury emissions from coal-fired power plants by reducing emissions by approximately 50% by 2010 and 90% by 2015. NYSDEC issued a proposed rule in July 2006. The proposed rule would establish a 72 lb/yr mercury emission limit for the Danskammer generating units beginning in January 2010. Beginning in January 2015, the rule would impose an emission rate limit of 0.6 pounds of mercury per trillion Btu for all affected generating units. The proposed rule would not allow trading of mercury emission allowances.

Various state legislative and regulatory bodies may be considering other legislation or rules that could impact current regulations or impose new regulations applicable to us and our subsidiaries. We cannot predict the outcome of these legislative and other regulatory developments, or the effects that they might have on our business.

FERC Market-Based Rate Authority. FERC-approved market-based rate authority allows those granted such authority to sell power at negotiated rates through the bilateral market or within an organized energy market, conditioned on periodic re-review. In June 2005, FERC issued an order accepting the updated market power analyses submitted by Sithe Energies and Dynegy. Accordingly, these entities have continuously had market-based rate authority. Our next triennial market power analysis is currently due in June 2008. However, FERC is considering adoption of a regional approach for the submission of triennial reviews that could alter this due date.

We are also subject to FERC’s new regulations prohibiting market manipulation implemented pursuant to the EPACT. In 2003, FERC promulgated market behavior rules prohibiting manipulation in the wholesale electricity and natural gas markets subject to FERC’s jurisdiction. The market behavior rules, which emerged from FERC’s consideration of market manipulation in the Western markets, are incorporated in the tariffs of the various Dynegy entities with market based rates for wholesale power. FERC rescinded the other two market behavior rules. The new regulations apply to sales in organized and bilateral markets and spot markets, as well as long-term sales (as well as to the wholesale sale of natural gas under a blanket marketing certificate). The remedies for violating the rules could include disgorgement of unjust profits or suspension or revocation of the authority to sell at market-based rates and penalties. The extent to which these regulations will affect us is uncertain. However, we believe that we are currently in compliance.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Note 12—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-73 of our Form 10-K/A.

Share-Based Compensation. Our share-based payments primarily consist of stock options and restricted stock awards. For stock options, we determine the fair value of each stock option at the grant date using a Black-Scholes model, with the following weighted-average assumptions used for grants for the nine months ended September 30, 2006 and 2005:


	Nine Months Ended September 30,
	2006	2005
Dividends	—	—
Expected volatility (historical)	48.8%	84.1%
Risk-free interest rate	5.1%	4.2%
Expected option life	6 Years	10 Years

The expected volatility was calculated based on a ten-year historical volatility of our stock price in 2005 and beginning in first quarter 2006, we used a three-year historical volatility. The risk-free interest rate was calculated based upon observed interest rates appropriate for the term of our employee stock options. Currently, we calculate the expected option life using the simplified methodology suggested by SAB 107, “Share-Based Payment.” For restricted stock awards, we consider the fair value to be the closing price of the stock on the grant date. We recognize the fair value of our share-based payments over the vesting periods of the awards, which is typically a three-year service period.

We have nine stock option plans, all of which contain authorized shares of our Class A common stock. Each option granted is exercisable at a strike price, which ranges from $1.47 per share to $56.98 per share for options currently outstanding. A brief description of each plan is provided below:

•

NGC Plan. Created early in our history and revised prior to Dynegy becoming a publicly traded company in 1996, this plan contains 13,651,802 authorized shares, had a 10-year term, and expired in May 2006. All option grants are vested.

•

Employee Equity Plan. This plan expired in May 2002 and is the only plan in which we granted options below the fair market value of Class A common stock on the date of grant. This plan had 20,358,802 authorized shares. All option grants are vested.

•

Illinova Plan. Adopted by Illinova prior to the merger with Dynegy, this plan expired upon the merger date in February 2000 and had 3,000,000 authorized shares. All option grants are vested.

•

Extant Plan. Adopted by Extant prior to its acquisition by Dynegy, this plan expired in September 2000 and had 202,577 authorized shares. All option grants are vested.

•

UK Plan. This plan had 276,000 authorized shares and has been terminated. All option grants are vested.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

•

Dynegy 1999 LTIP. This annual compensation plan has 6,900,000 authorized shares, has a 10-year term and expires in 2009. All option grants are vested.

•

Dynegy 2000 LTIP. This annual compensation plan, created for all employees upon the merger of Illinova and Dynegy, has 10,000,000 authorized shares, has a 10-year term and expires in February 2010. Grants from this plan vest in equal annual installments over a three-year period.

•

Dynegy 2001 Non-Executive LTIP. This plan is a broad-based plan and has 10,000,000 authorized shares, has a 10-year term and expires in September 2011. Grants from this plan vest in equal annual installments over a three-year period.

•

Dynegy 2002 LTIP. This annual compensation plan has 10,000,000 authorized shares, has a 10-year term and expires in May 2012. Grants from this plan vest in equal annual installments over a three-year period.

All of our option plans cease vesting for employees who are terminated for cause. For voluntary and involuntary termination, disability, retirement or death, continued vesting and/or an extended period in which to exercise vested options may apply, depending on the terms of the grant agreement in which a specific grant was awarded. It has been our practice to issue shares of common stock upon exercise of stock options generally from previously unissued shares.

The Merger Agreement with LS Power will result in a change in control as defined in our Severance Pay Plans, as well as the various grant agreements. Please read Note 2—Business Combinations—LS Power for further discussion of the transaction. As a result, all options previously granted to employees will fully vest immediately upon the close of the LS Power transaction. This occurrence will not have a material effect on our financial condition, results of operations or cash flows.

During the first quarter 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, 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 agreed to make a cash payment of approximately $5.6 million based on the in-the-money value of the vested stock options that were cancelled. This cash payment, which accrues interest at 7.5% annually, will be made on January 15, 2007. The newly granted stock options have a term of 10 years, vest in three equal annual installments beginning on the first anniversary of the grant date and are subject to earlier vesting upon a constructive termination, a termination without cause or a termination resulting from a change in control. We recorded a liability to reflect the agreed upon cash payment. We were not required to record any incremental compensation expense in connection with the transaction.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Options outstanding as of September 30, 2006 are summarized below:


	Options (in thousands)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (in years)	Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2005	9,314		$	12.66
Granted	3,268		$	4.88
Exercised	(1,423	)	$	3.46
Forfeited or expired	(2,829	)	$	4.93

Outstanding at September 30, 2006	8,330		$	13.80	6.13	$	5.0

Vested and unvested expected to vest at September 30, 2006	7,642		$	14.63	5.8	$	4.6
Exercisable at September 30, 2006	4,701		$	20.78	3.7	$	2.4

The weighted average grant-date fair value of options granted during the nine months ended September 30, 2006 and 2005 was $2.61 and $3.66, respectively. The total intrinsic value of options exercised for the nine-month periods ended September 30, 2006 and 2005 was $4 million and $1 million, respectively.

Restricted stock activity for the nine months ended September 30, 2006 was as follows:


	Number of Shares (in thousands)		Weighted Average Grant Date Fair Value
Nonvested at December 31, 2005	1,239		$	4.40
Granted	1,311		$	4.88
Vested	(251	)	$	4.40
Forfeited	(154	)	$	4.76

Nonvested at September 30, 2006	2,145		$	4.67

All restricted stock awards to employees vest immediately upon the occurrence of a change in control in accordance with the terms of the applicable Severance Pay Plan. The Merger Agreement with the LS Entities will result in a change in control as defined in our restricted stock agreements. Please read Note 2—Business Combinations—LS Power for further discussion.

Compensation expense related to options granted and restricted stock awarded totaled $2 million and $3 million for the quarters ended September 30, 2006 and 2005, respectively, and $6 million and $7 million for the nine month periods ended September 30, 2006 and 2005 respectively. Tax benefits for compensation expense related to options granted and restricted stock awarded totaled $1 million for the quarters ended September 30, 2006 and 2005, and $2 million for both the nine months ended September 30, 2006 and 2005. We recognize compensation expense ratably over the vesting period of the respective awards. As of September 30, 2006, $9 million of total unrecognized compensation expense related to options granted and restricted stock awarded is expected to be recognized over a weighted-average period of 2.2 years. The total fair value of shares vested was zero for the quarters ended September 30, 2006 and 2005, and $4 million and $3 million for the nine months ended September 30, 2006 and 2005, respectively. We did not capitalize or use cash to settle any share-based compensation in the nine months ended September 30, 2006.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Cash received from option exercises for the three and nine months ended September 30, 2006 was $1 and $5 million, respectively. The tax benefit realized for the additional tax deduction from share-based payment awards totaled $1 million for the nine months ended September 30, 2006.

In the first quarter 2006, we granted stock-based compensation awards that cliff vest after three years based on our cumulative operating cash flows for 2006-2008, or sooner upon a change in control. Compensation expense recorded in the three and nine months ended September 30, 2006 related to these “performance units” was less than $1 million and was accrued in Other long-term liabilities in our unaudited condensed consolidated balance sheets. The Merger Agreement with the LS Entities will result in a change in control as related to these awards.

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


	Pension Benefits						Other Benefits
	Three Months Ended September 30, 2006
	2006			2005			2006		2005
	(in millions)
Service cost benefits earned during period	$	2		$	2		$	—	$	1
Interest cost on projected benefit obligation		2			3			—		—
Expected return on plan assets		(2	)		(2	)		—		—
Recognized net actuarial loss		1			—			1		1

Net periodic benefit cost		3			3			1		2
Additional costs due to curtailment		1			—			—		—

Total net periodic benefit cost	$	4		$	3		$	1	$	2


	Pension Benefits						Other Benefits
	Nine Months Ended September 30,
	2006			2005			2006		2005
	(in millions)
Service cost benefits earned during period	$	7		$	8		$	2	$	2
Interest cost on projected benefit obligation		7			7			2		2
Expected return on plan assets		(7	)		(6	)		—		—
Recognized net actuarial loss		2			2			1		1

Net periodic benefit cost		9			11			5		5
Additional cost due to curtailment		3			—			—		—

Total net periodic benefit cost	$	12		$	11		$	5	$	5

The curtailment charge was accrued at December 31, 2005 in other long-term liabilities on our unaudited condensed consolidated balance sheets.

Contributions. In 2006, we contributed approximately $14 million to our pension plans, $11 million of which we paid in August 2006. We expect to contribute less than $1 million to our other postretirement benefit plans in the fourth quarter 2006.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Note 13—Income Taxes

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
	(in millions, except rates)
Income tax benefit	$	39		$	13		$	154		$	228
Effective tax rate		35	%		48	%		35	%		35	%

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. In general, differences between our effective rate and the statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and permanent differences attributable to book-tax differences. For the nine months ended September 30, 2005, additional differences in our overall effective tax rate on continuing operations included the non deductible portion of the charge associated with the shareholder litigation settlement, off set by changes in the valuation allowances and adjustments to the effective state tax rate. For the three months ended September 30, 2005, our effective tax rate on continuing operations included an increase in the reserve for future tax liabilities.

Texas Margin Tax. In May 2006, Texas enacted a new law that substantially changes the state’s tax system. The law replaces the taxable-capital and earned-surplus components of its franchise tax with a new franchise tax that is based on modified gross revenue. This new franchise tax is referred to as the “Margin Tax” and will significantly affect the financial reporting of a wide range of enterprises that have operations in Texas. As a result of the new law, which becomes effective January 1, 2007, we established a deferred tax liability of $2 million related to our Texas operations. The effect of the change in Texas law produced a total charge of $2 million.

Note 14—Segment Information

We report the results of our power generation business as three separate geographical segments in our consolidated financial statements: (1) the Midwest segment (GEN-MW); (2) the Northeast segment (GEN-NE); and (3) the South segment (GEN-SO). We also separately report the results of our former NGL and CRM business segments because of the diversity among their respective operations. Our consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization. Certain general and administrative expenses were allocated to our reporting segments prior to January 1, 2006. Beginning January 1, 2006, all direct general and administrative expenses are included in Other and Eliminations, unless they are specifically identified with the respective segment.

Our former natural gas liquids operations comprise the NGL segment and are included in discontinued operations. Results associated with the former DGC segment are included in discontinued operations in Other and Eliminations due to the sale of our communications businesses. Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the three and nine months ended September 30, 2006 and 2005 is presented below:

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Segment Data for the Three Months Ended September 30, 2006

(in millions)


	Power Generation									CRM			NGL		Other and Eliminations			Total
	GEN-MW			GEN-NE			GEN-SO			CRM			NGL		Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	260		$	182		$	97		$	20		$	—	$	—		$	559
Other		—			18			—			4			—		—			22

		260			200			97			24			—		—			581
Intersegment revenues		—			(1	)		—			1			—		—			—

Total revenues	$	260		$	199		$	97		$	25		$	—	$	—		$	581

Depreciation and amortization	$	(43	)	$	(6	)	$	(5	)	$	—		$	—	$	(3	)	$	(57	)
Impairment and other charges		(96	)		—			—			—			—		—			(96	)
Operating income (loss)	$	(10	)	$	33		$	8		$	(9	)	$	—	$	(40	)	$	(18	)
Earnings from unconsolidated investments		—			—			4			—			—		—			4
Other items, net		1			2			—			2			—		6			11
Interest expense and debt conversion costs																			(107	)

Loss from continuing operations before income taxes																			(110	)
Income tax benefit																			39

Loss from continuing operations																			(71	)
Income from discontinued operations, net of taxes																			2

Net loss																		$	(69	)


Identifiable assets:
Domestic	$	4,599		$	1,371		$	867		$	364		$	30	$	169		$	7,400
Other		—			10			2			95			—		—			107

Total	$	4,599		$	1,381		$	869		$	459		$	30	$	169		$	7,507

Unconsolidated investments	$	—		$	—		$	7		$	—		$	—	$	—		$	7
Capital expenditures	$	(22	)	$	(5	)	$	(4	)	$	—		$	—	$	(2	)	$	(33	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Segment Data for the Three Months Ended September 30, 2005

(in millions)


	Power Generation									CRM			NGL			Other and Eliminations			Total
	GEN-MW			GEN-NE			GEN-SO			CRM			NGL			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	256		$	329		$	134		$	39		$	—		$	—		$	758
Other		—			16			—			(4	)		—			—			12

		256			345			134			35			—			—			770
Intersegment revenues		(1	)		2			(3	)		2			—			—			—

Total revenues	$	255		$	347		$	131		$	37		$	—		$	—		$	770

Depreciation and amortization	$	(40	)	$	(6	)	$	(7	)	$	—		$	—		$	(3	)	$	(56	)
Operating income (loss)	$	55		$	49		$	11		$	(18	)	$	—		$	(32	)	$	65
Earnings from unconsolidated investments		6			—			1			—			—			—			7
Other items, net		3			1			(2	)		(5	)		—			3			—
Interest expense																				(99	)

Loss from continuing operations before income taxes																				(27	)
Income tax benefit																				13

Loss from continuing operations																				(14	)
Income from discontinued operations, net of taxes																				43

Net income																			$	29


Identifiable assets:
Domestic	$	5,165		$	1,621		$	1,041		$	1,394		$	1,705		$	576		$	11,502
Other		—			18			7			124			—			—			149

Total	$	5,165		$	1,639		$	1,048		$	1,518		$	1,705		$	576		$	11,651

Unconsolidated investments	$	65		$	—		$	226		$	—		$	77		$	—		$	368
Capital expenditures	$	(17	)	$	(4	)	$	(1	)	$	—		$	(16	)	$	(1	)	$	(39	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Segment Data for the Nine Months Ended September 30, 2006

(in millions)


	Power Generation									CRM			NGL		Other and Eliminations			Total
	GEN-MW			GEN-NE			GEN-SO			CRM			NGL		Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	744		$	410		$	276		$	69		$	—	$	—		$	1,499
Other		—			109			—			12			—		—			121

		744			519			276			81			—		—			1,620
Intersegment revenues		—			(3	)		—			3			—		—			—

Total revenues	$	744		$	516		$	276		$	84		$	—	$	—		$	1,620

Depreciation and amortization	$	(126	)	$	(18	)	$	(16	)	$	—		$	—	$	(14	)	$	(174	)
Impairment and other charges		(96	)		—			(9	)		—			—		(2	)		(107	)
Operating income (loss)	$	159		$	59		$	(15	)	$	(3	)	$	—	$	(121	)	$	79
Earnings from unconsolidated investments		—			—			6			—			—		—			6
Other items, net		1			6			1			1			—		32			41
Interest expense and debt conversion costs																			(559	)

Loss from continuing operations before income taxes																			(433	)
Income tax benefit																			154

Loss from continuing operations																			(279	)
Income from discontinued operations, net of taxes																			3
Cumulative effect of change in accounting principle, net of taxes																			1

Net loss																		$	(275	)


Identifiable assets:
Domestic	$	4,599		$	1,371		$	867		$	364		$	30	$	169		$	7,400
Other		—			10			2			95			—		—			107

Total	$	4,599		$	1,381		$	869		$	459		$	30	$	169		$	7,507

Unconsolidated investments	$	—		$	—		$	7		$	—		$	—	$	—		$	7
Capital expenditures	$	(58	)	$	(12	)	$	(16	)	$	—		$	—	$	(6	)	$	(92	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Segment Data for the Nine Months Ended September 30, 2005

(in millions)


	Power Generation									CRM			NGL			Other and Eliminations			Total
	GEN-MW			GEN-NE			GEN-SO			CRM			NGL			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	688		$	613		$	291		$	99		$	—		$	—		$	1,691
Other		—			46			—			(46	)		—			—			—

		688			659			291			53			—			—			1,691
Intersegment revenues		—			—			(28	)		28			—			—			—

Total revenues	$	688		$	659		$	263		$	81		$	—		$	—		$	1,691

Depreciation and amortization	$	(117	)	$	(16	)	$	(17	)	$	(1	)	$	—		$	(14	)	$	(165	)
Operating income (loss)	$	154		$	45		$	(5	)	$	(225	)	$	—		$	(353	)	$	(384	)
Earnings from unconsolidated investments		7			—			7			—			—			—			14
Other items, net		2			3			(1	)		(5	)		—			10			9
Interest expense																				(284	)

Loss from continuing operations before income taxes																				(645	)
Income tax benefit																				228

Loss from continuing operations																				(417	)
Income from discontinued operations, net of taxes																				209

Net loss																			$	(208	)


Identifiable assets:
Domestic	$	5,165		$	1,621		$	1,041		$	1,394		$	1,705		$	576		$	11,502
Other		—			18			7			124			—			—			149

Total	$	5,165		$	1,639		$	1,048		$	1,518		$	1,705		$	576		$	11,651

Unconsolidated investments	$	65		$	—		$	226		$	—		$	77		$	—		$	368
Capital expenditures	$	(74	)	$	(11	)	$	(2	)	$	—		$	(39	)	$	(6	)	$	(132	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Note 15—Subsequent Events

On October 5, 2006, we entered into a settlement agreement with Enron and certain of its subsidiaries to resolve claims arising from or relating to the entry of the Master Netting Setoff Security Agreement in 2001. Please read Note 10—Commitments and Contingencies—Enron Trade Credit Litigation for a discussion of the settlement.

DYNEGY INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended September 30, 2006 and 2005

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/A.

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. We report the results of our power generation business as three separate segments in our consolidated financial statements: (1) the Midwest segment (GEN-MW); (2) the Northeast segment (GEN-NE); and (3) 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 legacy physical natural gas supply contracts and natural gas transportation contracts and remaining legacy power and emission trading positions. Because of the diversity among their respective operations, we report the results of each business as a separate segment in our consolidated financial statements. Our consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.

Recent Developments

LS Power Combination. On September 14, 2006, we entered into a Plan of Merger, Contribution and Sale Agreement with the LS Entities, a privately held power plant investor, developer and manager, to combine the LS Entities’ generation portfolio with our current assets, and for us to acquire a 50 percent ownership interest in a development company that is currently controlled by the LS Entities. The combined company (“New Dynegy”) will have more than 20,000 MW of commissioned generating capacity. Upon completion of the transaction, which is subject to an affirmative vote by two-thirds of our stockholders and various regulatory approvals, the combined company will own 31 operating power plants in 15 states employing a balanced mix of fuel sources with baseload, intermediate, and peaking dispatch capabilities, enhanced cash flow-generating opportunities, and significant scale and scope in three key geographic regions. The expanded portfolio will also include a controlling interest in the Plum Point facility, a 665 MW coal-fired plant currently under construction in Arkansas. Additionally, the development joint venture will provide us with a 50 percent ownership interest in an established growth vehicle. The LS Entities’ current development activities include nine projects totaling more than 7,600 MW in various stages of development and approximately 2,300 MW of repowering opportunities.

Under the terms of the transaction, at closing the LS Entities will receive 340 million shares of New Dynegy’s Class B common stock, $100 million in cash and $275 million aggregate principal amount of notes to be issued by New Dynegy. New Dynegy will also assume approximately $1.8 billion in net debt from the LS Entities. Please read Note 2—Business Combinations—LS Power for further discussion of the terms of the Plan of Merger, Contribution and Sale Agreement.

Illinois Reverse Power Procurement Auction. On September 20, 2006, DPM entered into two Supplier Forward Contracts (“SFCs”) with subsidiaries of Ameren Corporation (the “Ameren Illinois Utilities”) to provide the Ameren Illinois Utilities with capacity, energy and related services.

Both of the SFCs are for services required by Ameren Illinois Utilities to serve their residential and commercial electric customers starting January 1, 2007. The products to be provided by DPM under both SFCs include electric energy and certain ancillary and other services necessary to serve full-requirements load. The first SFC extends through May 31, 2008 and is for 24 tranches of up to 50 MW per tranche. This amount translates to approximately 22.43% of the total Ameren Illinois Utilities’ relevant customers’ load during each hour of the contract period. The pricing for the first SFC is $64.77 per MW. The second SFC extends through May 31, 2009 and is for 4 tranches of up to 50 MW per tranche. This amount translates to approximately 3.74% of the total Ameren Illinois Utilities’ relevant customers’ load during each hour of the contract period. The pricing for the second SFC is $64.75 per MW.

At least one bill has been introduced in the Illinois General Assembly to extend the rate freeze in effect beyond the end of this year, which may have an impact on the SFCs. There is a possibility of political, legislative, judicial and/or regulatory actions over the next several months that could substantially alter the rights and obligations under the SFCs. There remains the possibility that the Illinois General Assembly will consider legislation in the fourth quarter 2006 either in a veto session or in a special session. We cannot predict the outcome of these matters or their impact, if any, on the SFCs.

Enron Trade Credit Litigation. On October 5, 2006, we entered into a settlement agreement with Enron and certain of its subsidiaries to resolve claims arising from or relating to the entry of the Master Netting Setoff Security Agreement in 2001. DHI paid Enron $44 million to resolve such claims and retained the right to pursue amounts owed by Enron Capital and Trade Resources Limited to Dynegy UK Limited. Please read Note 10—Commitments and Contingencies—Enron Trade Credit Litigation for further discussion of the settlement.

Liability Management. Since the second quarter 2006, we completed several liability management transactions:

•

Redemption of Second Priority Notes Due 2008. On July 15, 2006, DHI redeemed all $74 million of its remaining 2008 Notes, at a redemption price of 103% of the principal amount, plus accrued and unpaid interest to the redemption date. Please read Note 7—Debt—Second Priority Senior Secured Notes for further discussion of the redemption.

•

Sithe Subordinated Debt Exchange. On July 21, 2006, DHI issued $297 million principal amount of additional 8.375% Senior Unsecured Notes due 2016 in exchange for all $419 million of outstanding Independence subordinated debt. Please read Note 7—Debt—Sithe Subordinated Debt Exchange for further discussion of the redemption.

•

Senior Unsecured Notes Exchange Offer. On September 14, 2006, we completed an exchange offer of $1,047 million aggregate principal amount of DHI’s 8.375% Senior Unsecured Notes due 2016. Please read Note 7—Debt—Senior Unsecured Notes Exchange Offer for further discussion of the exchange offer.

Operational Highlights

Scheduled Outages and Maintenance. In the Midwest, we completed our planned Spring 2006 outages at our Havana and Hennepin facilities in a safe and efficient manner and ahead of schedule. Our scheduled outage at the Danskammer 3 facility to address routine boiler work and extensive turbine/generator work is underway. Scheduled outages currently being conducted at our Independence facility are expected to be completed on schedule and without incident. In the South, we completed routine maintenance and the first of several scheduled environmental upgrades at our CoGen Lyondell cogeneration facility. Planned outages during the latter half of 2006 continue on the Baldwin and Danskammer facilities and are expected to be completed by the end of November.

Safety Performance. Safety is a foremost priority for conducting our business. Safety permeates the way we act and work, all the way from our Guiding Principles, to the training and briefings that we do on a daily basis, to

the work plans created for each job that we do in the plants. We have a safety organization in place that is responsible for the training, managing, and oversight of our safety efforts, but our principal tenet is that each and every employee is responsible for his/her own safety, and for that of others with whom they work, on a continual basis. We use standard industry measurements relating to reportable and lost-time incident rates to evaluate our safety performance. Incidents were slightly higher for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005.

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, fixed capacity payments and contractual obligations, capital expenditures, 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, forward sales of power, 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

During 2006, we continued our efforts to reduce our outstanding debt obligations and extend our maturity profile. Please read Note 7—Debt 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 November 3, 2006, September 30, 2006 and December 31, 2005:


	November 3, 2006		September 30, 2006		December 31, 2005
	(in millions)
By Business:
Generation	$	139	$	153	$	280
Customer risk management		52		55		91
Other		7		7		10

Total	$	198	$	215	$	381

By Type:
Cash (1)	$	29	$	27	$	122
Letters of Credit		169		188		259

Total	$	198	$	215	$	381

(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 decrease in collateral postings from December 31, 2005 to September 30, 2006 is primarily due to a return of collateral postings of approximately $127 million in our generation business and $36 million in our customer risk management business. This decrease is primarily a result of decreases in commodity prices since the

end of 2005 as well as the expiration of certain hedging positions. In addition, the $44 million of collateral posted on behalf of West Coast Power was returned as a result of the sale of our 50% interest in West Coast Power to NRG, completed on March 31, 2006. Please read Note 3—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—West Coast Power for further discussion. The decrease in collateral postings from September 30, 2006 to November 3, 2006 is primarily due to decreased prices as well as hedging activities.

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. In addition, the contemplated merger with the LS Entities and the effect of the Illinois Reverse Power auction will have a significant impact on our exposure to collateral demands. 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

As of December 31, 2005, we have NOL carry-forwards of approximately $565 million. These NOL carry-forwards will begin to expire in the year 2022. If substantial changes in our ownership should occur, there could be annual limitations on the utilization of the NOL carry-forwards. While the contemplated merger with the LS Entities would constitute a substantial change in ownership, the transaction itself should not result in a limitation on the utilization of the NOL carry-forwards. However, the calculation of the limitation is complex and future capital transactions executed by us or our significant shareholders could trigger such a limitation. Also, the ultimate realization of these 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.

Our contractual obligations and contingent financial commitments have changed since December 31, 2005 as a result of the termination of the Sterlington long-term wholesale power tolling contract with Quachita Power. Under that termination agreement, which closed on March 7, 2006, capacity payments of up to approximately $744 million have been eliminated. Please read Note 3—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Sterlington Contract Termination for further discussion.

Please also read Note 7—Debt for a discussion of changes in our debt obligations. As of September 30, 2006, there were no other material changes to our contractual obligations and contingent financial commitments since December 31, 2005.

Dividends on Preferred and 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 third quarter 2006 and do not foresee a declaration of dividends in the near-term due to the dividend restrictions contained in our financing agreements.

Internal Liquidity Sources

Our primary internal liquidity sources are cash flows from operations, cash on hand and available capacity under our Fourth Senior Secured Credit Facility, which is scheduled to mature in April 2009 and January 2012.

Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at November 3, 2006, September 30, 2006 and December 31, 2005:


	November 3, 2006			September 30, 2006			December 31, 2005
	(in millions)
Total revolver capacity	$	470	(1)	$	470	(1)	$	—
Total additional letter of credit capacity, plus 3% reserve requirement		194			194			325
Outstanding letters of credit		(169	)		(188	)		(259	)

Unused capacity		495			476			66
Cash		282	(2)(3)		388	(2)(3)		1,549	(2)

Total available liquidity	$	777		$	864		$	1,615

(1)

In April 2006, we amended and restated the credit facility. Please read Note 7—Debt—Senior Secured Credit Facility for further discussion.

(2)

The November 3, 2006, September 30, 2006 and December 31, 2005 amounts include approximately $44 million, $44 million and $21 million, respectively, of cash that remains in Europe and $7 million, $22 million and $19 million, respectively, of cash that remains in Canada.

(3)

The decrease in cash balance since December 31, 2005 was primarily due to the debt repayments associated with our liability management activities. Please read Note 7—Debt for further discussion.

Cash Flows from Operations. We had operating cash outflows of $180 million for the nine months ended September 30, 2006. This consisted of $503 million in operating cash inflows from our power generation business, offset by $370 million of cash outflows relating to our customer risk management business and $313 million of cash outflows relating to corporate-level expenses. Please read “—Results of Operations—Operating Income (Loss)” and “—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—Outlook” for further discussion.

Cash on Hand. At November 3, 2006 and September 30, 2006, we had cash on hand of $282 million and $388 million, respectively, as compared to $1,549 million at the end of 2005. This decrease in cash on hand at September 30, 2006 as compared to the end of 2005 is primarily attributable to our liability management activities. Please read Note 7—Debt for further discussion. The decrease in cash balance on November 3, 2006 from September 30, 2006 was primarily due to the payment related to the settlement agreement with Enron.

Revolver and Letter of Credit Capacity. In April 2006, we entered into the Fourth Senior Secured Credit Facility. The Fourth Senior Secured Credit Facility replaces our former Third Senior Secured Credit Facility. Please read Note 23—Subsequent Events beginning on page F-85 of our Form 10-K/A for further discussion of our former Third Senior Secured Credit Facility. The revolving portion of the Fourth Senior Secured Credit Facility is scheduled to mature in April 2009 and the term letter of credit portion matures in January 2012. The $470 million revolving facility, which is currently undrawn, is available for general corporate purposes and for letters of credit. The $200 million term facility has been fully drawn and the proceeds placed in a collateral account to support the issuance of letters of credit. As of November 3, 2006, we had $169 million in letters of credit issued under these facilities. Our ability to borrow and/or issue letters of credit under a revolving credit facility could become increasingly important to our liquidity and financial condition, particularly if we are unable to generate operating cash flows relative to our substantial debt obligations and ongoing operating requirements. Please read Note 7—Debt—Fourth Senior Secured 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.

Asset Sale Proceeds. In March 2006, we completed our ownership exchange transactions with NRG which comprised our acquisition of NRG’s 50% ownership interest in the entity that owns the Rocky Road power plant (of which we already owned 50%), and the sale to NRG of our 50% ownership interest in the West Coast Power plant, a joint venture between us and NRG, which has ownership in power plants in southern California. As a result of the two transactions, we received cash proceeds of approximately $165 million, net of cash acquired, from NRG. Please read Note 2—Business Combinations—Rocky Road for further discussion. Please read Note 3—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—West Coast Power for further discussion.

We will continue to evaluate our generation fleet based primarily on geographic location, fuel supply, market structure and market recovery expectations. This evaluation will consider the combined portfolio of Dynegy and LS Power in anticipation of the pending transaction. Consistent with industry practice, we periodically consider divestitures of non-core generation assets where the balance of the factors described above suggests that such assets’ earnings potential is limited. Although we have not executed definitive agreements regarding the divestitures of any non-core assets other than Rockingham, opportunities arise from time to time and, as a result, a divestiture could occur at any time.

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 pending transaction with LS Power, we will be evaluating various opportunities to provide additional liquidity and streamline the combined capital structure.

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- and nine-month periods ended September 30, 2006 and 2005. At the end of this section, we have included our outlook for each segment.

We report the results of our power generation business as three separate segments in our unaudited condensed consolidated financial statements: (1) the Midwest segment (GEN-MW); (2) the Northeast segment (GEN-NE); and (3) 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 legacy physical natural gas supply contracts and natural gas transportation contracts and remaining legacy 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. Because of the diversity among their respective operations, we report the results of each business as a separate segment in our unaudited condensed consolidated financial statements. Certain general and administrative expenses were allocated to our reporting segments prior to January 1, 2006. Beginning January 1, 2006, all direct general and administrative expenses are included in Other and Eliminations, unless they are specifically identified with the respective segment. This change in allocation methodology is a result of our efforts to better align our corporate cost structure with a single line of business.

Three Months Ended September 30, 2006 and 2005

Summary Financial Information. The following tables provide summary financial data regarding our consolidated and segmented results of operations for the three-month periods ended September 30, 2006 and 2005, respectively:

Three Months Ended September 30, 2006


	Power Generation							CRM			Other and Eliminations			Total
	GEN-MW			GEN-NE		GEN-SO		CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	(10	)	$	33	$	8	$	(9	)	$	(40	)	$	(18	)
Earnings from unconsolidated investments		—			—		4		—			—			4
Other items, net		1			2		—		2			6			11
Interest expense and debt conversion costs															(107	)


Loss from continuing operations before income taxes															(110	)
Income tax benefit															39

Loss from continuing operations															(71	)
Income from discontinued operations, net of taxes															2

Net loss														$	(69	)

Three Months Ended September 30, 2005


	Power Generation
	GEN-MW		GEN-NE		GEN-SO			CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	55	$	49	$	11		$	(18	)	$	(32	)	$	65
Earnings from unconsolidated investments		6		—		1			—			—			7
Other items, net		3		1		(2	)		(5	)		3			—
Interest expense															(99	)

Loss from continuing operations before income taxes															(27	)
Income tax benefit															13

Loss from continuing operations															(14	)
Income from discontinued operations, net of taxes															43

Net income														$	29

The following table provides summary segmented operating statistics for the three months ended September 30, 2006 and 2005, respectively:


	Three Months Ended September 30,
	2006		2005
GEN-MW
Million Megawatt Hours Generated—Gross and Net		5.7		6.3
Average Actual On-Peak Market Power Prices ($/MWh) (1):
Cinergy (Cin Hub)	$	58	$	80
Commonwealth Edison (NI Hub)	$	58	$	75

GEN-NE
Million Megawatt Hours Generated—Gross and Net		1.7		3.3
Average Actual On-Peak Market Power Prices ($/MWh) (1):
New York— Zone G	$	84	$	110
New York— Zone A	$	62	$	91

GEN-SO
Million Megawatt Hours Generated—Gross		1.2		1.8
Million Megawatt Hours Generated—Net		1.1		1.3
Average Actual On-Peak Market Power Prices ($/MWh) (1):
Southern	$	61	$	90
ERCOT	$	72	$	107
Average natural gas price—Henry Hub ($/MMBtu) (2)	$	6.08	$	9.66

(1)	Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices realized by the company.

(2)	Reflects the average of daily quoted prices for the periods presented and does not necessarily reflect prices realized by the company.

The following tables summarize significant items on a pre-tax basis affecting net income (loss) for the periods presented.


	Three Months Ended September 30, 2006
	Power Generation
	GEN-MW			GEN-NE			GEN-SO		CRM			NGL		Other		Total
	(in millions)
Asset impairment	$	(96	)	$	—		$	—	$	—		$	—	$	—	$	(96	)
Sithe Subordinated Debt Exchange charge		—			(36	)		—		—			—		—		(36	)
Legal and settlement charges		—			—			—		(22	)		—		—		(22	)

Total	$	(96	)	$	(36	)	$	—	$	(22	)	$	—	$	—	$	(154	)


	Three Months Ended September 30, 2005
	Power Generation
	GEN-MW		GEN-NE		GEN-SO		CRM			NGL		Other		Total
	(in millions)
Legal and settlement charges	$	—	$	—	$	—	$	(29	)	$	—	$	4	$	(25	)
Discontinued operations		—		—		—		(2	)		71		—		69

Total	$	—	$	—	$	—	$	(31	)	$	71	$	4	$	44

Operating Income (Loss)

Operating loss was $18 million for the three months ended September 30, 2006, compared to operating income of $65 million for the three months ended September 30, 2005.

Power Generation— Midwest Segment. Operating loss for GEN-MW was $10 million for the three months ended September 30, 2006, compared to operating income of $55 million for the three months ended September 30, 2005. GEN-MW results for the three months ended September 30, 2005 included general and administrative expenses of $9 million. Beginning in 2006, general and administrative expenses are reported in our Other segment. Please read “Results of Operations—Operating Income (Loss)—Other” for a consolidated discussion of general and administrative expenses.

Results from our coal-fired generating units increased to $116 million for the three months ended September 30, 2006 from $99 million for the three months ended September 30, 2005. Average actual on-peak prices in the CinHub/Cinergy pricing region decreased from $80 per MWh in the third quarter 2005 to $58 per MWh in the third quarter 2006. Generated volumes decreased from 6.3 million MWh in the third quarter 2005 to 5.7 million MWh in the same period in 2006. Despite the decrease in market prices and volumes, our results for 2006 increased due to higher realized prices. Results for 2005 were negatively impacted by the AmerenIP contract which prevented us from recognizing the full benefit of market prices during the 2005 period. During certain peak periods in 2005, Ameren took higher volumes than we expected, resulting in a need to purchase power at market prices in order to satisfy our obligations for forward sales previously made to other third parties. We did not experience a similar situation under the AmerenIP contract in 2006. In addition, results for the three months ended September 30, 2006 include $11 million of mark-to-market income, compared with $12 million of mark-to-market losses for the three months ended September 30, 2005. These transactions are primarily related to options and other financial transactions that economically hedged our generation assets but were not designated as cash flow hedges. The higher realized prices and mark-to market income were partially offset by higher operating costs of approximately $5 million due to timing of scheduled maintenance.

Results from our natural gas-fired peaking facilities in GEN-MW improved by $4 million, from $8 million in the third quarter 2005 to $12 million for the same period in 2006. Results benefited from our increased ownership in the Rocky Road facility and the associated increase in capacity revenues but were negatively impacted by a quarter-over-quarter increase in operating expenses of approximately $1 million. Generated volumes decreased from 0.3 million MWh for the third quarter of 2005 to 0.2 million MWh in the third quarter of 2006.

Depreciation expense increased from $40 million in 2005 to $43 million in 2006 as a result of capital projects placed into service in 2005. This was primarily the result of the conversion of the Havana facility to burn PRB coal. Additionally, 2006 results include a pre-tax impairment charge of $96 million in the third quarter 2006 related to the Bluegrass generation facility, due to recent changes in the market that resulted in economic constraints on the facility. Please read Note 4—Restructuring and Impairment Charges—Asset Impairment for further discussion.

Power Generation— Northeast Segment. Operating income for GEN-NE was $33 million for the three months ended September 30, 2006, compared to $49 million for the three months ended September 30, 2005. GEN-NE operating income for the three months ended September 30, 2005 included general and administrative expenses of $7 million. Beginning in 2006, general and administrative expenses are reported in our Other segment. Please read “Results of Operations—Operating Income (Loss)—Other” for a consolidated discussion of general and administrative expenses.

Results for our Roseton and Danskammer facilities decreased by $19 million from $41 million for the three months ended September 30, 2005 to $22 million for the three months ended September 30, 2006. Average on-peak prices for Zone G, the market served by these two facilities, decreased from $110 per MWh in 2005 to $84 per MWh in 2006. Generated volumes decreased from 2.2 million MWh in the third quarter 2005 to 0.9 million MWh in the same period in 2006. Results decreased primarily due to lower spark spreads, lower coal margins and a fuel oil inventory write-down of approximately $6 million. Mark-to-market losses of $7 million and $5 million for the third quarters 2006 and 2005, respectively, were related to financial transactions not designated as cash flow hedges.

Results for our Independence facility decreased approximately $2 million from $19 million for the three months ended September 30, 2005 to $17 million for the three months ended September 30, 2006. Average on-peak prices for Zone A decreased from $91 per MWh in 2005 to $62 per MWh in 2006. Generated volumes decreased from 1.1 million MWh in the third quarter 2005 to 0.8 million MWh in the same period in 2006.

Depreciation expense remained flat at $6 million in 2006 and 2005.

Power Generation— South Segment. Operating income for GEN-SO was $8 million for three months ended September 30, 2006, compared to income of $11 million for the three months ended September 30, 2005. GEN-SO for the three months ended September 30, 2005, included general and administrative expenses of $3 million. Beginning in 2006, general and administrative expenses are reported in our Other segment. Please read “Results of Operations—Operating Income (Loss)—Other” for a consolidated discussion of general and administrative expenses.

Results from our ERCOT facility were $5 million for the three months ended September 30, 2006, compared to $17 million for the three months ended September 30, 2005. Results for 2006 and 2005 include losses of $5 million and income of $9 million, respectively, related to hedge ineffectiveness, caused by natural gas price volatility in the markets in which we hedge our Texas fuel purchases. In addition, results were lower for 2006 due to lower ancillary service revenue.

Results from our Southeast peaker assets increased from $3 million in 2005 to $8 million in 2006. These improved results are due to higher volumes for the Rockingham, Heard and Calcasieu facilities and lower operating costs of approximately $1 million.

Depreciation expense decreased to $5 million for the three months ended September 30, 2006 from $7 million for the three months ended September 30, 2005. We stopped depreciating the Rockingham facility as it has been classified as held for sale beginning in the second quarter 2006. Please read Note 3—Dispositions, Contract Terminations and Discontinued Operations—Rockingham for further discussion.

CRM. Operating loss for the CRM segment was $9 million for the three months ended September 30, 2006, compared to an operating loss of $18 million for the three months ended September 30, 2005. Results for 2006 reflect a charge of approximately $22 million 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. This was offset by mark-to-market income on our legacy coal, natural gas, emissions, and power positions. We continue to diligently work to eliminate or mitigate all CRM positions. CRM results are benefiting from our continued wind-down of the various positions that make up this segment.

In the third quarter of 2005, we recognized a $21 million gain related to the termination of a contract to sell emissions allowances. However, this gain was more than offset by $14 million of fixed payments on our Sterlington power tolling arrangement in excess of realized margins on power generated and sold, a $29 million increase in legal reserves, as well as net mark-to-market gains of $3 million on our legacy emissions, gas and power positions. The increased legal reserves resulted from additional activities during the quarter that affected management’s assessment of the probable and estimable loss associated with the applicable proceedings.

Other. Operating loss for the Other segment was $40 million for the three months ended September 30, 2006, compared to a loss of $32 million for the three months ended September 30, 2005. Results for third quarter 2006 include approximately $37 million of general and administrative expenses, including costs related to our business segments, which prior to the first quarter 2006 were included in the individual segments. Results for the three months ended September 30, 2005 included general and administrative expenses of $28 million.

Consolidated general and administrative expenses decreased from $76 million for the three months ended September 30, 2005 to $59 million for the three months ended September 30, 2006, primarily due to $25 million in legal and settlement charges recorded in 2005, largely associated with our CRM segment, as well as decreases in compensation and benefits costs and professional and legal fees from 2005 to 2006, offset by $22 million in legal reserves recorded in 2006, which are reflected in our CRM segment.

Earnings from Unconsolidated Investments

Earnings from unconsolidated investments for the three months ended September 30, 2006 of $4 million includes the GEN-SO investment in Black Mountain. Earnings from unconsolidated investments of $7 million for the three months ended September 30, 2005 includes results from GEN-SO investments in both Black Mountain and West Coast Power.

Other Items, Net

Other items, net totaled $11 million of income for the three months ended September 30, 2006, compared to no income for the three months ended September 30, 2005. The increase is due to higher interest income in 2006 resulting from higher cash balances and higher interest rates. In addition, we recognized foreign exchange losses in 2005 which were not repeated in 2006.

Interest Expense

Interest expense and debt conversion costs totaled $107 million for the three months ended September 30, 2006, compared to $99 million for the three months ended September 30, 2005. The increase is primarily due to the $36 million charge associated with the Sithe Subordinated Debt exchange, offset by reductions due to lower principal amounts outstanding as a result of our liability management program executed in the second quarter. Please read Note 7—Debt—Sithe Subordinated Debt Exchange for further discussion.

Income Tax Benefit

We reported an income tax benefit from continuing operations of $39 million for the three months ended September 30, 2006, compared to an income tax benefit from continuing operations of $13 million for the three months ended September 30, 2005. The 2006 effective tax rate was 35%, compared to 48% in 2005. In general, differences between these effective rates and the statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and permanent differences attributable to book-tax differences. Additionally, our overall effective tax rate on continuing operations for the three months ended September 30, 2006 was different than the statutory rate of 35% due primarily to an increase in the reserve for future tax liabilities.

Discontinued Operations

Income From Discontinued Operations Before Taxes. Discontinued operations include DMSLP in our NGL segment and our U.K. CRM business and U.K. natural gas storage assets in the CRM segment.

The following summarizes the activity included in income from discontinued operations:

Three Months Ended September 30, 2006


	U.K. CRM			NGL			Total
	(in millions)
Operating income included in income from discontinued operations	$	6		$	2		$	8
Other items, net included in income from discontinued operations		—			—			—

Income from discontinued operations before taxes								8
Income tax expense								(6	)

Income from discontinued operations							$	2


Three Months Ended September 30, 2005
	U.K. CRM			NGL			Total
	(in millions)
Operating income included in income from discontinued operations	$	—		$	93		$	93
Earnings from unconsolidated investments included in income from discontinued operations		—			1			1

Other items, net included in income from discontinued operations		(2	)		(8	)		(10	)
Interest expense included in income from discontinued operations								(15	)

Income from discontinued operations before taxes								69
Income tax expense								(26	)

Income from discontinued operations							$	43

We completed the sale of DMSLP on October 31, 2005 as further discussed in Note 3—Dispositions, Contract Terminations and Discontinued Operations— Discontinued Operations—Natural Gas Liquids. As a result of the sale, and as required by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we have reclassified the operations related to DMSLP, which comprised of the remaining operations of our NGL segment, from continuing operations to discontinued operations.

During the three months ended September 30, 2006, the pre-tax income from discontinued operations was $8 million ($2 million after-tax). Our U.K. CRM business includes a pre-tax gain of $6 million for the three months ended September 30, 2006, associated with a receivable previously reserved. During the three months ended September 30, 2005, pre-tax income from discontinued operations of $69 million ($43 million after-tax) included $71 million in pre-tax income attributable to our NGL business.

In accordance with EITF Issue 87-24, “Allocation of Interest to Discontinued Operations,” we have allocated interest expense to discontinued operations associated with debt instruments that were required to be paid upon the sale of DMSLP. Interest expense included in income from discontinued operations, which includes interest incurred on our former term loan and our former Generation facility debt, totaled zero and $15 million during the three months ended September 30, 2006 and 2005, respectively.

Income Tax Expense From Discontinued Operations. We recorded an income tax expense from discontinued operations of $6 million during the three months ended September 30, 2006, compared to income tax expense from discontinued operations of $26 million during the three months ended September 30, 2005. The effective rates for the three months ended September 30, 2006 and 2005, were 75% and 38%, respectively. FIN No. 18, “Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28” proscribes 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%.

Nine Months Ended September 30, 2006 and 2005

Summary Financial Information. The following tables provide summary financial data regarding our consolidated and segmented results of operations for the nine-month periods ended September 30, 2006 and 2005, respectively:

Nine Months Ended September 30, 2006


	Power Generation
	GEN-MW		GEN-NE		GEN-SO			CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	159	$	59	$	(15	)	$	(3	)	$	(121	)	$	79
Earnings from unconsolidated investments		—		—		6			—			—			6
Other items, net		1		6		1			1			32			41
Interest expense and debt conversion costs															(559	)

Loss from continuing operations before income taxes															(433	)
Income tax benefit															154

Loss from continuing operations															(279	)
Income from discontinued operations, net of taxes															3
Cumulative effect of change in accounting principle, net of taxes															1

Net loss														$	(275	)

Nine Months Ended September 30, 2005


	Power Generation
	GEN-MW		GEN - NE		GEN-SO			CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	154	$	45	$	(5	)	$	(225	)	$	(353	)	$	(384	)
Earnings from unconsolidated investments		7		—		7			—			—			14
Other items, net		2		3		(1	)		(5	)		10			9
Interest expense															(284	)

Loss from continuing operations before income taxes															(645	)
Income tax benefit															228

Loss from continuing operations															(417	)
Income from discontinued operations, net of taxes															209

Net loss														$	(208	)

The following table provides summary segmented operating statistics for the nine months ended September 30, 2006 and 2005, respectively:


	Nine Months Ended September 30,
	2006		2005
GEN-MW
Million Megawatt Hours Generated—Gross and Net		16.1		16.8
Average Actual On-Peak Market Power Prices ($/MWh) (1):
Cinergy (Cin Hub)	$	53	$	61
Commonwealth Edison (NI Hub)	$	54	$	59

GEN-NE
Million Megawatt Hours Generated—Gross and Net		3.5		6.8
Average Actual On-Peak Market Power Prices ($/MWh) (1):
New York— Zone G	$	78	$	86
New York— Zone A	$	60	$	70

GEN-SO
Million Megawatt Hours Generated—Gross		3.8		5.6
Million Megawatt Hours Generated—Net		3.1		4.1
Average Actual On-Peak Market Power Prices ($/MWh) (1):
Southern	$	57	$	65
ERCOT	$	66	$	76
Average natural gas price—Henry Hub ($/MMBtu) (2)	$	6.79	$	7.66

(1)	Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices realized by the company.

(2)	Reflects the average of daily quoted prices for the periods presented and does not necessarily reflect prices realized by the company.

The following tables summarize significant items on a pre-tax basis, with the exception of the 2005 tax item, affecting net loss for the periods presented.


	Nine Months Ended September 30, 2006
	Power Generation
	GEN-MW			GEN-NE			GEN-SO			CRM			NGL		Other			Total
	(in millions)
Debt conversion costs	$	—		$	—		$	—		$	—		$	—	$	(249	)	$	(249	)
Asset impairments		(96	)		—			(9	)		—			—		—			(105	)
Legal and settlement charges		—			—			—			(53	)		—		(2	)		(55	)
Sithe Subordinated Debt exchange charge		—			(36	)		—			—			—		—			(36	)
Acceleration of financing costs		—			—			—			—			—		(34	)		(34	)

Total	$	(96	)	$	(36	)	$	(9	)	$	(53	)	$	—	$	(285	)	$	(479	)


	Nine Months Ended September 30, 2005
	Power Generation
	GEN-MW		GEN-NE		GEN-SO		CRM			NGL		Other			Total
	(in millions)
Legal and settlement charges	$	—	$	—	$	—	$	(29	)	$	—	$	(249	)	$	(278	)
Independence toll settlement charge		—		—		—		(169	)		—		—			(169	)
Discontinued operations		—		—		—		3			152		—			155
Taxes		—		—		—		—			—		112			112

Total	$	—	$	—	$	—	$	(195	)	$	152	$	(137	)	$	(180	)

Operating Income (Loss)

Operating income was $79 million for the nine months ended September 30, 2006, compared to an operating loss of $384 million for the nine months ended September 30, 2005.

Power Generation— Midwest Segment. Operating income for GEN-MW was $159 million for the nine months ended September 30, 2006, compared to $154 million for the nine months ended September 30, 2005. GEN-MW results for the nine months ended September 30, 2005 included general and administrative expenses of $26 million. Beginning in 2006, general and administrative expenses are reported in our Other segment. Please read “Results of Operations—Operating Income (Loss)—Other” for a consolidated discussion of general and administrative expenses.

Results from our coal-fired generating units increased to $360 million for the nine months ended September 30, 2006 from $300 million for the nine months ended September 30, 2005. Average actual on-peak prices in the CinHub/Cinergy pricing region decreased from $61 per MWh in the nine months ended September 30, 2005 to $53 per MWh for the nine months ended September 30, 2006. Generated volumes decreased from 16.8 million MWh in the nine months ended September 30, 2005 to 16.1 million MWh in the same period in 2006. Despite the decrease in market prices and the decrease in output, the increase in results was primarily driven by higher realized power prices. We realized higher power prices in the first quarter 2006 as we settled forward power sales. Additionally, results from our coal-fired generating units were negatively impacted by the AmerenIP contract during the second and third quarters of 2005, preventing us from recognizing the full benefit of market prices during the 2005 period. During certain peak periods in 2005, Ameren took higher volumes than we expected, resulting in a need to purchase power at market prices in order to satisfy our obligations for forward sales previously made to other third-parties. We did not experience a similar situation under the AmerenIP contract in 2006. In addition, results for the nine months ended September 30, 2006 include mark-to-market income of approximately $10 million, compared with losses of $2 million for the nine months ended September 30, 2005. These transactions are primarily related to options and other financial transactions that economically hedged our generation assets but were not designated as cash flow hedges. The higher realized prices and mark-to-market income were partially offset by higher operating costs of approximately $6 million due to the timing of scheduled maintenance.

Results for our natural gas-fired peaking facilities in GEN-MW improved by $14 million, increasing from $6 million for the first nine months of 2005 to $20 million for the same period in 2006. This improvement was the result of increased capacity fees particularly at our Renaissance facility. In addition, our acquisition of the remaining ownership interest in the Rocky Road facility and the related increase in capacity fees also contributed to the increase.

Depreciation expense increased from $117 million in 2005 to $126 million in 2006 as a result of capital projects placed into service in 2005. This was primarily related to the conversion of the Havana facility to burn PRB coal. In addition, we recorded a $96 million pre-tax impairment charge in the third quarter of 2006 related to the Bluegrass generation facility due to recent changes in the market that resulted in economic constraints on the facility. Please read Note 4—Restructuring and Impairment Charges—Asset Impairment for further discussion. Additionally, our 2005 results include a $7 million charge associated with the write-off of an environmental project.

Power Generation— Northeast Segment. Operating income for GEN-NE was $59 million for the nine months ended September 30, 2006, compared to $45 million for the nine months ended September 30, 2005. GEN-NE for the nine months ended September 30, 2005 included general and administrative expenses of $18 million. Beginning in 2006, general and administrative expenses are reported in our Other segment. Please read “Results of Operations—Operating Income (Loss)—Other” for a consolidated discussion of general and administrative expenses.

Results for our Roseton and Danskammer facilities decreased from $53 million in 2005 to $41 million in 2006 primarily as a result of lower prices and volumes. Average on-peak prices for Zone G, the market served by these two facilities, decreased from $86 per MWh in 2005 to $78 per MWh in 2006. Generated volumes decreased from 4.7 million MWh in the nine months ended September 30, 2005 compared to 2.2 million MWh in the nine months ended September 30, 2006. Additionally, the nine months ended September 30, 2006 included mark-to-market losses of $20 million related to financial transactions not designated as cash flow hedges and a fuel oil inventory write-down of approximately $6 million. The nine months ended September 30, 2005 results included mark-to-market losses of $7 million.

Independence contributed results of $36 million for the nine months ended September 30, 2006, compared with $25 million for the period from February through September 2005. Average on-peak prices for Zone A decreased from $70 per MWh in 2005 to $60 per MWh in 2006. Generated volumes decreased from 2.2 million MWh for the nine months ended September 30, 2005 to 1.3 million MWh for the same period in 2006. Although market prices and generated volumes from our Independence facility decreased year over year, we received a benefit from the realization of higher power prices in the first half of 2006, as we settled forward power sales. The increased results also related to merchant capacity payments.

Depreciation expense for GEN-NE increased from $16 million in 2005 to $18 million in 2006, as the result of acquiring the Independence facility in February 2005.

Power Generation— South Segment. Operating loss for GEN-SO was $15 million for the nine months ended September 30, 2006, compared to an operating loss of $5 million for the nine months ended September 30, 2005. GEN-SO for the nine months ended September 30, 2005, included general and administrative expenses of $9 million. Beginning in 2006, general and administrative expenses are reported in our Other segment. Please read “Results of Operations—Operating Income (Loss)—Other” for a consolidated discussion of general and administrative expenses.

Results from our ERCOT facility decreased by $16 million from $15 million in 2005 to a loss of $1 million in 2006. Included in the 2006 results are $1 million of mark-to-market losses compared to mark-to-market income of $8 million in 2005, which relate to hedge ineffectiveness in the ERCOT region. Decreases in ancillary services revenue caused by a depressed ancillary services market in the ERCOT region during 2006 added to these losses.

Results from our other South assets increased from $6 million in the nine months ended September 30, 2005 to $12 million in the same period in 2006, primarily as a result of increased volumes in our peaking facilities.

Depreciation expense was $16 million for the nine months ended September 30, 2006 compared to $17 million for the nine months ended September 30, 2005. In addition, during the second quarter 2006, we recorded a $9 million impairment of our Rockingham facility, resulting from the pending sale. Please read Note 3—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—Rockingham for further discussion.

CRM. Operating loss for the CRM segment was $3 million for the nine months ended September 30, 2006, compared to an operating loss of $225 million for the nine months ended September 30, 2005.

Results for 2006 reflect charges of approximately $53 million in legal reserves resulting from additional activities during the period that negatively affected management’s assessment of probable and estimable losses associated with the applicable proceedings. These charges were partially offset by mark-to-market income on our legacy coal, natural gas, emissions, and power positions.

Results for 2005 were negatively impacted by a $169 million charge associated with the acquisition of Sithe Energies. Prior to the acquisition, Independence held a power tolling contract and a natural gas supply agreement with our CRM segment. Upon completion of the purchase, these contracts became intercompany agreements reported under our GEN-NE segment, and were effectively eliminated on a consolidated basis, resulting in the $169 million charge upon completion of the acquisition. In addition, this segment’s 2005 results reflect $63 million of fixed payments on our power tolling arrangements in excess of realized margins on power generated and a $29 million charge related to increased legal reserves. The increased legal reserves resulted from additional activities during the quarter that affected management’s assessment of the probable and estimable loss associated with the applicable proceedings. These losses were partly offset by a $21 million gain related to the termination of a contract to sell emissions allowances, and a net mark-to-market benefit of $14 million from our legacy gas, power and emissions positions.

Other. Other operating loss was $121 million for the nine months ended September 30, 2006, compared to a loss of $353 million for the nine months ended September 30, 2005. Results for the nine months ended September 30, 2006 include approximately $107 million of general and administrative expenses, including costs related to our business segments, which prior to first quarter 2006 were included in the individual segments. Results for the nine months ended September 30, 2005 included general and administrative expenses of $339 million.

Consolidated general and administrative expenses decreased from $421 million for the nine months ended September 30, 2005 to $160 million for the nine months ended September 30, 2006. General and administrative expenses for 2005 included a $236 million charge associated with settlement of our shareholder class action litigation and other legal settlement charges totaling $42 million, while 2006 included $55 million in additional legal reserves. Additionally, compensation and benefits costs and professional and legal fees were lower in 2006 compared to 2005.

Earnings from Unconsolidated Investments

The $6 million earnings reported from unconsolidated investments for the nine months ended September 30, 2006 included the GEN-SO investment in Black Mountain. The $14 million earnings reported for the nine months ended September 30, 2005 includes results from GEN-SO investments in both Black Mountain and West Coast Power.

Other Items, Net

Other items, net totaled $41 million of income for the nine months ended September 30, 2006, compared to $9 million of income for the nine months ended September 30, 2005. The increase is primarily associated with higher interest income in 2006 resulting from higher cash balances and higher interest rates.

Interest Expense

Interest expense and debt conversion costs totaled $559 million for the nine months ended September 30, 2006, compared to $284 million for the nine months ended September 30, 2005. The increase is primarily due to debt conversion and acceleration of financing costs, as well as a $36 million charge associated with the Sithe Subordinated Debt exchange. These charges are partially offset by reductions due to lower principal amounts outstanding as a result of our liability management program. Please read Note 7—Debt for further discussion.

Income Tax Benefit

We reported an income tax benefit from continuing operations of $154 million for the nine months ended September 30, 2006, compared to an income tax benefit from continuing operations of $228 million for the nine months ended September 30, 2005. The 2006 effective tax rate was 35%, as well as 35% in 2005.

Discontinued Operations

Income From Discontinued Operations Before Taxes. Discontinued operations include DMSLP in our NGL segment and our U.K. CRM business and U.K. natural gas storage assets in the CRM segment.

The following summarizes the activity included in income from discontinued operations:

Nine Months Ended September 30, 2006


	U.K. CRM		NGL		Total
	(in millions)
Operating income included in income from discontinued operations	$	3	$	3	$	6
Other items, net included in income from discontinued operations		2		—		2

Income from discontinued operations before taxes						8
Income tax expense						(5	)

Income from discontinued operations					$	3

Nine Months Ended September 30, 2005


	U.K. CRM			NGL			Total
	(in millions)
Operating income (loss) included in income from discontinued operations	$	(1	)	$	205		$	204
Earnings from unconsolidated investments included in income from discontinued operations		—			5			5
Other items, net included in income from discontinued operations		4			(18	)		(14	)
Interest expense included in income from discontinued operations								(40	)

Income from discontinued operations before taxes								155
Income tax benefit								54

Income from discontinued operations							$	209

We completed the sale of DMSLP on October 31, 2005 as further discussed in Note 3—Dispositions, Contract Terminations and Discontinued Operations— Discontinued Operations—Natural Gas Liquids. As a result of the sale, and as required by SFAS No. 144, we have reclassified the operations related to DMSLP, which comprised of the remaining operations of our NGL segment, from continuing operations to discontinued operations.

During the nine months ended September 30, 2006, pre-tax income from discontinued operations of $8 million ($3 million after-tax) included a pre-tax gain of $6 million associated a receivable previously reserved in our U.K. CRM business. During the nine months ended September 30, 2005, pre-tax income from discontinued operations of $155 million ($209 million after-tax) included $152 million in pre-tax income attributable to NGL.

In accordance with EITF Issue 87-24, we have allocated interest expense to discontinued operations associated with debt instruments that were required to be paid upon the sale of DMSLP. Interest expense included in income from discontinued operations, which includes interest incurred on our former term loan and our former Generation facility debt, totaled zero and $40 million during the nine months ended September 30, 2006 and 2005, respectively.

Income Tax Benefit From Discontinued Operations. We recorded an income tax expense from discontinued operations of $5 million during the nine months ended September 30, 2006, compared to an income tax benefit from discontinued operations of $54 million during the nine months ended September 30, 2005. The income tax benefit in 2005 includes a $112 million benefit associated with reducing a valuation allowance related to our capital loss carryforward, which primarily relates to our third quarter 2002 sale of NNG. We reduced the valuation allowance related to our capital loss carryforward as a result of capital gains expected to be recognized from our sale of DMSLP. For further information regarding the sale, please see Note 3— Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Natural Gas Liquids. The effective rates for the nine months ended September 30, 2006 and 2005, adjusting for the reduction of the valuation allowance in 2005, are 63% and 37%, respectively. FIN No. 18 proscribes 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%.

Outlook

In September 2006, we and the LS Entities announced an agreement to combine the operating assets of both entities into a diversified operating portfolio upon receipt of all required approvals. The combination will yield a more robust portfolio than either entity possesses currently. Our current portfolio consists primarily of baseload coal assets in GEN-MW and GEN-NE and natural gas-fired peaking assets throughout GEN-MW and GEN-SO. In addition to the volumes committed under the contracts resulting from the Illinois auction and power and steam delivery commitments from our Independence and Lyondell facilities, the output from our facilities is available for other forward sales opportunities to capture attractive market prices. 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 and power

commodity markets. The only intermediate (combined cycle) assets in our current portfolio are the Independence and Lyondell natural gas-fired facilities. The LS Entities’ portfolio consists primarily of natural gas fired intermediate (combined cycle) assets with a significant portion of the output committed under multi-year power purchase agreements or hedged through financial agreements. The LS Entities’ portfolio includes significant generating capacity located in the Western Electricity Coordinating Council NERC region, a region that is expected to continue to experience demand growth but in which we currently own no generating assets. The combination will result in a more balanced portfolio geographically and in terms of fuel type and dispatch characteristics.

The following summarizes our outlook for our current power generation business and our customer risk management business.

Power Generation Business. Generally, we expect that future financial results will continue to reflect sensitivity to fuel and emissions commodity prices, market structure and prices for energy, ancillary services and capacity, transportation and transmission logistics, weather conditions and in-market asset availability (“IMA”). Our commercial team actively manages price risk associated with our power length by entering into forward sales in the prompt one to three months. Decisions regarding longer term forward sales opportunities to capture attractive market prices are made by the executive management team. 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 of the commodity price movement.

GEN- MW. We expect our results to continue to be impacted by (i) power prices, (ii) IMA of our assets and (iii) fuel availability and prices. A significant power sales agreement with AmerenIP will be expiring at the end of 2006. Although we expect wholesale power prices to continue to remain higher than the price we receive under our existing agreement with AmerenIP for the remainder of 2006, we will not be able to fully realize these prices as a result of the options held by AmerenIP in our fixed price power purchase agreement with them. We will continue to benefit from prevailing market prices for those volumes in excess of the maximum quantity Ameren can call under our current agreement. Additionally, any volumes below this maximum for which Ameren does not exercise its right to require delivery will also be available for sale at prevailing market prices.

Beyond 2006, GEN-MW results will be affected by the expiration of this power purchase agreement and delivery obligations resulting from our participation in the Illinois Resource Procurement auction. We participated in the Illinois Resource Procurement auction in September 2006 and were awarded contracts for delivery of up to 1,200 MW into the AmerenIP portion of the auction for the time period from January 1, 2007 through May 31, 2008 and up to an additional 200 MW for the time period from January 1, 2007 through May 31, 2009. The volumes we expect to deliver under the resulting agreements are significantly less than the maximum volumes AmerenIP can call under our current agreement. AmerenIP will continue to have similar volumetric options as they have under our current PPA. The power commodity price under the auction related agreements is higher than exists under our current contract as are Dynegy’s costs to manage deliveries. All other volumes which we produce will be exposed to prevailing market pricing. We anticipate that the revenues generated by our Midwest facilities will improve significantly beginning in 2007 with 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 beyond 2006 will be the regulatory environment in Illinois. Within the Illinois political arena, there continues 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 11—Regulatory Issues—Illinois Resource Procurement Auction for further details.

Our IMA will also impact GEN-MW’s results. We use IMA to monitor steam fleet performance over time. This measure quantifies the percentage of generation for each unit that was available when market prices were favorable for participation. IMA is calculated on a unit specific basis as a ratio of dispatchable capacity actually available during periods when each unit is scheduled to be available and the megawatt hours resulting from the capacity of each facility multiplied by the hours when the market pricing for electricity and fuel and the variable costs to operate indicate each unit can be profitably dispatched. 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 steam-driven fleet through September 2006 was approximately 88%, compared to 90.4% for the comparable period of 2005. 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 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 September 30, 2006, DMG had achieved all of the scheduled emission reductions and was developing plans to install additional emission control equipment to meet future, more stringent emission limits. DMG recently received a construction permit for the 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 2013, have increased from a previously reported amount of $611 million to an estimated $674 million. Factors contributing to this growth are increased costs associated with the Vermilion Mercury Control Project and the anticipated cost of adding additional particulate control equipment at the Hennepin Station. Another major component of the increase is large commodity cost-escalations for raw materials (steel, cement and copper) required for the scrubbers and baghouses. These supply-side market pressures will continue to subject the final cost of Consent Decree compliance to cost volatility.

We have diligently worked with our rail service provider to decrease our risk of delivery-related disruptions, including the re-deployment of existing rail assets and coal supplies in an opportunistic fashion to provide coal deliveries to our highest margin plants to allow full economic dispatch during peak demand. At this time, we believe that the core issues which created the delivery uncertainty are resolved and our ability to maintain or build coal inventory at each of our coal-fired facilities continues to be sufficient to meet forecast requirements.

Through 2010, 96% of our Midwest coal requirements are contracted. Additionally, 100% of our coal requirements for 2006 and more than half of our coal requirements through 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.

During 2005, our results reflected increased demand for capacity-related products from our peaking generation facilities. In addition, we benefited from operation of all of our peaking plants at certain times during the summer months of 2005. We experienced comparable dispatch opportunities this past summer as each of our peaking facilities experienced some level of economic dispatch, as a result of weather driven market demand.

GEN-NE. We expect commodity fuel prices and market prices for energy and capacity to continue to be strong, although current forward prices are lower than forward market highs seen in the fall of 2005. Spreads are expected to remain volatile as fuel prices change.

Our results are also dependent on our ability to maintain coal and oil deliveries to the facilities. We have recently completed negotiations to continue coal deliveries through 2007 with existing suppliers for our Northeast coal requirements. With the completion of the agreements, we have now secured all of our expected 2007 coal supply requirements and a portion of our 2008 coal supply requirements for our Danskammer facility.

Additionally, our results could be affected by potential changes in environmental regulations in the State of New York, as well as our ability to obtain permits necessary for the operation of our facilities. For further discussion of these matters, Please read Note 10—Commitments and Contingencies—Roseton State Pollutant Discharge Elimination System Permit and Note 10—Commitments and Contingencies— Danskammer State Pollutant Discharge Elimination System Permit.

GEN-SO. We entered into various agreements in September 2005 extending the steam and energy sales component of an ongoing relationship to 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 Chemical Company (“Lyondell”) for an initial term from January 2007 through December 2021 and subsequent automatic rollover terms of two years each

thereafter through December 2046. Incremental annual operating income associated with this contract is expected to range between $40 million to $55 million. The primary drivers of this improvement are the adjustment to the price of steam supplied to Lyondell and our ability to optimize power and steam generation for the entire Lyondell facility to capture maximum market potential from the CoGen Lyondell cogeneration facility.

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. We continue to pursue opportunities to sell additional capacity from these facilities as well as our Lyondell cogeneration facility. We expect opportunities for capacity sales will develop at times during the year. However, due to the regulated, non-liquid market in the southeast region, our results will continue to be impacted by our ability to complete additional sales to a limited pool of buyers for these products and as a result, we anticipate capacity pricing in the South region will lag the remainder of the country.

CRM. Our CRM business segment’s future results of operations will be impacted by our ability to complete our exit from this business. Our CRM business remains a party to certain legacy natural gas, power and emission transactions, most of which have been hedged. Although we continue to work diligently to minimize the financial impact of the CRM segment, we expect to continue to incur cash outflows associated with these legacy transactions. We are proactively working with our customers to exit the remainder of our obligations on economically favorable terms.

Cash Flow Disclosures

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


	Nine Months Ended September 30,
	2006			2005
	(in millions)
Operating cash flows from our generation businesses	$	503		$	354
Operating cash flows used in our customer risk management business		(370	)		(64	)
Operating cash flows from our natural gas liquids business		—			241
Other operating cash flows		(313	)		(709	)

Net cash used in operating activities	$	(180	)	$	(178	)

Operating Cash Flow. Our cash flow used in operations totaled $180 million for the nine months ended September 30, 2006. During the nine months ended September 30, 2006, our power generation business provided positive cash flow from operations of $503 million primarily due to positive earnings for the period. Our customer risk management business used approximately $370 million in cash primarily due to a $370 million termination payment on our Sterlington tolling contract. Please read Note 3—Dispositions, Contract Terminations and Discontinued Operations— Dispositions and Contract Terminations—Sterlington Contract Termination for further information. Other and Eliminations includes a use of approximately $313 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.

Our cash flow used in operations totaled $178 million for the nine months ended September 30, 2005. During the period, our GEN and NGL segments provided positive cash flow from operations. GEN provided cash flow from operations of $354 million, and NGL provided cash flow from operations of $241 million primarily due to positive earnings for the period as well as the return of cash collateral. Our CRM segment used approximately $64 million in cash primarily due to fixed payments associated with power tolling arrangements and our final payment of

$26 million related to our exit from certain natural gas transportation contracts, offset by the return of cash collateral. Other and Eliminations includes a use of approximately $709 million in cash primarily due to our payments of $255 million in 2005 in connection with the settlement of the shareholder class action litigation, interest payments to service debt, pension plan contributions, state tax payments and general and administrative expenses.

Capital Expenditures and Investing Activities. Cash provided by investing activities during the nine months ended September 30, 2006 totaled $213 million. Capital spending of $92 million was primarily comprised of $58 million, $12 million, and $16 million in the GEN-MW, GEN-NE, and GEN-SO segments, respectively. The capital spending for each segment primarily related to maintenance and environmental capital projects. In addition, there was approximately $6 million of capital expenditures in the Other segment.

Proceeds from the sale and acquisition of unconsolidated investments, net of cash acquired, totaled $165 million. This included net cash proceeds of $205 million from the sale of our 50% ownership interest in West Coast Power to NRG. Please read Note 3—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—West Coast Power for further information. This was partially offset by a payment of $45 million for our acquisition of NRG’s 50% ownership interest in Rocky Road, which included $5 million of cash on hand. Please read Note 2—Business Combinations—Rocky Road for more information.

Proceeds from assets sales, net totaled $18 million and primarily consisted of proceeds from the sale of a gas turbine not in use.

The decrease in restricted cash of $125 million related primarily to the return of our $335 million deposit associated with our former cash collateralized facility, offset by a $200 million deposit associated with our cash collateralized facility and a $10 million increase in the Independence restricted cash balance.

Cash used in investing activities during the nine months ended September 30, 2005 totaled $172 million. Capital spending of $132 million was primarily comprised of $74 million, $11 million, $2 million and $39 million in the GEN-MW, GEN-NE, GEN-SO and NGL segments, respectively. The capital spending for the generation business segments primarily related to maintenance capital projects, as well as $10 million in development capital associated with the completion of the Havana PRB conversion in GEN-MW. Capital spending in our NGL segment primarily related to maintenance capital projects and wellconnects. The cost to acquire Sithe Energies, net of cash proceeds, totaled $120 million. Proceeds from asset sales consisted of a $5 million payment to Ameren associated with the working capital adjustment related to the sale of Illinois Power.

Financing Activities. Cash used in financing activities during the nine months ended September 30, 2006 totaled $1,094 million. Repayments of long-term debt totaled $1,780 million for the nine months ended September 30, 2006 and consisted of the following payments:

•

$900 million in aggregate principal amount on our 10.125% Second Priority Senior Secured Notes due 2013;

•

$614 million in aggregate principal amount on our 9.875% Second Priority Senior Secured Notes due 2010;

•

$225 million in aggregate principal amount on our Second Priority Senior Secured Floating Rate Notes due 2008;

•

$23 million in aggregate principal amount on our 7.45% Senior Notes due 2006; and

•

$18 million in aggregate principal amount on our 8.50% secured bonds due 2007.

In addition to the above repayments, we redeemed all of the outstanding shares of our Series C Preferred for $400 million.

Debt conversion costs of $249 million consisted of the following payments:

•

$204 million to redeem the Second Priority Senior Secured Notes mentioned above, including approximately $3 million of transaction costs;

•

$44 million aggregate premium to induce conversion of our $225 million 4.75% Convertible Subordinated Debentures due 2023; and

•

$1 million in transaction costs associated with the redemption of our Series C Preferred.

The repayments were partially offset by $1,071 million of proceeds from the following sources, net of approximately $29 million of debt issuance costs:

•

$750 million aggregate principal amount from a private offering of our 8.375% Senior Unsecured Notes due 2016;

•

$200 million, LIBOR + 1.75% letter of credit facility due 2012; and

•

$150 million, LIBOR + 1.75% term loan due 2012.

Proceeds from the issuance of common stock consisted primarily of approximately $178 million in proceeds from a common stock offering of 40.25 million shares of our Class A common stock at $4.60 per share, net of underwriting fees. Dividend payments totaling $17 million were also made on our Series C Preferred prior to its redemption.

Cash used in financing activities during the nine months ended September 30, 2005 totaled $73 million. Repayments of long-term debt totaled $40 million for the nine months ended September 30, 2005 and consisted of the following: (i) payments of $18 million on a maturing series of DHI senior notes; (ii) payments of $17 million on the Independence Senior Notes due 2007 and (iii) payments of $5 million on DHI’s Term Loan. Cash used in financing activities also includes a semi-annual dividend payments of $22 million on our Series C Preferred.

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 Nine Months Ended September 30, 2006
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2006	$	(112	)
Risk-management gains recognized through the income statement in the period, net		28
Cash received related to risk-management contracts settled in the period, net		(17	)
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other (2)		96

Fair value of portfolio at September 30, 2006	$	(5	)

(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 $5 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 September 30, 2006 and December 31, 2005. 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			2006 (3)			2007			2008			2009			2010		Thereafter
	(in millions)
September 30, 2006 (2)	$	(60	)	$	5		$	(65	)	$	(4	)	$	—		$	—	$	4
December 31, 2005 (2)		(84	)		(5	)		(65	)		(19	)		2			—		3

Increase (decrease)	$	24		$	10		$	—		$	15		$	(2	)	$	—	$	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 September 30, 2006 of $5 million on the unaudited condensed consolidated balance sheets include the $60 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 September 30, 2006 and December 31, 2005 were derived solely from market quotations.

(3)	Amounts represent October 1 to December 31, 2006 values in the September 30, 2006 row and January 1 to December 31, 2006 values in the December 31, 2005 row.

Cash Flow Components of Net Risk-Management Asset


	Nine Months Ended September 30, 2006			Three Months Ended December 31, 2006		Total 2006		2007			2008			2009			2010		Thereafter
	(in millions)
September 30, 2006(1)	$	(1	)	$	6	$	5	$	(66	)	$	(5	)	$	—		$	—	$	6
December 31, 2005							1		(64	)		(21	)		2			—		4

Increase (decrease)						$	4	$	(2	)	$	16		$	(2	)	$	—	$	2

(1)

The cash flow values for 2006 reflect realized cash flows for the nine months ended September 30, 2006 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.

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:

•

expectations and beliefs related to the combination with LS Entities including satisfying closing conditions and obtaining shareholder and regulatory approvals;

•

expected synergies resulting from the combination with the LS Entities and beliefs associated with the integration of operations of both companies;

•

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

•

expectations regarding capital expenditures, interest expense and other payments;

•

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 while reducing our long-term hedging activities;

•

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

•

beliefs and assumptions relating to our liquidity position;

•

strategies to address our substantial leverage, to access the capital markets, or to obtain additional financing or 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 recovery of the wholesale power generation market;

•

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

•

beliefs about the outcome of legal and administrative proceedings, including the matters involving the western power and natural gas markets, environmental matters and the investigations primarily relating to our past trading practices;

•

assumptions about prospective regulatory developments, including those associated with and resulting from the Illinois auction;

•

expectations regarding environmental matters, including costs of compliance and availability and adequacy of emission credits;

•

strategies to remediate the material weaknesses existing in our accounting for income taxes and our risk management assets and liabilities;

•

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

•

positioning our power generation business for future growth and pursuing and executing acquisition or combination opportunities; and

•

our ability to complete our exit from the customer risk management business and the costs associated with this exit.

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—Accounting Policies 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 40 of our Form 10-K/A 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/A.

Item 3—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Please read Item 7A. Quantitative and Qualitative Disclosures About Market Risk beginning on page 85 of our Form 10-K/A for a discussion of our exposure to commodity price variability and other market risks, including foreign currency exchange rate risk. Following is a discussion of the more material of these risks and our relative exposures as of September 30, 2006.

Value at Risk. 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 and CRM segments.

Daily and Average VaR for Risk-Management Portfolios

Credit Risk. The following table represents our credit exposure at September 30, 2006 associated with the mark-to-market portion of our risk-management portfolio, on a net basis.

Credit Exposure Summary


	Investment Grade Quality		Non-Investment Grade Quality		Total
	(in millions)
Type of Business:
Financial Institutions	$	51	$	—	$	51
Commercial/Industrial/End Users		—		—		—
Utility and Power Generators		42		4		46
Crude Oil and Natural Gas Producers		—		—		—

Total	$	93	$	4	$	97

Of the $4 million in credit exposure to non-investment grade counterparties, 55% is collateralized or subject to other credit exposure protection.

Interest Rate Risk. We are exposed to fluctuating interest rates related to variable rate financial obligations. As of September 30, 2006, our fixed rate debt instruments as a percentage of total debt instruments was approximately 79%. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of September 30, 2006, 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 September 30, 2007 would either decrease or increase income before taxes by approximately $9 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.

Derivative Contracts. The notional financial contract amounts associated with our commodity risk-management, interest rate and foreign currency exchange contracts were as follows at September 30, 2006 and December 31, 2005, respectively:

Absolute Notional Contract Amounts


	September 30, 2006		December 31, 2005
Natural Gas (Trillion Cubic Feet)		0.310		0.374
Electricity (Million Megawatt Hours) (1)		94.567		30.479
Emission Credits (Million Tons) (2)		0.031		0.043
Net Fair Value Hedge Interest Rate Swaps (In Millions of U.S. Dollars)	$	525	$	525
Fixed Interest Rate Received on Swaps (Percent)		4.331		4.331
Interest Rate Risk-Management Contract (In Millions of U.S. Dollars)	$	231	$	306
Fixed Interest Rate Paid (Percent)		5.35		5.29
Interest Rate Risk-Management Contract (In Millions of U.S. Dollars)	$	206	$	281
Fixed Interest Rate Received (Percent)		5.28		5.23

(1)	This amount includes notional volumes related to additional Financial Transmission Rights (FTRs) that we acquired in various ISOs during 2006.

(2)	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 15(d)-15(e) under the Exchange Act). This evaluation included consideration of the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified by the SEC. This evaluation also considered the work completed as of the end of the third quarter 2006 relating to our compliance with Section 404 of the Sarbanes-Oxley Act of 2002.

Based on this evaluation, our CEO and CFO concluded that, as of September 30, 2006, as a result of the material weaknesses identified and discussed below, our disclosure controls and procedures were not effective to ensure that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the requisite time periods.

Notwithstanding the material weaknesses that existed at September 30, 2006, management believes, based on its knowledge, that the financial statements, and other financial information included in this report, fairly present in all material respects in accordance with GAAP our financial condition, results of operations and cash flows as of, and for, the periods presented in this report.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of our annual or interim financial statements would not be prevented or detected. We have identified the following material weaknesses:

Material Weakness Related to Income Taxes

As of December 31, 2005 and September 30, 2006, we did not maintain effective controls over the completeness and accuracy of the tax provision and deferred income tax balances in accordance with GAAP. Specifically, our processes, procedures and controls related to the preparation, analysis and recording of the income tax provision were not effective to ensure that the tax provision and deferred tax balances were recorded in accordance with GAAP. This control deficiency resulted in the restatement of our 2004 and 2003 annual consolidated financial statements, as well as audit adjustments to the 2005 income tax provision. This control deficiency also resulted in the restatement of the 2005 consolidated financial statements as reported in our Annual Report on Form 10-K/A. Further, this control deficiency could result in a misstatement of the income tax provision and related deferred tax accounts and disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Therefore, as of December 31, 2005 and September 30, 2006, we concluded that this control deficiency constitutes a material weakness.

Status of Remediation of Material Weakness Related to Income Taxes. During 2005, the following steps were taken to improve our internal controls around our tax accounting and tax reconciliation processes, procedures and controls: (i) increased levels of review in the preparation of the quarterly and annual tax provisions; (ii) formalized processes, procedures and documentation standards relating to the income tax provision; and (iii) restructured our Tax Department to ensure appropriate segregation of duties regarding preparation and review of the quarterly and annual tax provision. Despite these efforts, when making management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005, we determined that those controls were still not operating effectively.

In addition to continuing the enhanced processes implemented in 2005 and described above, during the second and third quarters of 2006, we implemented the following steps in an attempt to remediate the material weakness reported at December 31, 2005: (i) implemented new processes around the analysis of the income tax provision, including detailed reconciliations between book basis and tax basis of significant tax sensitive balance sheet accounts; (ii) implemented additional procedures around identifying, analyzing and recording the tax effects of significant transactions; (iii) formalized communication channels between the Tax and Accounting Departments, and (iv) enhanced the competencies of our Tax Department personnel through the addition of experienced tax professionals. We are also in the process of implementing the following steps: (i) further formalizing and documenting the procedures around the preparation and review of the tax provision and tax accounts; (ii) enhancing the competencies and capabilities of our Tax Department personnel through ongoing formal training initiatives in key tax-related areas and (iii) simplifying the data entry process surrounding the automated tax provision calculation. Finally, we also engaged an independent consulting firm, which has assessed and provided recommendations to strengthen our processes and procedures.

We believe we are taking the steps necessary to remediate this material weakness relating to our tax accounting and tax reconciliation processes, procedures and controls. However, certain of the corrective processes, procedures and controls relate to annual controls that cannot be tested until the preparation of our 2006 annual tax provision. Accordingly, we will continue to vigorously monitor the effectiveness of these processes, procedures and controls and will make any further changes management determines are necessary. We will not be able to conclude that this material weakness has been successfully remediated, and we cannot assure you we will be able to make such conclusion, until management’s testing and assessment demonstrates that such controls have operated effectively for a sufficient period of time.

Material Weakness Related to Risk Management Assets and Liabilities

As of September 30, 2006, we did not maintain effective controls over the accuracy of our risk management asset and liability balances. Our processes, procedures and controls related to the calculation and analysis of applicable pricing data were not effective to ensure that the risk management asset and liability balances were accurately reflected in the financial statements. This control deficiency resulted in an adjustment to the first quarter 2006 interim condensed consolidated financial statements prior to being reported in our Quarterly Report on Form 10-Q for the interim period ended March 31, 2006. Further, this control deficiency could result in a misstatement of revenue and the related risk management asset and liability balances that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Therefore, as of September 30, 2006, we concluded that this control deficiency constitutes a material weakness.

Status of Remediation of Material Weakness Related to Risk Management Assets and Liabilities. In order to remediate this material weakness, during the second and third quarters 2006, we implemented the following steps around our risk management asset and liability valuation process: (i) automated a process step that was previously performed manually; (ii) further formalized and documented the procedures around the end-of-day valuation process; (iii) expanded the review and validation process with respect to pricing data; (iv) performed a review of all pricing data to eliminate redundant or unnecessary data; (v) implemented a new monthly process to identify pricing data related to active positions; and (vi) further restricted access to and assigned accountability for process documentation. We also engaged an independent third party to review, evaluate and test our processes, procedures and controls related to the calculation and analysis of pricing data. This review was completed in the third quarter 2006, and the resulting recommendations did not require significant changes to our current procedures or controls.

We believe we have taken the steps necessary to remediate this material weakness related to the accuracy of our risk management asset and liability balances. However, the controls have not been in place for an adequate period of time to test and conclude that they are operating effectively and that the material weakness has been remediated. Accordingly, we will continue to vigorously monitor the effectiveness of these processes, procedures and controls and will make any further changes management determines are necessary.

Changes in Internal Control Over Financial Reporting

The changes discussed above in the Item 4 were changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of our internal control performed during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. There were no other changes in our internal control over financial reporting during the quarter ended September 30, 2006.

DYNEGY INC.

PART II. OTHER INFORMATION

Item 1—LEGAL PROCEEDINGS

See Note 10—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

Item 1A. Risk Factors beginning on page 23 of our 2005 Form 10-K, page 56 of our first quarter 2006 Form 10-Q and page 72 of our second quarter 2006 Form 10-Q includes a detailed discussion of our risk factors. The information presented below updates, and should be read in conjunction with, the risk factors and information disclosed in our 2005 Form 10-K and first and second quarter 2006 Form 10-Qs.

The Merger Agreement with the LS Entities and related transactions, regardless of whether they are ultimately consummated, have presented and will continue to present us with certain risks and uncertainties, and have imposed and will continue to impose on us and our business and operations certain restrictions and significant financial and other costs. In addition, if the Merger Agreement and related transactions are ultimately consummated, the expected benefits of the Merger Agreement and related transactions may not be realized in a timely or efficient manner or at all, and the LS Entities, by virtue of their stock ownership of New Dynegy, will have significant influence over New Dynegy’s business and operations and may have interests that differ from, and conflict with, the interests of our shareholders.

The consummation of the Merger Agreement with the LS Entities and related transactions is subject to the approval of our shareholders and is conditioned upon our and the LS Entities’ receipt of various approvals, consents and clearances from various governmental and regulatory entities. We cannot assure you that we and the LS Entities will receive these approvals, consents and clearances in a timely manner or at all and, as a result, we cannot assure you that the Merger Agreement and related transactions will be consummated in a timely manner or at all. Moreover, a substantial delay in obtaining these approvals, consents and clearances or the imposition of unfavorable terms or conditions in connection with obtaining such approvals, consents and clearances could have a material adverse effect on our and/or New Dynegy’s business, financial condition and results of operations and may cause us and/or the LS Entities to abandon the Merger Agreement and related transactions. In addition, the Merger Agreement restricts us, without the LS Entities’ consent, from taking certain specified actions until the Merger Agreement is consummated or terminated. These restrictions may prevent us from pursuing otherwise attractive business opportunities and effecting other beneficial transactions and changes to our business and operations prior to the consummation or termination of the Merger Agreement.

We entered into the Merger Agreement with the LS Entities with the expectation that the combination of our business and operations with the business and operations of the power generation entities to be contributed by the LS Entities pursuant to the Merger Agreement would result in various benefits, including, among other things, certain synergies, cost savings and operating efficiencies. Although we expect these and other anticipated benefits of the Merger Agreement and related transactions to be realized, we cannot assure you that such benefits will be realized in a timely manner, in full or at all.

In addition, we have incurred and expect to continue to incur significant costs in connection with consummating the Merger Agreement and related transactions. We also expect to incur, upon the consummation of the Merger Agreement and related transactions, costs in connection with integrating our operations and procedures with the operations and procedures of the power generation entities to be contributed by the LS Entities. Although we believe that the realization of certain synergies, cost savings and operating efficiencies related to the integration of our business with that of the power generation entities to be contributed by the LS Entities will offset these costs over time, we cannot assure you that this benefit will be realized in a timely manner, in full or at all.

If the Merger Agreement and related transactions are consummated, we will face significant challenges in integrating, in a timely and efficient manner, our operations and procedures with the operations and procedures of the power generation entities to be contributed by the LS Entities. As a result, we cannot assure you that the integration will be completed in a timely or efficient manner. In addition, such integration efforts could also divert our management’s focus and resources from our and, subsequent to the consummation of the Merger Agreement, New Dynegy’s day-to-day business and operations. Such diversion of our management’s focus and resources could have a material and adverse effect on our and, subsequent to the consummation of the Merger Agreement, New Dynegy’s business, financial condition and results of operations.

Furthermore, subsequent to the consummation of the Merger Agreement and related transactions, the LS Entities will own approximately 40% of the voting power of New Dynegy and will have the right to nominate up to three members of the 11-member board of directors of New Dynegy. By virtue of such stock ownership and board representation, the LS Entities will have the power to influence New Dynegy’s affairs as well as the outcome of matters submitted to a vote of New Dynegy’s stockholders. Moreover, the LS Entities may have interests that differ from, and conflict with, those of our shareholders, who will be holders of New Dynegy’s common stock upon the consummation of the Merger Agreement and related transactions.

If we issue a material amount of our common stock in the future or certain of our shareholders sell a material amount of our common stock, we could be subject to an annual limitation on the utilization of our net operating losses (NOLs) and alternative minimum tax (AMT) credits under Sections 382 and 383 of the Internal Revenue Code.

If we were to undergo an “ownership change” within the meaning of Section 382 of the Internal Revenue Code (the “Code”), an annual limitation could be imposed against our utilization of previously incurred NOLs against future taxable income or existing AMT credits against future tax liability. In general, an ownership change occurs whenever there is more than a 50% change in the ownership of the stock of a corporation, taking into account all cumulative changes in ownership over the preceding three years.

More specifically, depending on prevailing interest rates and our market value 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 NOLs against the total future taxable income of a given year or full utilization of our AMT credits against the total future tax liability of a given year. The annual limitation would not affect the expiration dates of our NOLs, which, under current law, begin to expire in 2022; AMT credits do not expire. The consummation of the Merger Agreement and related transactions with the LS Entities will increase the likelihood that previously incurred NOLs and AMT credits will become subject to the limitations set forth in Sections 382 and 383 of the Code. Avoiding such an ownership change may limit our ability and, subsequent to the consummation of the Merger Agreement and related transactions (if consummated), New Dynegy’s ability to raise additional equity capital in the near future.

The magnitude of such limitations and their effect on us and, subsequent to the consummation of the Merger Agreement and related transactions (if consummated), their effect on New Dynegy, is difficult to assess and may depend in part on our or New Dynegy’s (as the case may be) value at the time of any such ownership change and prevailing interest rates. For accounting purposes, at December 31, 2005, our net operating loss deferred tax asset attributable to our previously incurred NOLs was valued at approximately $198 million and our AMT credits were valued at approximately $256 million.

We have reported two material weaknesses in our internal control over financial reporting, one of which caused a restatement, and both of which, if not remedied, could continue to adversely affect our internal controls and financial reporting.

In connection with our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005, our management concluded that, as of December 31, 2005, we did not maintain effective internal control over our financial reporting due to a material weakness in our processes, procedures and controls related to the preparation, analysis and recording of the income tax provision. Our management’s

assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 was audited by PricewaterhouseCoopers LLP, which expressed an unqualified opinion on management’s assessment and an adverse opinion on the effectiveness of our internal control over financial reporting as of December 31, 2005.

Likewise, in connection with our management’s assessment of the effectiveness of our internal control over financial reporting as of September 30, 2006, our management concluded that, as of September 30, 2006, we did not maintain effective internal control over our financial reporting due to the same material weakness in our processes, procedures and controls related to the preparation, analysis and recording of the income tax provision. Also in connection with our management’s assessment as of September 30, 2006, our management concluded that, as of September 30, 2006, we did not maintain effective internal control over our financial reporting due to a material weakness in our processes, procedures and controls related to the calculation and analysis of our risk management asset and liability balances. A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of our annual or interim financial statements would not be prevented or detected.

We previously reported in our Annual Report on Form 10-K, as amended, for the fiscal year ended December 31, 2004 that we did not maintain effective internal control over our financial reporting as of December 31, 2004 due to a material weakness in our processes, procedures and controls related to the preparation, analysis and recording of the income tax provision. During 2005, actions were taken to remediate this material weakness. Despite these efforts, when making management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005, we determined that those processes and controls were still not operating effectively. This control deficiency resulted in the restatement of our 2004 and 2003 annual consolidated financial statements, as well as year-end audit adjustments to the 2005 income tax provision. This control deficiency also resulted in the restatement of our consolidated financial statements for the year ended December 31, 2005, as reported in Amendment No. 1 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2005. Further, this control deficiency could have resulted in a misstatement of the income tax provision and related deferred tax accounts and disclosures that would result in a material misstatement to our annual or interim consolidated financial statements that would not be prevented or detected.

The material weakness related to the calculation and analysis of our risk management asset and liability balances resulted in an adjustment to our condensed consolidated financial statements as of and for the three months ended March 31, 2006 prior to being reported in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2006. Further, this control deficiency could result in a misstatement of revenue and the related risk management asset and liability balances that would result in a material misstatement to our annual or interim consolidated financial statements that would not be prevented or detected.

We believe we are taking the steps necessary to remediate the material weakness relating to our tax accounting and tax reconciliation processes, procedures and controls. However, certain of the corrective processes, procedures and controls relate to annual controls that cannot be tested until the preparation of our 2006 annual tax provision. We also believe we are taking the steps necessary to remediate the material weakness related to the accuracy of our risk management asset and liability balances. However, the controls have not been in place for an adequate period of time to test and conclude that they are operating effectively. Accordingly, in each case, we will continue to vigorously monitor the effectiveness of these processes, procedures and controls and will make any further changes management determines are necessary; however, we cannot assure you that these processes, procedures and controls will result in full remediation of the two material weaknesses described above. Failure to remediate these material weaknesses, or the identification of one or more additional material weaknesses, could result in materially inaccurate financial reports and negatively impact the market’s view of our control environment and, potentially, our stock price.

Item 6—EXHIBITS

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


Exhibit Number		Description

2.1		Plan of Merger, Contribution and Sale Agreement dated September 14, 2006 by and among Dynegy Inc., LSP Gen Investors, LP, LS Power Partners, LP, LS Power Equity Partners PIE I, L.P., LS Power Equity Partners, L.P., LS Power Associates, L.P., Falcon Merger Sub Co. and Dynegy Acquisition, Inc. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).

2.2		Limited Liability Company Membership Interests and Stock Purchase Agreement dated as of September 14, 2006, among LS Power Associates, L.P., LS Power Equity Partners, L.P., LS Power Equity Partners PIE I, L.P., LS Power Partners, L.P. and Kendall Power LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).

4.1		Registration Rights Agreement, effective as of July 21, 2006, by and among Dynegy Holdings Inc., RCP Debt, LLC and RCMF Debt, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on July 24, 2006, File No. 1-15659).

4.2		Shareholder Agreement dated as of September 14, 2006 among Dynegy Acquisition, Inc. and LS Power Partners, L.P., LS Power Associates, L.P., LS Power Equity Partners, L.P., LS Power Equity Partners PIE I, L.P. and LSP Gen Investors, L.P. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).

4.3		Registration Rights Agreement dated as of September 14, 2006 among Dynegy Acquisition, Inc., LS Power Partners, L.P., LS Power Associates, L.P., LS Power Equity Partners, L.P., LS Power Equity Partners PIE I, L.P. and LSP Gen Investors, L.P. (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).

4.4		Registration Rights Agreement dated as of September 14, 2006 among Dynegy Acquisition, Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).

4.5		Registration Rights Agreement dated as of September 14, 2006 among Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.4 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).

4.6		Lock-Up Agreement dated as of September 14, 2006 by and among LSP Gen Investors, LP, LS Power Partners, LP, LS Power Associates, L.P., LS Power Equity Partners PIE I, LP, LS Power Equity Partners, L.P. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.5 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).

10.1		Exchange Agreement, dated as of July 21, 2006, by and among Dynegy Holdings Inc., RCP Debt, LLC and RCMF Debt, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on July 24, 2006, File No. 1-15659).


10.2		Amendment No. 2, dated as of July 11, 2006, to the Fourth Amended and Restated Credit Agreement, dated as of April 19, 2006, among Dynegy Holdings Inc., as borrower, Dynegy Inc., as parent guarantor, the other guarantors party thereto, the lenders party thereto and the various other parties thereto (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q of Dynegy Inc. for the quarterly period ended June 30, 2006 filed on August 10, 2006, File No. 1-15659).

10.3		Voting Agreement dated as of September 14, 2006 by and among LSP Gen Investors, LP, LS Power Partners LP, LS Power Associates, L.P., LS Power Equity Partners PIE I, LP, LS Power Equity Partners, L.P. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).

10.4		Voting Agreement dated as of September 14, 2006 by and among LS Power Associates, L.P., LSP Gen Investors, LP, LS Power Equity Partners PIE I, LP, LS Power Equity Partners, L.P., LS Power Partners, LP and Bruce A. Williamson, Stephen A. Furbacher, Holli C. Nichols, Lynn A. Lednicky and J. Kevin Blodgett (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).

10.5		Corporate Opportunity Agreement dated as of September 14, 2006 between Dynegy Acquisition, Inc. and LS Power Development, LLC (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).

10.6		BGS-FP Supplier Forward Contract by and between Dynegy Power Marketing, Inc., Central Illinois Light Company d/b/a AmerenCILCO, Central Illinois Public Service Company d/b/a AmerenCIPS and Illinois Power Company d/b/a AmerenIP dated September 20, 2006 (Term through May 31, 2008) (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 25, 2006, File No. 1-15659).

10.7		BGS-FP Supplier Forward Contract by and between Dynegy Power Marketing, Inc., Central Illinois Light Company d/b/a AmerenCILCO, Central Illinois Public Service Company d/b/a AmerenCIPS and Illinois Power Company d/b/a AmerenIP dated September 20, 2006 (Term through May 31, 2009) (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 25, 2006, File No. 1-15659).

**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 Securities Act.

DYNEGY INC.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	DYNEGY INC.

Date: November 8, 2006	By:	/S/ HOLLI C. NICHOLS
		Holli C. Nichols Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)