Edgar Filing: DYNEGY HOLDINGS INC

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q/A
Amendment No. 1


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

For the quarterly period ended March 31, 2008

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

For the transition period from ________ to ________

DYNEGY INC.
DYNEGY HOLDINGS INC.
(Exact name of registrant as specified in its charter)


Entity	Commission File Number	State of Incorporation	I.R.S. Employer Identification No.

Dynegy Inc.	001-33443	Delaware	20-5653152
Dynegy Holdings Inc.	000-29311	Delaware	94-3248415

1000 Louisiana, Suite 5800 Houston, Texas (Address of principal executive offices)			77002 (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.


	Dynegy Inc.	Yes x No ¨
	Dynegy Holdings Inc.	Yes x No ¨

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


	Large accelerated filer	Accelerated filer	Non-accelerated filer (Do not check if a smaller reporting company)	Smaller reporting company
Dynegy Inc.	x	o	o	o


	Dynegy Holdings Inc.	o	o	x	o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).


	Dynegy Inc.	Yes ¨ No x
	Dynegy Holdings Inc.	Yes ¨ No x

Indicate the number of shares outstanding of Dynegy Inc.’s classes of common stock, as of the latest practicable date: Class A common stock, $0.01 par value per share, 502,112,596 shares outstanding as of May 2, 2008; Class B common stock, $0.01 par value per share, 340,000,000 shares outstanding as of May 2, 2008. All of Dynegy Holdings Inc.’s outstanding common stock is owned indirectly by Dynegy Inc.

This combined Form 10-Q/A is separately filed by Dynegy Inc. and Dynegy Holdings Inc. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to a registrant other than itself.

DYNEGY INC. and DYNEGY HOLDINGS INC.

TABLE OF CONTENTS


			Page

PART I. FINANCIAL INFORMATION

	Item 1.	FINANCIAL STATEMENTS—DYNEGY INC. AND DYNEGY HOLDINGS INC.:

Condensed Consolidated Balance Sheets—Dynegy Inc.: March 31, 2008 and December 31, 2007			5
Condensed Consolidated Statements of Operations (Restated)—Dynegy Inc.: For the three months ended March 31, 2008 and 2007			6
Condensed Consolidated Statements of Cash Flows—Dynegy Inc.: For the three months ended March 31, 2008 and 2007			7
Condensed Consolidated Statements of Comprehensive Loss—Dynegy Inc.: For the three months ended March 31, 2008 and 2007			8
Condensed Consolidated Balance Sheets—Dynegy Holdings Inc.: March 31, 2008 and December 31, 2007			9
Condensed Consolidated Statements of Operations (Restated)—Dynegy Holdings Inc.: For the three months ended March 31, 2008 and 2007			10
Condensed Consolidated Statements of Cash Flows—Dynegy Holdings Inc.: For the three months ended March 31, 2008 and 2007			11
Condensed Consolidated Statements of Comprehensive Loss—Dynegy Holdings Inc.: For the three months ended March 31, 2008 and 2007			12
Notes to Condensed Consolidated Financial Statements			13

	Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	36
	Item 4.	CONTROLS AND PROCEDURES—DYNEGY INC. AND DYNEGY HOLDINGS INC.	55

PART II. OTHER INFORMATION

	Item 6.	EXHIBITS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	57

DYNEGY INC. AND DYNEGY HOLDINGS INC. FORM 10-Q/A
EXPLANATORY NOTE 1

Dynegy Inc. and Dynegy Holdings Inc. are filing this Amendment No. 1 on Form 10-Q/A (“Amendment No. 1”) to reflect the effect of a $229 million overstatement of both revenues and cost of sales for the three months ended March 31, 2008, as reported in our Quarterly Report on Form 10-Q for the period ended March 31, 2008, which was originally filed on May 8, 2008 (the “Original Filing”). The restatement for the foregoing items had no effect on our previously reported operating loss, net loss or loss per share for the three months ended March 31, 2008. These items are discussed in more detail in the Introductory Note to the accompanying unaudited condensed consolidated financial statements beginning on page 13. The following Items of the Original Filing are amended by this Amendment No. 1:


	Item 1.	Condensed Consolidated Financial Statements
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 4.	Controls and Procedures

Unaffected items have not been repeated in this Amendment No. 1.

ORIGINAL FILING. SUCH EVENTS INCLUDE, AMONG OTHERS, THE EVENTS DESCRIBED IN OUR CURRENT REPORTS ON FORM 8-K. FOR A DESCRIPTION OF THESE EVENTS, PLEASE READ OUR REPORTS FILED SINCE MAY 8, 2008, INCLUDING OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO.

EXPLANATORY NOTE 2

This report includes the combined filing of Dynegy Inc. (“Dynegy”) and Dynegy Holdings Inc. (“DHI”). DHI is the principal subsidiary of Dynegy, providing nearly 100 percent of Dynegy’s total consolidated revenue for the three month period ended March 31, 2008 and constituting nearly 100 percent of Dynegy’s total consolidated asset base as of March 31, 2008 except for Dynegy’s 50 percent interest in DLS Power Holdings, LLC and DLS Power Development Company, LLC. Unless the context indicates otherwise, throughout this report, the terms “the Company”, “we”, “us”, “our” and “ours” are used to refer to both Dynegy and DHI and their direct and indirect subsidiaries, including Dynegy Illinois Inc. (“Dynegy Illinois”) before it became a wholly owned subsidiary of Dynegy by way of the merger of Merger Sub Co., then Dynegy’s wholly owned subsidiary, with and into Dynegy Illinois. Discussions or areas of this report that apply only to Dynegy or DHI are clearly noted in such section.

DEFINITIONS

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


APB		Accounting Principles Board
BTA		Best technology available
Cal ISO		The California Independent System Operator
CARB		California Air Resources Board
CDWR		California Department of Water Resources
CEC		California Energy Commission
CFTC		Commodity Futures Trading Commission
CO2		Carbon Dioxide
CRM		Our former customer risk management business segment
CUSA		Chevron U.S.A. Inc., a wholly owned subsidiary of Chevron Corporation
DHI		Dynegy Holdings Inc., Dynegy’s primary financing subsidiary
DMG		Dynegy Midwest Generation, Inc.
DMSLP		Dynegy Midstream Services L.P.
EITF		Emerging Issues Task Force
EPA		Environmental Protection Agency
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIN		FASB Interpretation
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-WE		Our power generation business - West segment
ICC		Illinois Commerce Commission
IMA		In-market asset availability
ISO		Independent System Operator
LNG		Liquefied natural gas
MISO		Midwest Independent Transmission Operator, Inc.
MMBtu		One million British thermal units
MW		Megawatts
MWh		Megawatt hour
NPDES		National Pollutant Discharge Elimination System
NRG		NRG Energy, Inc.
NYSDEC		New York State Department of Environmental Conservation
PJM		PJM Interconnection, LLC
PPEA		PPEA Holding Company LLC
PUHCA		Public Utility Holding Company Act of 1935, as amended
RGGI		Regional Greenhouse Gas Initiative
SCEA		Sandy Creek Energy Associates, LP
SCH		Sandy Creek Holdings LLC
SEC		U.S. Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
SPDES		State Pollutant Discharge Elimination System
VaR		Value at Risk
VIE		Variable Interest Entity

PART I. FINANCIAL INFORMATION

Item 1—FINANCIAL STATEMENTS—DYNEGY INC. AND DYNEGY HOLDINGS INC.

DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS
See Introductory Note
(unaudited) (in millions, except share data)


	March 31, 2008			December 31, 2007

ASSETS
Current Assets
Cash and cash equivalents	$	429		$	328
Restricted cash and investments		113			104
Accounts receivable, net of allowance for doubtful accounts of $18 and $20, respectively		383			426
Accounts receivable, affiliates		1			1
Inventory		185			199
Assets from risk-management activities		1,751			358
Deferred income taxes		117			45
Prepayments and other current assets		209			145
Assets held for sale		—			57

Total Current Assets		3,188			1,663

Property, Plant and Equipment		10,796			10,689
Accumulated depreciation		(1,736	)		(1,672	)

Property, Plant and Equipment, Net		9,060			9,017
Other Assets
Unconsolidated investments		71			79
Restricted cash and investments		1,237			1,221
Assets from risk-management activities		96			55
Goodwill		438			438
Intangible assets		481			497
Deferred income taxes		5			6
Accounts receivable, affiliates		4			—
Other long-term assets		243			245

Total Assets	$	14,823		$	13,221


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	298		$	292
Accrued interest		127			56
Accrued liabilities and other current liabilities		154			201
Liabilities from risk-management activities		2,030			397
Notes payable and current portion of long-term debt		51			51
Liabilities held for sale		—			2

Total Current Liabilities		2,660			999

Long-term debt		5,789			5,739
Long-term debt, affiliates		200			200

Long-Term Debt		5,989			5,939
Other Liabilities
Liabilities from risk-management activities		220			116
Deferred income taxes		1,222			1,250
Other long-term liabilities		371			388

Total Liabilities		10,462			8,692

Minority Interest		11			23
Commitments and Contingencies (Note 9)
Stockholders’ Equity
Class A Common Stock, $0.01 par value, 2,100,000,000 shares authorized at March 31, 2008 and December 31, 2007; 504,491,825 and 502,819,794 shares issued and outstanding at March 31, 2008 and December 31, 2007, respectively		5			5
Class B Common Stock, $0.01 par value, 850,000,000 shares authorized at March 31, 2008 and December 31, 2007; 340,000,000 shares issued and outstanding at March 31, 2008 and December 31, 2007		3			3
Additional paid-in capital		6,468			6,463
Subscriptions receivable		(3	)		(5	)
Accumulated other comprehensive loss, net of tax		(36	)		(25	)
Accumulated deficit		(2,016	)		(1,864	)
Treasury stock, at cost, 2,449,440 and 2,449,259 shares at March 31, 2008 and December 31, 2007, respectively		(71	)		(71	)

Total Stockholders’ Equity		4,350			4,506

Total Liabilities and Stockholders’ Equity	$	14,823		$	13,221

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
See Introductory Note
(unaudited) (in millions, except per share data)


	Three Months Ended March 31,

	2008			2007

	(Restated)
Revenues	$	545		$	505
Cost of sales		(451	)		(240	)
Operating and maintenance expense, exclusive of depreciation and amortization shown separately below		(112	)		(79	)
Depreciation and amortization expense		(93	)		(52	)
General and administrative expenses		(39	)		(53	)


Operating income (loss)		(150	)		81
Losses from unconsolidated investments		(9	)		—
Interest expense		(109	)		(67	)
Other income and expense, net		20			8


Income (loss) from continuing operations before income taxes		(248	)		22
Income tax benefit (expense) (Note 11)		96			(6	)


Income (loss) from continuing operations		(152	)		16
Loss from discontinued operations, net of tax benefit of $1 and $1, respectively (Notes 3 and 11)		—			(2	)


Net income (loss)	$	(152	)	$	14


Earnings (Loss) Per Share (Note 8):
Basic earnings (loss) per share:
Income (loss) from continuing operations	$	(0.18	)	$	0.03
Loss from discontinued operations		—			—


Basic earnings (loss) per share	$	(0.18	)	$	0.03


Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	(0.18	)	$	0.03
Loss from discontinued operations		—			—


Diluted earnings (loss) per share	$	(0.18	)	$	0.03


Basic shares outstanding		836			496
Diluted shares outstanding		838			498

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
See Introductory Note
(unaudited) (in millions)


	Three Months Ended March 31,

	2008			2007

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(152	)	$	14
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization		94			57
Losses from unconsolidated investments, net of cash distributions		9			—
Risk-management activities		280			3
Deferred income taxes		(95	)		3
Legal and settlement charges		—			17
Other		—			10
Changes in working capital:
Accounts receivable		36			(29	)
Inventory		14			18
Prepayments and other assets		(55	)		(13	)
Accounts payable and accrued liabilities		18			(37	)
Changes in non-current assets		(7	)		(1	)
Changes in non-current liabilities		4			2


Net cash provided by operating activities		146			44


CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(131	)		(34	)
Unconsolidated investments		(6	)		—
Proceeds from asset sales, net		57			—
Business acquisitions, net of cash acquired		—			(1	)
(Increase) decrease in restricted cash and restricted investments		(25	)		9
Other investing		10			—


Net cash used in investing activities		(95	)		(26	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net		51			—
Repayments of long-term borrowings		—			(19	)
Other financing, net		(1	)		(1	)


Net cash provided by (used in) financing activities		50			(20	)


Net increase (decrease) in cash and cash equivalents		101			(2	)
Cash and cash equivalents, beginning of period		328			371


Cash and cash equivalents, end of period	$	429		$	369


Other non-cash investing activity:
Noncash construction expenditures	$	9		$	—

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
See Introductory Note
(unaudited) (in millions)


	Three Months Ended March 31,

	2008			2007


Net income (loss)	$	(152	)	$	14
Cash flow hedging activities, net:
Unrealized mark-to-market losses arising during period, net		(26	)		(59	)
Reclassification of mark-to-market (gains) losses to earnings, net		8			(15	)


Changes in cash flow hedging activities, net (net of tax benefit of $5 and $44, respectively)		(18	)		(74	)
Allocation to minority interest		11			—

Total cash flow hedging activities		(7	)		(74	)
Amortization of unrecognized prior service cost and actuarial loss (net of tax benefit (expense) of zero and zero, respectively)		—			1
Net unrealized loss on securities, net (net of tax benefit of $3 and zero, respectively)		(4	)		—


Other comprehensive loss, net of tax		(11	)		(73	)


Comprehensive loss	$	(163	)	$	(59	)

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS
See Introductory Note
(unaudited) (in millions)


	March 31, 2008			December 31, 2007

ASSETS
Current Assets
Cash and cash equivalents	$	396		$	292
Restricted cash and investments		113			104
Accounts receivable, net of allowance for doubtful accounts of $15 and $15, respectively		385			428
Accounts receivable, affiliates		1			1
Inventory		185			199
Assets from risk-management activities		1,751			358
Deferred income taxes		99			30
Prepayments and other current assets		209			145
Assets held for sale		—			57

Total Current Assets		3,139			1,614

Property, Plant and Equipment		10,796			10,689
Accumulated depreciation		(1,736	)		(1,672	)

Property, Plant and Equipment, Net		9,060			9,017
Other Assets
Unconsolidated investments		8			18
Restricted cash and investments		1,237			1,221
Assets from risk-management activities		96			55
Goodwill		438			438
Intangible assets		481			497
Deferred income taxes		5			6
Accounts receivable, affiliates		4			—
Other long-term assets		241			241

Total Assets	$	14,709		$	13,107


LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities
Accounts payable	$	298		$	291
Accrued interest		127			56
Accrued liabilities and other current liabilities		155			202
Liabilities from risk-management activities		2,030			397
Notes payable and current portion of long-term debt		51			51
Liabilities held for sale		—			2

Total Current Liabilities		2,661			999

Long-term debt		5,789			5,739
Long-term debt, affiliates		200			200

Long-Term Debt		5,989			5,939
Other Liabilities
Liabilities from risk-management activities		220			116
Deferred income taxes		1,023			1,052
Other long-term liabilities		367			381

Total Liabilities		10,260			8,487

Minority Interest		11			23
Commitments and Contingencies (Note 9)
Stockholder’s Equity
Capital Stock, $1 par value, 1,000 shares authorized at March 31, 2008 and December 31, 2007		—			—
Additional paid-in capital		5,684			5,684
Affiliate receivable		(820	)		(825	)
Accumulated other comprehensive loss, net of tax		(36	)		(25	)
Accumulated deficit		(390	)		(237	)

Total Stockholder’s Equity		4,438			4,597

Total Liabilities and Stockholder’s Equity	$	14,709		$	13,107

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
See Introductory Note
(unaudited) (in millions)


	Three Months Ended March 31,

	2008			2007

	(Restated)
Revenues	$	545		$	505
Cost of sales		(451	)		(240	)
Operating and maintenance expense, exclusive of depreciation and amortization shown separately below		(112	)		(79	)
Depreciation and amortization expense		(93	)		(52	)
General and administrative expenses		(39	)		(36	)


Operating income (loss)		(150	)		98
Losses from unconsolidated investments		(5	)		—
Interest expense		(109	)		(67	)
Other income and expense, net		20			4


Income (loss) from continuing operations before income taxes		(244	)		35
Income tax benefit (expense) (Note 11)		91			(11	)


Income (loss) from continuing operations		(153	)		24
Loss from discontinued operations, net of tax benefit of $1 and $1, respectively (Notes 3 and 11)		—			(2	)


Net income (loss)	$	(153	)	$	22

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
See Introductory Note
(unaudited) (in millions)


	Three Months Ended March 31,

	2008			2007

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(153	)	$	22
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization		94			57
Earnings from unconsolidated investments, net of cash distributions		5			—
Risk-management activities		280			3
Deferred income taxes		(90	)		9
Other		(1	)		9
Changes in working capital:
Accounts receivable		36			(29	)
Inventory		14			18
Prepayments and other assets		(55	)		(13	)
Accounts payable and accrued liabilities		19			(35	)
Changes in non-current assets		(6	)		(1	)
Changes in non-current liabilities		3			3


Net cash provided by operating activities		146			43


CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(131	)		(34	)
Proceeds from asset sales, net		57			—
(Increase) decrease in restricted cash and restricted investments		(25	)		9
Affiliate transactions		1			(8	)
Other investing		6			—


Net cash used in investing activities		(92	)		(33	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net		51			—
Repayments of long-term borrowings		—			(19	)
Dividend to affiliate		—			(50	)
Other financing, net		(1	)		(1	)


Net cash provided by (used in) financing activities		50			(70	)


Net increase (decrease) in cash and cash equivalents		104			(60	)
Cash and cash equivalents, beginning of period		292			242


Cash and cash equivalents, end of period	$	396		$	182


Other non-cash investing activity:
Noncash construction expenditures	$	9		$	—

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
See Introductory Note
(unaudited) (in millions)


	Three Months Ended March 31,

	2008			2007


Net income (loss)	$	(153	)	$	22
Cash flow hedging activities, net:
Unrealized mark-to-market losses arising during period, net		(26	)		(59	)
Reclassification of mark-to-market (gains) losses to earnings, net		8			(15	)


Changes in cash flow hedging activities, net (net of tax benefit of $5 and $44, respectively)		(18	)		(74	)
Allocation to minority interest		11			—

Total cash flow hedging activities		(7	)		(74	)
Amortization of unrecognized prior service cost and actuarial loss (net of tax benefit (expense) of zero and zero, respectively)		—			1
Net unrealized loss on securities, net (net of tax benefit of $3 and zero, respectively)		(4	)		—


Other comprehensive loss, net of tax		(11	)		(73	)


Comprehensive loss	$	(164	)	$	(51	)

See the notes to condensed consolidated financial statements.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

PLEASE NOTE THAT THESE FINANCIAL STATEMENTS AND THE NOTES THERETO DO NOT REFLECT EVENTS OCCURRING AFTER MAY 8, 2008 (THE DATE OF THE ORIGINAL FILING). FOR A DESCRIPTION OF THESE EVENTS, PLEASE READ OUR EXCHANGE ACT REPORTS FILED SINCE MAY 8, 2008, INCLUDING OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO.

Introductory Note

On July 25, 2008, we filed a Current Report on Form 8-K announcing a restatement of our previously issued financial statements included in our Quarterly Report on Form 10-Q for the period ended March 31, 2008. The restatement relates to a $229 million overstatement of both revenues and cost of sales. The financial information in this amendment has been revised to reflect the effects of such restatement.

In accordance with EITF Issue 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3,” we present all mark-to-market gains and losses on energy trading contracts net in the income statement. In order to conform to this accounting standard, on a quarterly basis, we calculate our net mark-to-market gains and losses on energy trading contracts and adjust our revenues and cost of sales accordingly. During the first quarter 2008, we inadvertently excluded certain amounts from the calculation.

The restatement of our previously issued financial statements did not change our previously reported operating loss, net loss or loss per share for the three months ended March 31, 2008, nor did the restatement change our unaudited condensed consolidated statements of cash flows or our unaudited condensed consolidated statements of comprehensive loss for the three months ended March 31, 2008 or our unaudited condensed consolidated balance sheet as of March 31, 2008.

The table below summarizes the effects to both Dynegy and DHI of the correction to revenues and cost of sales (in millions):


	For the Three Months Ended March 31, 2008

	Power Generation

	GEN-MW			GEN-WE			GEN-NE			Other			Total

Revenues
As previously reported in Original Filing	$	319		$	205		$	251		$	(1	)	$	774
Adjustment		(155	)		(74	)		—			—			(229	)

As restated	$	164		$	131		$	251		$	(1	)	$	545


Cost of Sales
As previously reported in Original Filing	$	(279	)	$	(197	)	$	(213	)	$	9		$	(680	)
Adjustment		155			74			—			—			229

As restated	$	(124	)	$	(123	)	$	(213	)	$	9		$	(451	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

Note 1—Accounting Policies

Basis of Presentation

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 accounting principles generally accepted in the United States of America. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in Dynegy’s and DHI’s Form 10-K for the year ended December 31, 2007 filed on February 28, 2008, which we refer to as each registrant’s “Form 10-K”.

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/A 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 informed 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 based on currently available information. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (i) developing fair value assumptions, including estimates of future cash flows and discount rates, (ii) analyzing tangible and intangible assets for possible impairment, (iii) estimating the useful lives of our assets, (iv) assessing future tax exposure and the realization of tax assets, (v) determining amounts to accrue for contingencies, guarantees and indemnifications, (vi) estimating various factors used to value our pension assets and liabilities and (vii) determining the primary beneficiary of certain VIEs from a set of related parties. Actual results could differ materially from any such estimates. Certain reclassifications have been made to prior period amounts in order to conform to current year presentation.

Accounting Principles Adopted

SFAS No. 157. On September 15, 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). Please read Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

SFAS No. 159. On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure eligible items at fair value at specified election dates. A business entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. We adopted SFAS No. 159 on January 1, 2008 but have not elected the fair value option to measure eligible items. Accordingly, this statement had no impact on our financial statements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

Accounting Principles Not Yet Adopted

SFAS No. 141(R). On December 4, 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) requires the acquiring entity in a business combination to recognize the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS No. 141(R) is effective for fiscal years beginning on or after December 15, 2008. We are currently evaluating the impact of this statement on our financial statements.

SFAS No. 160. On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 requires ownership interests in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity; the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of income; changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently; and any retained noncontrolling equity investment in the former subsidiary be initially measured at fair value. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. We are currently evaluating the impact of this statement on our financial statements.

SFAS No. 161. On March 19, 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”). SFAS No. 161 is meant to improve transparency about the location and amounts of derivative instruments in an entity’s financial statements; how derivative instruments and related hedged items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended; and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 requires disclosure of the fair values of derivative instruments and their gains and losses in a tabular format. It also provides more information about an entity’s liquidity by requiring disclosure of derivative features that are credit risk–related and it requires cross-referencing within footnotes to enable financial statement users to locate important information about derivative instruments. SFAS No. 161 is effective for fiscal years beginning on or after November 15, 2008. We are currently evaluating the impact of this statement on our financial statements.

Note 2—Acquisitions and Contributions

LS Power Business Combination. On April 2, 2007, Dynegy acquired entities that owned ten power plants, a power plant under construction (the “Contributed Entities”) and 50 percent interests in DLS Power Holdings, LLC (“DLS Power Holdings”), a development joint venture, and DLS Power Development Company, LLC (“DLS Power Development”) from LSP Gen Investors, L.P., LS Power Partners, L.P., LS Power Equity Partners PIE I, L.P., LS Power Equity Partners, L.P. and LS Power Associates, L.P. (the “Merger”). The aggregate purchase price was comprised of (i) $100 million cash, (ii) 340 million shares of the Class B common stock of Dynegy, (iii) the issuance of a promissory note in the aggregate principal amount of $275 million (the “Note”) (which was simultaneously issued and repaid in full without interest or prepayment penalty), (iv) the issuance of an additional $70 million of project-related debt (the “Griffith Debt”) (which was simultaneously issued and repaid in full without interest or prepayment penalty) via an indirect wholly owned subsidiary, and (v) transaction costs of approximately $52 million, approximately $8 million of which were paid in 2006. The Class B common stock issued by Dynegy was valued at $5.98 per share, which represents the average closing price of Dynegy’s common stock on the New York Stock Exchange for the two days prior to, including, and two days subsequent to the September 15, 2006 public announcement of the Merger, or approximately $2,033 million. Dynegy funded the cash payment and the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

repayment of the Note and the Griffith Debt using cash on hand and borrowings by DHI (and subsequent permitted distributions to Dynegy) of (i) an aggregate $275 million under the revolving portion of our Fifth Amended and Restated Credit Facility and (ii) an aggregate $70 million under a senior secured term loan facility. Please see Note 15—Debt—Fifth Amended and Restated Credit Facility in Dynegy’s and DHI’s Form 10-K for discussion of DHI’s borrowings. We paid a premium over the fair value of the net tangible and identified intangible assets acquired due to the (i) scale and diversity of assets acquired in key regions of the United States; (ii) financial benefits of such assets; and (iii) proven nature of the asset development platform that was subsequently contributed to DLS Power Holdings and DLS Power Development.

In connection with the completion of the Merger, Dynegy contributed to Dynegy Illinois its interest in the Contributed Entities. Following such contribution, Dynegy Illinois contributed to DHI its interest in the Contributed Entities and, as a result, the Contributed Entities are subsidiaries of DHI. Accordingly, all of the entities acquired in the Merger are included within DHI with the exception of Dynegy’s 50 percent interests in DLS Power Holdings and DLS Power Development, which are directly owned by Dynegy.

The application of purchase accounting under SFAS No. 141, “Business Combinations”, (“SFAS No. 141”) required that the total purchase price be allocated to the fair value of assets acquired and liabilities assumed based on their fair values at the acquisition date, with amounts exceeding the fair values being recorded as goodwill in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”). The allocation process includes an analysis of acquired fixed assets, contracts, and contingencies to identify and record the fair value of all assets acquired and liabilities assumed. Dynegy’s allocation of the purchase price to specific assets and liabilities was based upon customary valuation procedures and techniques.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):


Cash	$	16
Restricted cash and investments (including $37 million current)		91
Accounts receivable		52
Inventory		37
Assets from risk management activities (including $11 million current)		37
Prepaids and other current assets		12
Property, plant and equipment		4,223
Intangible assets (including $9 million current)		224
Goodwill		486
Unconsolidated investments		83
Other		35

Total assets acquired	$	5,296

Current liabilities and accrued liabilities	$	(92	)
Liabilities from risk management activities (including $14 million current)		(75	)
Long-term debt (including $32 million current)		(1,898	)
Deferred income taxes		(627	)
Other		(96	)
Minority interest		22

Total liabilities and minority interest assumed	$	(2,766	)

Net assets acquired	$	2,530

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

Included in Other liabilities was an intangible liability of $35 million in GEN-MW primarily related to a contract held by LSP Kendall Holding LLC, one of the entities acquired by Dynegy. LSP Kendall Holding LLC was party to a power tolling agreement with another of our subsidiaries. This power tolling agreement had a fair value of approximately $31 million as of April 2, 2007, representing an intangible liability from the perspective of LSP Kendall Holding LLC. Upon completion of the Merger, this power tolling agreement was effectively settled, which resulted in a $31 million second quarter 2007 gain equal to the fair value of this contract, in accordance with EITF Issue 04-1, “Accounting for Pre-existing Contractual Relationships Between the Parties to a Purchase Business Combination”.

Dynegy’s and DHI’s results of operations include the results of the acquired entities for the period beginning April 2, 2007. The following table presents unaudited pro forma information for 2007, as if the acquisition had occurred on January 1, 2007:


	Dynegy Inc.					Dynegy Holdings Inc.

	Three Months Ended March 31, 2007					Three Months Ended March 31, 2007

	Actual		Pro Forma			Actual		Pro Forma

	(in millions, except per share amounts)
Revenue	$	505	$	794		$	505	$	794
Income (loss) before cumulative effect of a change in accounting principal		14		(34	)		22		(23	)
Net income (loss) applicable to common stockholders		14		(34	)		22		(23	)

Basic and diluted earnings (loss) per share before cumulative effect of accounting change	$	0.03	$	(0.04	)		N/A		N/A
Basic and diluted earnings (loss) per share		0.03		(0.04	)		N/A		N/A

These unaudited pro forma results, based on assumptions deemed appropriate by management, have been prepared for informational purposes only and are not necessarily indicative of Dynegy’s and DHI’s results for the three months ended March 31, 2007 if the Merger had occurred on January 1, 2007. Pro forma adjustments to the results of operations include the effects on depreciation and amortization, interest expense, interest income and income taxes. The unaudited pro forma condensed consolidated financial statements reflect the Merger in accordance with SFAS No. 141 and SFAS No. 142.

Sithe Assets Contribution. On January 31, 2005, Dynegy acquired, and subsequently contributed to DHI in April 2007, 100 percent of the outstanding common shares of ExRes SHC, Inc. (“ExRes”), the parent company of Sithe Energies, Inc. (“Sithe Energies”) and Sithe/Independence Power Partners, L.P. (“Independence”). The results of the operations of ExRes have been included in Dynegy’s consolidated financial statements since January 31, 2005. Through this acquisition, Dynegy acquired the 1,064 MW Independence power generation facility located near Scriba, New York, as well as natural gas-fired merchant facilities in New York and hydroelectric generation facilities in Pennsylvania (the “Sithe Assets”).

In April 2007, Dynegy Illinois contributed to DHI all of its interest in New York Holdings Inc. (“New York Holdings”), together with its indirect interest in the subsidiaries of New York Holdings. New York Holdings, together with its wholly owned subsidiaries, owns the Sithe Assets. The Sithe Assets primarily consist of the Independence power generation facility. This contribution was accounted for as a transaction between entities under common control. As such, the assets and liabilities of New York Holdings were recorded by DHI at Dynegy’s

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

historical cost on Dynegy’s date of acquisition, January 31, 2005. In addition, DHI’s historical financial statements have been adjusted in all periods presented to reflect the contribution as though DHI had owned New York Holdings beginning January 31, 2005.

Note 3—Discontinued Operations

CoGen Lyondell. On August 1, 2007, we completed the sale of the CoGen Lyondell power generation facility for approximately $470 million to EnergyCo, LLC (“EnergyCo”), a joint venture between PNM Resources and a subsidiary of Cascade Investment, LLC.

In accordance with SFAS No. 144, we discontinued depreciation and amortization of CoGen Lyondell’s property, plant and equipment during the second quarter 2007. Depreciation and amortization expense related to CoGen Lyondell totaled approximately $4 million in the three month period ended March 31, 2007. Also pursuant to SFAS No. 144, we are reporting the results of CoGen Lyondell’s operations in discontinued operations for all periods presented.

Calcasieu. On March 31, 2008, we completed the sale of the Calcasieu power generation facility to Entergy Gulf States, Inc. (“Entergy”) for approximately $56 million, net of transaction costs.

In accordance with SFAS No. 144, we discontinued depreciation and amortization of Calcasieu’s property, plant and equipment during the first quarter 2007. Depreciation and amortization expense related to Calcasieu totaled zero and less than a million dollars in the three month periods ended March 31, 2008 and 2007, respectively. Also pursuant to SFAS No. 144, we are reporting the results of Calcasieu’s operations in discontinued operations for all periods presented.

Summary. The following table summarizes information related to both Dynegy’s and DHI’s discontinued operations (all of which is included in our GEN-WE segment) (in millions):


Three Months Ended March 31, 2008
Loss on sale before taxes	$	(1	)
Loss on sale after taxes		—

Three Months Ended March 31, 2007
Revenues	$	69
Loss from operations before taxes		(3	)
Loss from operations after taxes		(2	)

Note 4—Risk Management Activities, Derivatives and Financial Instruments

The nature of our business necessarily involves market and financial risks. Specifically, we are exposed to commodity price variability related to our power generation business. Our commercial team manages these commodity price risks by entering 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 of Dynegy’s and DHI’s Form 10-K. Consistent with our commodity risk management policy, our commercial team also uses a limited amount of financial instruments to capture the benefit of fluctuations in market prices in the geographic regions where our assets operate.

Cash Flow Hedges. We enter into financial derivative instruments that qualify, and that we may elect to designate, as cash flow hedges.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

Interest rate swaps have been used to convert floating interest rate obligations to fixed interest rate obligations. Instruments related to our GEN business, which are entered into for purposes of hedging future fuel requirements and sales commitments and securing commodity prices we consider favorable under the circumstances, have also historically been designated as cash flow hedges. Beginning on April 2, 2007, we chose to cease designating such instruments related to our GEN business as cash flow hedges, and thus apply mark-to-market accounting treatment prospectively. Accordingly, as fair values fluctuate from period to period due to market price volatility, fair value changes are reflected in the unaudited condensed consolidated statements of operations. Pursuant to EITF Issue 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 02-3”), all gains and losses on third party energy trading contracts, whether realized or unrealized, are presented net in the unaudited condensed consolidated statements of operations. The balance in Other comprehensive loss at April 2, 2007 related to these instruments will be reclassified to future earnings contemporaneously with the related purchases of fuel and sales of electricity. As of March 31, 2008, the remaining balance was a $7 million pre-tax loss.

During the three months ended March 31, 2008, we recorded no income related to ineffectiveness from changes in the 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 months ended March 31, 2007, we recorded $5 million 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 months ended March 31, 2008 and 2007, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.

The balance in cash flow hedging activities, net at March 31, 2008, is expected to be reclassified to future earnings when the hedged transaction impacts earnings. Of this amount, after-tax losses of approximately $4 million are currently estimated to be reclassified into earnings over the 12-month period ending March 31, 2009. The actual amounts that will be reclassified into 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 that we designate, as fair value hedges. We use interest rate swaps to convert a portion of our non-prepayable fixed-rate debt into floating-rate debt. During the three months ended March 31, 2008 and 2007, there was no ineffectiveness from changes in the fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. During the three months ended March 31, 2008 and 2007, no amounts were recognized in relation to firm commitments that no longer qualified as fair value hedges.

Fair Value Measurements. On September 15, 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value and expands disclosure requirements for 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. The provisions of SFAS No. 157 are to be applied prospectively, except for the initial impact on three specific items: (i) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF No. 02-3, (ii) existing hybrid financial instruments measured initially at fair value using the transaction price and (iii) blockage factor discounts. We adopted SFAS No. 157 effective January 1, 2008 and did not record a cumulative effect upon the adoption.

On February 12, 2008, the FASB issued FASB Staff Position No. FAS 157-2, which defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, with respect to non-financial assets and non-

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

financial liabilities which are not recognized or disclosed at fair value in the financial statements on a recurring basis. Therefore, we have deferred application of SFAS No. 157 to such non-financial assets and non-financial liabilities until January 1, 2009.

Fair value, as defined in SFAS No. 157, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). However, as permitted under SFAS No. 157, we utilize a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of our assets and liabilities measured and reported at fair value. Where appropriate, valuation adjustments are made to account for various factors, including the impact of our credit risk, our counterparties’ credit risk and bid-ask spreads. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:


	•	Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

	•	Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter forwards, options and repurchase agreements.

	•	Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to our needs as well as financial transmission rights. At each balance sheet date, we perform an analysis of all instruments subject to SFAS No. 157 and include in Level 3 all of those whose fair value is based on significant unobservable inputs.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2008. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.


	Fair Value as of March 31, 2008

	Level 1		Level 2		Level 3		Total

	(in millions)
Assets:
Assets from risk management activities	$	—	$	1,835	$	12	$	1,847
Other		—		14		—		14

Total	$	—	$	1,849	$	12	$	1,861

Liabilities:
Liabilities from risk management activities	$	—	$	2,180	$	70	$	2,250

Total	$	—	$	2,180	$	70	$	2,250

The determination of the fair values above incorporates various factors required under SFAS No. 157. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities.

Assets and liabilities from risk management activities may include exchange-traded derivative contracts and OTC derivative contracts. Some exchange-traded derivatives are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets. In such cases, these exchange-traded derivatives are classified within Level 2. OTC derivative trading instruments include swaps, forwards, options and complex structures that are valued at fair value. In certain instances, these instruments may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain OTC derivatives trade in less active markets with a lower availability of pricing information. In addition, complex or structured transactions, such as heat-rate call options, can introduce the need for internally-developed model inputs that might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3. Other assets primarily represent available-for-sale securities.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

The following table sets forth a reconciliation of changes in the fair value of financial instruments classified as Level 3 in the fair value hierarchy:


	2008

	(in millions)
Balance at December 31, 2007	$	(16	)
Realized and unrealized gains (losses)		(42	)


Balance at March 31, 2008	$	(58	)


Change in unrealized gains (losses) relating to instruments still held as of March 31, 2008	$	(22	)

Gains and losses (realized and unrealized) for Level 3 recurring items are included in revenues on the unaudited condensed consolidated statements of operations. We believe an analysis of instruments classified as Level 3 should be undertaken with the understanding that these items are generally hedging our generation portfolio

Transfers in and/or out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. There were no transfers in or out of Level 3 during the three months ended March 31, 2008.

Note 5—Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, net of tax, is included in Dynegy’s stockholders’ equity and DHI’s stockholder’s equity on our unaudited condensed consolidated balance sheets, respectively, as follows:


	March 31, 2008			December 31, 2007

	(in millions)
Cash flow hedging activities, net	$	(46	)	$	(39	)
Foreign currency translation adjustment		27			27
Unrecognized prior service cost and actuarial loss		(25	)		(25	)
Available for sale securities		8			12


Accumulated other comprehensive loss, net of tax	$	(36	)	$	(25	)

Note 6—Variable Interest Entities

Hydroelectric Generation Facilities. On January 31, 2005, Dynegy completed the acquisition of ExRes, the parent company of Sithe Energies, Inc. and Independence. ExRes also 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 (“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 all costs, liabilities, and obligations of the entities owning these facilities, and to indemnify ExRes with respect to the past and present assets and operations of the entities. As a result, we are not the primary beneficiary of the entities and have not consolidated them in accordance with the provisions of FIN No. 46(R), “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (“FIN No. 46(R)”). There was no material change during the three months ended March 31, 2008. Please see Note 12—

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

Variable Interest Entities— Hydroelectric Generation Facilities in Dynegy’s and DHI’s Form 10-K for discussion of these entities.

PPEA Holding Company LLC. On April 2, 2007, in connection with the completion of the Merger, we acquired a 70 percent interest in PPEA Holding Company LLC (“PPEA”). On December 13, 2007, we sold a portion of our interest in PPEA, reducing our ownership interest in PPEA to 37 percent. PPEA owns and operates Plum Point Energy Associates, LLC (“Plum Point”). Plum Point is constructing a 665 MW coal fired power generation facility (the “Project”), located in Mississippi County, Arkansas, in which it owns an approximate 57 percent undivided interest. These assets consist primarily of $371 million of plant construction in progress at March 31, 2008. As of March 31, 2008, we have posted a $15 million letter of credit to support our equity contribution to the Project. See Note 15—Debt—Plum Point Credit Agreement Facility for discussion of Plum Point’s borrowings in Dynegy’s and DHI’s Form 10-K. PPEA meets the definition of a VIE, and we have determined we are the primary beneficiary of this entity. As such, we have consolidated it in accordance with the provisions of FIN No. 46(R).

DLS Power Holdings and DLS Power Development. On April 2, 2007, in connection with the transactions consummated by the Merger, Dynegy acquired a 50 percent interest in DLS Power Holdings and DLS Power Development. The purpose of DLS Power Development is to provide services to DLS Power Holdings and the project subsidiaries related to power project development and to evaluate and pursue potential new development projects. DLS Power Holdings and DLS Power Development meet the definition of VIEs, as they will require additional subordinated financial support from their owners to conduct normal on-going operations. However, Dynegy is not the primary beneficiary of the entities and, in accordance with the provisions of FIN No. 46(R), has not consolidated them. Dynegy accounts for its investments in DLS Power Holdings and DLS Power Development as equity method investments pursuant to APB No. 18, “The Equity Method of Accounting for Investments in Common Stock”. We believe that Dynegy’s maximum exposure to economic loss from this VIE is limited to $63 million, which represents its equity investment in these entities at March 31, 2008.

Sandy Creek. Dynegy Sandy Creek Holdings, LLC (the “Dynegy Member”), an indirectly wholly owned subsidiary of Dynegy and DHI, and LSP Sandy Creek Member, LLC (the “LSP Member”) each own a 50 percent interest in Sandy Creek Holdings LLC (“SCH”), which owns all of Sandy Creek Energy Associates, LP (“SCEA”). SCEA owns an approximate 75 percent undivided interest in the Sandy Creek Energy Station (“the Project”), which is an 898 MW facility under construction in McLennan County, Texas. In addition, Sandy Creek Services, LLC (“SC Services”) was formed to provide services to SCH. Dynegy Power Services and LSP Sandy Creek Services LLC each own a 50 percent interest in SC Services.

SCH and SC Services both meet the definition of a VIE, as they will require additional subordinated financial support to conduct their normal on-going operations. However, we are not the primary beneficiary of the entities, and, in accordance with FIN No. 46(R), do not consolidate them. We account for our investments in SCH and SC Services as equity method investments pursuant to APB 18. We believe that our maximum exposure to economic loss from these VIEs is limited to $335 million, which represents our $8 million equity investment in these entities at March 31, 2008, a note receivable of approximately $4 million and letters of credit totaling $323 million supporting our funding commitment.

Note 7—Related Party Transactions

Equity Investments. We hold four investments in joint ventures in which LS Power or its affiliates are also investors. Dynegy has a 50 percent ownership interest in DLS Power Holdings and DLS Power Development. DHI has a 50 percent ownership interest in SCEA and SC Services, which were contributed to it by Dynegy in August 2007. Please see Note 6—Variable Interest Entities for further discussion.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

Other. On March 30, 2007, DHI paid a dividend of $50 million to Dynegy.

Note 8—Dynegy’s Earnings (Loss) Per Share

Basic earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of Dynegy common stock outstanding during the period. Diluted earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of Dynegy common stock outstanding during the period plus each share that would have been outstanding assuming the issuance of common shares for all dilutive potential common shares outstanding during the period.

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


	Three Months Ended March 31,

	2008			2007

	(in millions, except per share amounts)

Income (loss) from continuing operations for basic and diluted earnings (loss) per share	$	(152	)	$	16


Basic weighted-average shares		836			496
Effect of dilutive securities:
Stock options and restricted stock		2			2

Diluted weighted-average shares		838			498


Earnings (loss) per share from continuing operations:
Basic	$	(0.18	)	$	0.03

Diluted (1)	$	(0.18	)	$	0.03



(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, Dynegy has utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three months ended March 31, 2008.

Note 9—Commitments and Contingencies

PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS NOTE 9, WHICH WAS PRESENTED IN OUR FIRST QUARTER 2008 FORM 10-Q ORIGINALLY FILED WITH THE SEC ON MAY 8, 2008 IN ORDER TO REFLECT THE MATERIAL CHANGES IN OR UPDATES TO OUR MATERIAL LEGAL PROCEEDINGS SINCE THE ORIGINAL FILING OF OUR ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2007, DOES NOT REFLECT EVENTS OCCURRING AFTER MAY 8, 2008. FOR A DESCRIPTION OF THESE EVENTS, INCLUDING MATERIAL CHANGES IN, OR UPDATES TO, OUR MATERIAL LEGAL PROCEEDINGS, PLEASE READ OUR REPORTS FILED SINCE MAY 8, 2008, INCLUDING OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

Legal Proceedings

Set forth below is a summary of our material ongoing legal proceedings. In accordance with SFAS No. 5, we record reserves for contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. In addition, we disclose matters for which management believes a material loss is at least reasonably possible. In all instances, management has assessed the matters below based on current information and made a judgment concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may prove materially inaccurate and such judgment is made subject to the known uncertainty of litigation.

Gas Index Pricing Litigation. We, several of our affiliates, our former joint venture affiliate West Coast Power and other energy companies were named defendants in twenty-two lawsuits in state and federal court claiming damages resulting from alleged price manipulation and false reporting of natural gas prices to various index publications in the 2000-2002 timeframe. Many of the cases have been resolved and those which remain are pending in Nevada and Tennessee. Recent developments include:


	•	In October 2007, we, on behalf of ourselves and our former joint venture affiliate West Coast Power, entered into a confidential memorandum of understanding to settle the fourteen cases comprising the California-based gas index litigation. In February 2008, a formal settlement agreement was executed and funding occurred shortly thereafter. Dismissals with prejudice were entered by the court in March 2008. The settlement is without admission of wrongdoing, and we continue to deny plaintiffs’ allegations.

	•	In February 2008, the United States District Court in Las Vegas, Nevada granted defendants’ motion for summary judgment in a Colorado class action which had been transferred to Nevada through the multi-district litigation process thereby dismissing the case and all of plaintiffs’ claims. Plaintiffs have moved for reconsideration of the dismissal.

	•	The remaining six cases, three of which seek class certification, are also pending in the Nevada federal district court. Five of the cases were transferred through multi-district litigation from other states, including Kansas, Wisconsin, Missouri and Illinois. All of the cases contain similar claims — that individually and in conjunction with other energy companies, we engaged in an illegal scheme to inflate natural gas prices by providing false information to natural gas index publications. The complaints rely heavily on prior FERC and CFTC investigations into and reports concerning index manipulation in the energy industry. The lawsuits seek actual and punitive damages, restitution and/or expenses.

We continue to analyze the Gas Index Pricing Litigation and are vigorously defending the remaining individual matters. Due to the uncertainty of litigation, we cannot predict whether we will incur any liability in connection with these lawsuits. However, given the nature of the claims, an adverse result in these proceedings could have a material adverse effect on our financial condition, results of operations and cash flows.

California Market Litigation. We and various other power generators and marketers were defendants in numerous lawsuits alleging rate and market manipulation in California’s wholesale electricity market during the California energy crisis several years ago. The complaints generally alleged unfair, unlawful and deceptive trade practices in violation of the California Unfair Business Practices Act and sought injunctive relief, restitution and unspecified actual and treble damages. All of these cases have been dismissed on grounds of federal preemption and affirmed on appeal. Plaintiffs in one case, which was dismissed by the district court and recently affirmed by the Ninth Circuit, sought rehearing by the appellate court. In January 2008, the Ninth Circuit denied plaintiffs’ motion and the deadline for plaintiffs to seek Supreme Court review recently passed. Accordingly, no California Market Litigation matters are pending.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

Nevada Power Arbitration. Through one of our indirect subsidiaries, we hold an ownership interest in Black Mountain, in which our equal partner is a CUSA subsidiary. Black Mountain has a long-term power sale agreement with Nevada Power Company (“Nevada Power”) that extends through April 2023. In October 2007, Nevada Power initiated an arbitration against Black Mountain seeking a declaratory judgment that (i) Nevada Power’s methodology for calculating certain cumulative excess payments in the event of default or early termination by Black Mountain is correct and (ii) Black Mountain is obligated to repay to Nevada Power the full amount of any outstanding excess payments in the event of a default or early termination or upon the expiration of the agreement’s term in 2023. The arbitration is scheduled for July 2008 and the parties are actively engaged in discovery. Currently, Nevada Power does not allege an event of default or early termination has occurred. Nonetheless, Nevada Power maintains that as of December 31, 2007, if an event of default occurred, Black Mountain would be required to pay approximately $136 million in cumulative excess payments, 50 percent of which would be our proportionate share. We previously disclosed that we agreed to guarantee 50 percent of any Black Mountain obligation to pay cumulative excess payments. Nevada Power further alleges that the cumulative excess payments calculation could equal approximately $365 million in 2023 and would be payable upon the scheduled termination of the power sale agreement, 50 percent of which would be our proportionate share. Management does not believe that Black Mountain has an obligation to pay any amount to Nevada Power upon the scheduled termination of the agreement. We believe Nevada Power’s claims are without merit and we intend to defend against them vigorously. However, given the amount in controversy, an adverse ruling could have a material adverse effect on our future financial condition, results of operations and cash flows.

New York Attorney General Subpoena. On September 17, 2007, Dynegy and four other companies received a subpoena from the Office of the New York Attorney General. The subpoena seeks information and documents related to, among other things: Dynegy’s evaluation, analysis and projections regarding climate change; the impact of climate change on Dynegy’s operations; development opportunities through Dynegy’s joint venture with LS Power; and alleged deficiencies in Dynegy’s SEC disclosures related to the foregoing. We are reviewing the subpoena and discussing its contents with the New York Attorney General’s office in anticipation of our responding as appropriate.

Illinova Arbitration. In June 2000, Dynegy’s subsidiary, Illinova Generating Company (“IGC”), sold a minority interest it held in a Cleburne, Texas generating plant to Ponderosa Pine Energy (“PPE”). Brazos Electric Cooperative, Inc. (“Brazos”), the party to an offtake agreement from the plant, brought legal action against PPE alleging that PPE’s purchase did not comply with the terms of Brazos’ offtake agreement. Brazos received a favorable arbitration award against PPE, which in turn sought recovery from IGC and the other former owners of the plant for indemnification. In May 2007, the panel in PPE’s arbitration action ruled that IGC and the other former owners of the plant must indemnify PPE for the Brazos arbitration award, with IGC’s portion being defined as approximately $17 million. Dynegy recognized a legal settlement charge of approximately $17 million in the first quarter 2007 relating to this adverse ruling. In May 2007, Dynegy paid the judgment under protest. PPE moved to enforce the arbitration award in state district court and the defendants have filed a motion to vacate the arbitration award. A hearing on these motions was held in December 2007, with a ruling expected in the third quarter 2008.

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 (“BTA”) for minimizing adverse environmental impacts.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

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 Danskammer SPDES Permit was issued in May 2006. In June 2006, the NYSDEC issued the revised Danskammer SPDES Permit with conditions generally favorable to us. While the revised Danskammer SPDES Permit does not require installation of a closed cycle cooling system, it does require aquatic organism mortality reductions resulting from NYSDEC’s determination of BTA requirements under its regulations. In July 2006, two of the petitioners filed suit in the Supreme Court of the State of New York seeking to vacate the Deputy Commissioner’s decision and the revised Danskammer SPDES Permit. On March 26, 2007, the Court transferred the lawsuit to the Third Department Appellate Division. The case will now proceed as a normal appeal from a final agency decision and the decision will be based on whether there is substantial evidence in the record to support the agency decision. On December 21, 2007, petitioners filed their Brief for Appellants. Our Respondent’s Brief was filed on March 26, 2008. Petitioner’s Reply brief was filed on April 18, 2008. We expect a decision in the summer of 2008. We believe that the decision of the Deputy Commissioner is well reasoned and will be affirmed. However, in the event the decision is not affirmed and we ultimately are required to install a closed cycle cooling system, this could have a material adverse effect on our financial condition, results of operations and cash flows.

Roseton State Pollutant Discharge Elimination System Permit. In April 2005, the NYSDEC issued a Draft SPDES Permit renewal for the Roseton plant. The Draft Roseton 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 Roseton SPDES Permit. Three environmental organizations filed petitions for party status in the permit renewal proceeding. The petitioners are seeking to impose a permit requirement that the Roseton plant install a closed cycle cooling system in order to reduce the volume of water withdrawn from the Hudson River, thus reducing aquatic organism mortality. The petitioners claim that only a closed cycle cooling system meets the Clean Water Act’s requirement that the cooling water intake structures reflect the BTA for minimizing adverse environmental impacts. In September 2006, the administrative law judge issued a ruling admitting the petitioners to full party status and setting forth the issues to be adjudicated in the permit renewal hearing. Various holdings in the ruling have been appealed to the Commissioner of NYSDEC by us, NYSDEC staff, and the petitioners. We expect that the adjudicatory hearing on the Draft Roseton SPDES Permit will occur in 2008. 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.

Moss Landing National Pollutant Discharge Elimination System Permit. The California Regional Water Quality Control Board (“Water Board”) issued a NPDES permit for the Moss Landing Power Plant in 2000 in connection with modernization of the plant and the California Energy Commission’s licensing of that project. A local environmental group sought review of the permit in Superior Court in Monterey County in July 2001 claiming that the permit was not supported by sufficient analysis of the BTA for cooling water intake structures as required under the Clean Water Act. Petitioner contends that the once-through, seawater-cooling system at Moss Landing should be replaced with a closed cycle cooling system.

The Superior Court concluded that the Water Board’s BTA analysis was insufficient and remanded the permit to the Water Board directing a comprehensive analysis and reconsideration of the NPDES permit. Following the hearing on remand, the Water Board affirmed its BTA finding. In July 2004, the Superior Court held that the Water Board had conducted a thorough and comprehensive BTA analysis on remand. This decision was appealed by petitioner to California’s Sixth Appellate District. On December 14, 2007, the Court of Appeals issued its opinion affirming the trial court’s judgment upholding the permit. The petitioners filed a Petition for Review by the Supreme Court of California, which was granted on March 19, 2008 with further action deferred pending disposition of several petitions for certiorari in the U. S. Supreme Court related to the EPA rule governing existing water

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

intakes. On April 14, 2008, the U.S. Supreme Court granted petitions for certiorari to consider whether cost–benefit comparisons are authorized in determining BTA for cooling water intake structures.

We believe that petitioner’s claims lack 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.

Native Village of Kivalina and City of Kivalina v. ExxonMobil Corporation, et al. In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska initiated an action in federal court in the Northern District of California against DHI and 23 other companies in the energy industry. Plaintiffs claim that defendants’ emissions of greenhouse gases including carbon dioxide contribute to climate change and have caused significant damage to a native Alaskan Eskimo village through increased vulnerability to waves, storm surges and erosion. An initial schedule requires defendants to answer or otherwise respond to Plaintiffs’ complaint in late June 2008. We believe the plaintiffs’ suit lacks merit and we intend to oppose their claims vigorously.

Ordinary Course Litigation. In addition to the matters discussed above, we are party to numerous legal proceedings arising in the ordinary course of business or related to discontinued business operations. In management’s judgment, which may prove to be materially inaccurate as indicated above, the disposition of these matters will not materially adversely affect our financial condition, results of operations or cash flows.

Regulatory Matters

We are subject to regulation by various federal, state and local agencies, including extensive rules and regulations governing transportation, transmission and sale of energy commodities as well as the discharge of materials into the environment or otherwise relating to environmental protection. Compliance with these regulations requires general and administrative, capital and operating expenditures including those related to monitoring, pollution control equipment, emission fees and permitting at various operating facilities and remediation obligations.

Illinois Resource Procurement. In January 2006, the ICC approved a reverse power procurement auction as the process by which utilities would procure power beginning in 2007. The initial 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. The Illinois legislature passed legislation in 2007 as part of the Illinois rate relief package that significantly altered the power procurement process in Illinois. The interim process (before a new state agency implements a permanent process) was approved by the ICC and implemented in Spring 2008 with the two major Illinois utilities procuring capacity and energy for the period June 2008- May 2009 through a request for proposal process. Separately, we continue to make our required payments under the rate relief package.

Mercury Emissions. In December 2006, the Illinois Pollution Control Board approved a state rule for the control of mercury emissions from coal-fired power plants that required additional capital and O&M expenditures at each of our Illinois coal-fired plants beginning in 2007. In January 2007, the State of New York also approved a mercury rule that will likely require additional capital and operating costs at our Danskammer plant.

FERC Market-Based Rate Authority. FERC’s market-based rate authority allows the sale of power at negotiated rates through the bilateral market or within an organized energy market, conditioned on periodic re-review. In June 2007, the FERC finalized a series of fundamental reforms to its market-based rate program intended to strengthen competitive markets and protect consumers by reinforcing regulations for just and reasonable wholesale electric power sales by protecting consumers from an electric power seller’s exercise of market power.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

Our next triennial market power update will be an analysis of our Northeast assets and is due between June 1, 2008 and June 30, 2008.

Guarantees and Indemnifications

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

West Coast Power Indemnities. In connection with the sale of our 50 percent interest in West Coast Power to NRG on March 31, 2006, an agreement was executed to allocate responsibility for managing certain litigation and provide for certain indemnities with respect to such litigation. The agreement states that we will manage the Gas Index Pricing Litigation described above for which NRG could suffer a loss subsequent to the closing and that we would indemnify NRG for all costs or losses resulting from such litigation, as well as from other proceedings based on similar acts or omissions, which formed the basis of such litigation. Upon execution of the California Gas Index Pricing Litigation settlement discussed above, West Coast Power will no longer be a party to any active Gas Index Pricing Litigation matters subject to this indemnity. The agreement further states that we will manage the California Market Litigation described above for which NRG could suffer a loss subsequent to the closing, and that we and NRG would each be responsible for 50 percent 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 provides that NRG will manage other active litigation and indemnify us for any resulting losses, subject to certain conditions. Maximum recourse under these matters is not limited by the agreement or by the passage of time with the exception of the California Department of Water Resources matter in which NRG has a specified indemnity obligation. The damages claimed by the various plaintiffs in these matters are unspecified as of March 31, 2008.

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 certain assets, properties and businesses disposed of by DMSLP prior to our sale of DMSLP. We have incurred no significant expense under these prior indemnities and deem their value to be insignificant. We have recorded an accrual in association with the cleanup of groundwater contamination at the Breckenridge Gas Processing Plant. The indemnification provided by DMSLP to the purchaser of the plant has a limit of $5 million. We have also indemnified Targa for certain tax matters arising from periods prior to our sale of DMSLP. We have recorded a reserve associated with this indemnification.

Illinois Power Indemnities. As a condition of Dynegy’s 2004 sale of Illinois Power and its interest in Electric Energy Inc.’s plant in Joppa, Illinois, Dynegy provided indemnifications to third parties regarding environmental, tax, employee and other representations. These indemnifications are limited to a maximum recourse of $400 million. Additionally, Dynegy has 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 Dynegy’s liability under this indemnity, the amount of the indemnity is limited to 50 percent of any such losses. In August 2007, the ICC issued its final Order in a case, which has been affirmed on appeal. Dynegy has adjusted the amount reserved for the various ongoing cases in light of this and other developments in other cases. Further disallowances and other

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

events, which fall within the scope of the indemnity, may still occur; however, Dynegy is not required to accrue a liability in connection with these indemnifications, as management cannot reasonably estimate a range of outcomes or at this time considers the probability of an adverse outcome as only reasonably possible. Dynegy intends to contest any proposed disallowances.

Other Indemnities. During 2003, as part of our sales of the Rough and Hornsea natural gas storage facilities and certain natural gas liquids assets, we provided indemnities to third parties regarding tax representations. Maximum recourse under these indemnities is limited to $857 million and $28 million, 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 the Calcasieu, CoGen Lyondell and Rockingham power generating facilities as well as the Hartwell and Commonwealth assets. We have recorded reserves for existing environmental, tax and employee liabilities and have incurred no other expense relating to these indemnities.

Note 10—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 21—Employee Compensation, Savings and Pension Plans in Dynegy’s and DHI’s Form 10-K.

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


	Pension Benefits						Other Benefits

	Three Months Ended March 31,

	2008			2007			2008		2007

	(in millions)
Service cost benefits earned during period	$	3		$	2		$	1	$	1
Interest cost on projected benefit obligation		3			3			1		1
Expected return on plan assets		(3	)		(3	)		—		—
Recognized net actuarial loss		—			1			—		—


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


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

Contributions. During the three months ended March 31, 2008 and 2007, we made no contributions to our pension plans or other postretirement benefit plans.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

Note 11—Income Taxes

Effective Tax Rate. 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. Dynegy’s income taxes included in continuing operations were as follows:


	Three Months Ended March 31,

	2008			2007

	(in millions, except rates)
Income tax benefit (expense)	$	96		$	(6	)

Effective tax rate		39	%		27	%

For the three months ended March 31, 2008, Dynegy’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to state income taxes. For the three months ended March 31, 2007, Dynegy’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to state income taxes and adjustments to our reserve for uncertain tax positions.

DHI’s income taxes included in continuing operations were as follows:


	Three Months Ended March 31,

	2008			2007

	(in millions, except rates)
Income tax benefit (expense)	$	91		$	(11	)

Effective tax rate		37	%		31	%

For the three months ended March 31, 2008, DHI’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to state income taxes. For the three months ended March 31, 2007, DHI’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to state income taxes and adjustments to our reserve for uncertain tax positions.

Note 12—Segment Information

Amounts in this footnote have been restated. Please see the Introductory Note for further discussion.

As reflected in this report, we have changed our reportable segments. Prior to this report, we reported results for the following segments: (i) GEN-MW, (ii) GEN-WE, (iii) GEN-NE and (iv) CRM. We will continue to report the results of our power generation business as three separate geographical segments in our unaudited condensed consolidated financial statements. Beginning in the first quarter 2008, the results of our former CRM segment are included in Other as it does not meet the criteria required to be an operating segment as of January 1, 2008. Accordingly, we have restated the corresponding items of segment information for prior periods. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

Reportable segment information for Dynegy, including intercompany transactions accounted for at prevailing market rates, for the three months ended March 31, 2008 and 2007 is presented below:

Dynegy’s Segment Data for the Three Months Ended March 31, 2008
(in millions)


	Power Generation

	GEN-MW			GEN-WE			GEN-NE			Other			Total

Unaffiliated revenues:
Domestic	$	164		$	131		$	179		$	(1	)	$	473
Other		—			—			72			—			72


Total revenues	$	164		$	131		$	251		$	(1	)	$	545


Depreciation and amortization	$	(53	)	$	(24	)	$	(13	)	$	(3	)	$	(93	)

Operating loss	$	(59	)	$	(46	)	$	(21	)	$	(24	)	$	(150	)

Losses from unconsolidated investments		—			(5	)		—			(4	)		(9	)
Other items, net		—			—			6			14			20
Interest expense														(109	)


Loss from continuing operations before income taxes														(248	)
Income tax benefit														96


Loss from continuing operations														(152	)
Loss from discontinued operations, net of taxes														—


Net loss													$	(152	)


Identifiable assets:
Domestic	$	7,650		$	3,778		$	1,958		$	1,380		$	14,766
Other		—			—			46			11			57


Total	$	7,650		$	3,778		$	2,004		$	1,391		$	14,823


Unconsolidated investments	$	—		$	8		$	—		$	63		$	71

Capital expenditures and investments in unconsolidated affiliates	$	(115	)	$	(3	)	$	(10	)	$	(9	)	$	(137	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

Dynegy’s Segment Data for the Three Months Ended March 31, 2007
(in millions)


	Power Generation

	GEN-MW			GEN-WE			GEN-NE			Other			Total

Unaffiliated revenues:
Domestic	$	272		$	—		$	200		$	9		$	481
Other		—			—			24			—			24

Total revenues	$	272		$	—		$	224		$	9		$	505


Depreciation and amortization	$	(42	)	$	(1	)	$	(6	)	$	(3	)	$	(52	)

Operating income (loss)	$	100		$	(2	)	$	42		$	(59	)	$	81
Other items, net		—			—			—			8			8
Interest expense														(67	)


Income from continuing operations before income taxes														22
Income tax expense														(6	)


Income from continuing operations														16
Loss from discontinued operations, net of taxes														(2	)


Net income													$	14


Identifiable assets:
Domestic	$	4,577		$	593		$	1,329		$	589		$	7,088
Other		—			7			14			98			119


Total	$	4,577		$	600		$	1,343		$	687		$	7,207


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

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

Reportable segment information for DHI, including intercompany transactions accounted for at prevailing market rates, for the three months ended March 31, 2008 and 2007 is presented below:

DHI’s Segment Data for the Three Months Ended March 31, 2008
(in millions)


	Power Generation

	GEN-MW			GEN-WE			GEN-NE			Other			Total

Unaffiliated revenues:
Domestic	$	164		$	131		$	179		$	(1	)	$	473
Other		—			—			72			—			72


Total revenues	$	164		$	131		$	251		$	(1	)	$	545


Depreciation and amortization	$	(53	)	$	(24	)	$	(13	)	$	(3	)	$	(93	)

Operating loss	$	(59	)	$	(46	)	$	(21	)	$	(24	)	$	(150	)

Losses from unconsolidated investments		—			(5	)		—			—			(5	)
Other items, net		—			—			6			14			20
Interest expense														(109	)


Loss from continuing operations before income taxes														(244	)
Income tax benefit														91


Loss from continuing operations														(153	)
Loss from discontinued operations, net of taxes														—


Net loss													$	(153	)


Identifiable assets:
Domestic	$	7,650		$	3,778		$	1,958		$	1,266		$	14,652
Other		—			—			46			11			57


Total	$	7,650		$	3,778		$	2,004		$	1,277		$	14,709


Unconsolidated investments	$	—		$	8		$	—		$	—		$	8

Capital expenditures	$	(115	)	$	(3	)	$	(10	)	$	(3	)	$	(131	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2008 and 2007

DHI’s Segment Data for the Three Months Ended March 31, 2007
(in millions)


	Power Generation

	GEN-MW			GEN-WE			GEN-NE			Other			Total

Unaffiliated revenues:
Domestic	$	272		$	—		$	200		$	9		$	481
Other		—			—			24			—			24

Total revenues	$	272		$	—		$	224		$	9		$	505


Depreciation and amortization	$	(42	)	$	(1	)	$	(6	)	$	(3	)	$	(52	)

Operating income (loss)	$	100		$	(2	)	$	42		$	(42	)	$	98
Other items, net		—			—			—			4			4
Interest expense														(67	)


Income from continuing operations before income taxes														35
Income tax expense														(11	)


Income from continuing operations														24
Loss from discontinued operations, net of taxes														(2	)


Net Income													$	22


Identifiable assets:
Domestic	$	4,577		$	598		$	1,329		$	1,001		$	7,505
Other		—			—			14			98			112


Total	$	4,577		$	598		$	1,343		$	1,099		$	7,617


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

DYNEGY INC. and DYNEGY HOLDINGS INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

For the Interim Periods Ended March 31, 2008 and 2007

Item 2—MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—DYNEGY INC. AND DYNEGY HOLDINGS INC.

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 Forms 10-K. As discussed in the Explanatory Note 1 to this Amendment No. 1, the financial information contained in this Form 10-Q/A has been revised to reflect the restatement items described in the Introductory Note to the accompanying unaudited condensed consolidated financial statements.

PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS AMENDMENT NO. 1, INCLUDING THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND THE NOTES THERETO, DOES NOT REFLECT EVENTS OCCURRING AFTER THE DATE OF THE ORIGINAL FILING. SUCH EVENTS INCLUDE, AMONG OTHERS, THE EVENTS DESCRIBED IN OUR CURRENT REPORTS ON FORM 8-K. FOR A DESCRIPTION OF THESE EVENTS, PLEASE READ OUR REPORTS FILED SINCE MAY 8, 2008, INCLUDING OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO.

We are holding companies 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: (i) the Midwest segment (“GEN-MW”); (ii) the West segment (“GEN-WE”); and (iii) the Northeast segment (“GEN-NE”). The results of our former CRM segment are included in Other as it does not meet the criteria required to be an operating segment as of January 1, 2008. Accordingly, we have restated the corresponding items of segment information for prior periods. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.

In addition to our operating generation facilities, we own an approximate 37 percent interest in PPEA which in turn owns a 57 percent undivided interest in Plum Point, a 665 MW coal-fired power generation facility under construction in Arkansas, which is included in GEN-MW. We also own a 50 percent interest in SCEA, which owns a 75 percent undivided interest in Sandy Creek, an 898 MW power generation facility under construction in McLennan County, Texas, which is included in GEN-WE. Finally, through its interest in DLS Power Holdings, Dynegy owns a 50 percent interest in a portfolio of greenfield development projects and repowering and/or expansion opportunities which is included in Other.

On March 31, 2008, we completed our sale of the Calcasieu power generation facility to Entergy for approximately $56 million, net of transaction costs.

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 (including required environmental expenditures) and working capital needs. Examples of working capital needs include prepayments or cash collateral associated with purchases of commodities, particularly natural gas and coal, facility maintenance costs 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. Additionally, DHI may borrow money from time to time from Dynegy.

Collateral Postings

We 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 business at May 2, 2008, March 31, 2008 and December 31, 2007:


	May 2, 2008		March 31, 2008		December 31, 2007

	(in millions)
By Business:
Generation	$	1,480	$	1,235	$	1,130
Other		193		193		202


Total	$	1,673	$	1,428	$	1,332

By Type:
Cash (1)	$	100	$	84	$	53
Letters of Credit		1,573		1,344		1,279


Total	$	1,673	$	1,428	$	1,332




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

The increase in collateral postings from December 31, 2007 to March 31, 2008 and to May 2, 2008 is primarily due to increased power prices associated with collateral postings supporting our normal power sales.

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. 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.

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.

As of March 31, 2008, there were no material changes to our contractual obligations and contingent financial commitments since December 31, 2007.

Dividends on Common Stock

Dividend payments on Dynegy’s common stock are at the discretion of Dynegy’s Board of Directors. Dynegy did not declare or pay a dividend on its common stock during the first quarter 2008, and does not foresee a declaration of dividends in the near term.

Internal Liquidity Sources

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

Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at May 2, 2008, March 31, 2008 and December 31, 2007:


	May 2, 2008			March 31, 2008			December 31, 2007

	(in millions)
Revolver capacity	$	1,150		$	1,150		$	1,150
Borrowings against revolver capacity		—			—			—
Term letter of credit capacity, net of required reserves		825			825			825
Plum Point and Sandy Creek letter of credit capacity		425			425			425
Outstanding letters of credit		(1,573	)		(1,344	)		(1,279	)


Unused capacity		827			1,056			1,121

Cash—DHI		317	(1)		396	(1)		292	(1)


Total available liquidity—DHI		1,144			1,452			1,413
Cash—Dynegy		28			33			36


Total available liquidity—Dynegy	$	1,172		$	1,485		$	1,449




(1)	The May 2, 2008, March 31, 2008 and December 31, 2007 amounts include approximately $14 million, $13 million and $5 million, respectively, of cash that remains in Canadian subsidiaries.

Cash Flows from Operations. Dynegy had operating cash inflows of $146 million for the three months ended March 31, 2008. This consisted of $239 million in operating cash flows from our power generation business, offset by $93 million of cash outflows relating to corporate-level expenses and our former customer risk management business.

DHI had operating cash inflows of $146 million for the three months ended March 31, 2008. This consisted of $239 million in operating cash flows from our power generation business, offset by $93 million of cash outflows relating to corporate-level expenses and our former customer risk management business.

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 and capacity. Additionally, 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, in balance with ensuring that our plants are available to operate when markets offer attractive returns.

Cash on Hand. At May 2, 2008 and March 31, 2008, Dynegy had cash on hand of $345 million and $429 million, respectively, as compared to $328 million at December 31, 2007. The increase in cash on hand as compared to the end of 2007 is primarily attributable to proceeds from the sale of the Calcasieu power generating

facility, as well as cash provided by the operations of our power generating facilities partially offset by an increase in cash margin postings on futures and exchange-cleared derivative positions.

At May 2, 2008 and March 31, 2008, DHI had cash on hand of $317 million and $396 million, respectively, as compared to $292 million at December 31, 2007. The increase in cash on hand as compared to the end of 2007 is primarily attributable to proceeds from the sale of the Calcasieu power generating facility, as well as cash provided by the operations of our power generating facilities partially offset by an increase in cash margin postings on futures and exchange-cleared derivative positions.

External Liquidity Sources

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

Asset Sale Proceeds. On March 31, 2008, we completed our sale of the Calcasieu power generation facility for approximately $56 million, net of transaction costs. Please read Note 3—Discontinued Operations—Calcasieu for further discussion.

Consistent with industry practice, we regularly evaluate our generation fleet based primarily on geographic location, fuel supply, market structure and market recovery expectations. We consider divestitures of non-core generation assets where the balance of the above factors suggests that such assets’ earnings potential is limited or that the value that can be captured through a divestiture outweighs the benefits of continuing to own and operate such assets. Moreover, dispositions of one or more generation facilities could occur in 2008 or beyond. Were any such sale or disposition to be consummated, the disposition could result in accounting charges related to the affected asset(s), and our future earnings and cash flows could be affected.

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 may explore additional sources of external liquidity. The timing of any transaction may be impacted by events, such as strategic growth opportunities, development activities, legal judgments or regulatory requirements, which could require us to pursue additional capital in the near-term. The receptiveness of the capital markets to an offering of debt or equity securities cannot be assured and may be negatively impacted by, among other things, our non-investment grade credit ratings, significant debt maturities, long-term business prospects and other factors beyond our control. Any issuance of equity by Dynegy likely would have other effects as well, including stockholder dilution. Our ability to issue debt securities is limited by our financing agreements, including our Fifth Amended and Restated Credit Facility, as amended.

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

Capital Allocation. We continually review our investment options with respect to our capital resources. We do not have any material debt maturities until 2011, and between now and then we expect to enhance our current capital resources through the results of our operating business. We will seek to invest these capital resources in various projects and activities based on their return to stockholders. Potential investments could include, among others: add-on or other enhancement projects associated with our current power generation assets; greenfield or brownfield development projects; merger and acquisition activities; and returns of capital to stockholders through, for example, a share buy-back. Capital allocation determinations generally are subject to the discretion of Dynegy’s Board of Directors as well as availability of capital and related investment opportunities, and may be limited by the provisions of our credit agreement. Any particular use of capital in an amount that is not considered material may be made without any prior public disclosure and could occur at any time.

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

RESULTS OF OPERATIONS—DYNEGY INC. and DYNEGY HOLDINGS INC.

Overview. In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the three month periods ended March 31, 2008 and 2007. At the end of this section, we have included our outlook for each segment.

As reflected in this report, we have changed our reportable segments. Prior to this report, we reported results for the following segments: (i) GEN-MW, (ii) GEN-WE, (iii) GEN-NE and (iv) CRM. We report the results of our power generation business as three separate geographical segments in our unaudited condensed consolidated financial statements. Beginning in the first quarter 2008, the results of our former CRM segment are included in Other as it does not meet the criteria required to be an operating segment as of January 1, 2008. Accordingly, we have restated the corresponding items of segment information for prior periods. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.

Summary Financial Information. The following tables provide summary financial data regarding Dynegy’s consolidated and segmented results of operations for the three month periods ended March 31, 2008 and 2007, respectively. This financial data has been restated to reflect the impact of the items described in the Introductory Note to the unaudited condensed consolidated financial statements. The restatements relate to both decreased revenues and cost of sales. Please read this Introductory Note for further discussion of these restatement items.

Dynegy’s Results of Operations for the Three Months Ended March 31, 2008


	Power Generation

	GEN-MW			GEN-WE			GEN-NE			Other			Total


Revenues	$	164		$	131		$	251		$	(1	)	$	545
Cost of sales		(124	)		(123	)		(213	)		9			(451	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(46	)		(30	)		(46	)		10			(112	)
Depreciation and amortization expense		(53	)		(24	)		(13	)		(3	)		(93	)
General and administrative expense		—			—			—			(39	)		(39	)

Operating loss	$	(59	)	$	(46	)	$	(21	)	$	(24	)	$	(150	)
Losses from unconsolidated investments		—			(5	)		—			(4	)		(9	)
Other items, net		—			—			6			14			20
Interest expense														(109	)


Loss from continuing operations before income taxes														(248	)
Income tax benefit														96


Net loss													$	(152	)

Dynegy’s Results of Operations for the Three Months Ended March 31, 2007


	Power Generation

	GEN-MW			GEN-WE			GEN-NE			Other			Total


Revenues	$	272		$	—		$	224		$	9		$	505
Cost of sales		(90	)		(1	)		(139	)		(10	)		(240	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(40	)		—			(37	)		(2	)		(79	)
Depreciation and amortization expense		(42	)		(1	)		(6	)		(3	)		(52	)
General and administrative expense		—			—			—			(53	)		(53	)

Operating income (loss)	$	100		$	(2	)	$	42		$	(59	)	$	81
Other items, net		—			—			—			8			8
Interest expense														(67	)


Income from continuing operations before income taxes														22
Income tax expense														(6	)


Income from continuing operations														16
Loss from discontinued operations, net of taxes														(2	)


Net income													$	14

The following tables provide summary financial data regarding DHI’s consolidated and segmented results of operations for the three month periods ended March 31, 2008 and 2007, respectively:

DHI’s Results of Operations for the Three Months Ended March 31, 2008


	Power Generation

	GEN-MW			GEN-WE			GEN-NE			Other			Total


Revenues	$	164		$	131		$	251		$	(1	)	$	545
Cost of sales		(124	)		(123	)		(213	)		9			(451	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(46	)		(30	)		(46	)		10			(112	)
Depreciation and amortization expense		(53	)		(24	)		(13	)		(3	)		(93	)
General and administrative expense		—			—			—			(39	)		(39	)

Operating loss	$	(59	)	$	(46	)	$	(21	)	$	(24	)	$	(150	)
Losses from unconsolidated investments		—			(5	)		—			—			(5	)
Other items, net		—			—			6			14			20
Interest expense														(109	)


Loss from continuing operations before income taxes														(244	)
Income tax benefit														91


Net loss													$	(153	)

DHI’s Results of Operations for the Three Months Ended March 31, 2007


	Power Generation

	GEN-MW			GEN-WE			GEN-NE			Other			Total


Revenues	$	272		$	—		$	224		$	9		$	505
Cost of sales		(90	)		(1	)		(139	)		(10	)		(240	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(40	)		—			(37	)		(2	)		(79	)
Depreciation and amortization expense		(42	)		(1	)		(6	)		(3	)		(52	)
General and administrative expense		—			—			—			(36	)		(36	)


Operating income (loss)	$	100		$	(2	)	$	42		$	(42	)	$	98
Other items, net		—			—			—			4			4
Interest expense														(67	)


Income from continuing operations before income taxes														35
Income tax expense														(11	)

Income from continuing operations														24
Loss from discontinued operations, net of taxes														(2	)


Net income													$	22

The following table provides summary segmented operating statistics for the three months ended March 31, 2008 and 2007, respectively:


	Three Months Ended March 31,

	2008			2007

GEN-MW
Million Megawatt Hours Generated		5.9			5.7
In Market Availability for Coal Fired Facilities (1)		82	%		89	%
Average Capacity Factor for Combined Cycle Facilities (2)		10	%		—
Average Actual On-Peak Market Power Prices ($/MWh) (3):
Cinergy (Cin Hub)	$	68		$	56
Commonwealth Edison (NI Hub)	$	68		$	54
PJM West	$	79		$	65
Average Market Spark Spreads ($/MWh) (4):
PJM West	$	9		$	6

GEN-WE
Million Megawatt Hours Generated (5) (6)		2.4			0.1
Average Capacity Factor for Combined Cycle Facilities (2)		37	%		—
Average Actual On-Peak Market Power Prices ($/MWh) (3):
North Path 15 (NP 15)	$	80		$	60
Palo Verde	$	70		$	55
Average Market Spark Spreads ($/MWh) (4):
North Path 15 (NP 15)	$	18		$	8
Palo Verde	$	9		$	5

GEN-NE
Million Megawatt Hours Generated		1.9			2.0
In Market Availability for Coal Fired Facilities (1)		94	%		89	%
Average Capacity Factor for Combined Cycle Facilities (2)		24	%		30	%
Average Actual On-Peak Market Power Prices ($/MWh) (3):
New York—Zone G	$	97		$	85
New York—Zone A	$	68		$	63
Mass Hub	$	90		$	80
Average Market Spark Spreads ($/MWh) (4):
New York—Zone A	$	4		$	11
Mass Hub	$	19		$	20
Fuel Oil	$	(35	)	$	9

Average natural gas price—Henry Hub ($/MMBtu) (7)	$	8.58		$	7.16



(1)	Reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched.

(2)	Reflects actual production as a percentage of available capacity.

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

(4)	Reflects the simple average of the spark spread available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price and does not reflect spark spreads available to the Company.

(5)	Includes our ownership percentage in the MWh generated by our GEN-WE investment in the Black Mountain power generation facility for the three months ended March 31, 2008 and 2007, respectively.

(6)	Excludes approximately 0.7 million MWh generated by our CoGen Lyondell power generation facility, which we sold in August 2007, for the three months ended March 31, 2007 and less than


	0.1 million MWh generated by our Calcasieu power generation facility, which we sold on March 31, 2008, for the three months ended March 31, 2008 and 2007, respectively.

(7)	Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by the Company.

The following table summarizes Dynegy’s significant items on a pre-tax basis affecting net income for the period presented:


	Three Months Ended March 31, 2007

	Power Generation

	GEN-MW		GEN-WE		GEN-NE		Other			Total

	(in millions)
Legal and settlement charges	$	—	$	—	$	—	$	(17	)	$	(17	)


Total	$	—	$	—	$	—	$	(17	)	$	(17	)

There were no such items reported for the three months ended March 31, 2008.

Operating Income (Loss)

Operating loss for Dynegy was $150 million for the three months ended March 31, 2008, compared to operating income of $81 million for the three months ended March 31, 2007. Operating loss for DHI was $150 million for the three months ended March 31, 2008, compared to operating income of $98 million for the three months ended March 31, 2007.

Our operating loss for the first quarter of 2008 was driven, in large part, by mark-to-market losses on forward sales of power associated with our generating assets. Such losses, which totaled $284 million for the three months ended March 31, 2008, were a result of an increase in market power prices or spark spreads during the first quarter 2008 combined with greater outstanding notional amounts of forward positions compared to the same period in the prior year partially due to the Merger. Effective April 2, 2007, we chose to cease designating our commodity derivative instruments as cash flow hedges for accounting purposes. Please see Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion. The resulting mark-to-market accounting treatment results in the immediate recognition of gains and losses within the unaudited condensed consolidated statements of operations due to changes in the fair value of the derivative instruments. As such, these mark-to-market gains and losses are not reflected in the unaudited condensed consolidated statement of operations in the same period as the underlying power sales from generation activity for which the derivative instruments serve as economic hedges. Except for those positions that settled in the three months ended March 31, 2008, the expected cash impact of the settlement of these positions will be recognized over time through the end of 2010 based on the prices at which such positions are contracted. Dynegy’s overall mark-to-market position and the related mark-to-market value will change as we buy or sell volumes within the market and as forward commodity prices fluctuate.

Power Generation—Midwest Segment. Operating loss for GEN-MW was $59 million for the three months ended March 31, 2008, compared to operating income of $100 million for the three months ended March 31, 2007.

Revenues for the three months ended March 31, 2008 decreased by $108 million compared to the three months ended March 31, 2007, cost of sales increased by $34 million and operating and maintenance expense increased by $6 million, resulting in a net decrease of $148 million. The decrease was primarily driven by the following:


	•	Mark-to-market losses – GEN-MW’s results for the three months ended March 31, 2008 included mark-to-market losses of $193 million related to forward sales, compared to $19 million of mark-to-market losses for the three months ended March 31, 2007. Of the $193 million in 2008 mark-to-market losses, $155 million related to positions that settled or will settle in 2008, and the remaining $38 million related to positions that will settle in 2009 and beyond.


	This item was partly offset by the following:

	•	The addition of the Midwest plants acquired through the Merger – Generated volumes were 5.9 million MWh for the three months ended March 31, 2008, up from 5.7 million MWh for the three months ended March 31, 2007. The volume increase was primarily driven by the Kendall and Ontelaunee plants acquired on April 2, 2007, which offset a decrease in volumes caused by forced outages at two of our coal-fired facilities. Kendall and Ontelaunee provided results of $22 million for the three months ended March 31, 2008, exclusive of mark-to-market losses discussed above; and

	•	Increased market prices – The average actual on-peak prices in the Cin Hub pricing region increased from $56 per MWh for the three months ended March 31, 2007 to $68 per MWh for the three months ended March 31, 2008.

Depreciation expense increased from $42 million for the first quarter 2007 to $53 million for the first quarter 2008 primarily as a result of the addition of the Midwest plants.

Power Generation—West Segment. Operating loss for GEN-WE was $46 million for three months ended March 31, 2008, compared to a loss of $2 million for the three months ended March 31, 2007. Such amounts do not include results from our CoGen Lyondell and Calcasieu power generation facilities, which have been classified as discontinued operations for all periods presented.

Revenues for the three months ended March 31, 2008 increased by $131 million compared to the three months ended March 31, 2007, cost of sales increased by $122 million and operating and maintenance expense increased by $30 million, resulting in a net decrease of $21 million. The decrease was primarily driven by the following:


	•	Mark-to-market losses – GEN-WE’s results for the three months ended March 31, 2008 included mark-to-market losses of $47 million, compared to $2 million of mark-to-market losses for the three months ended March 31, 2007. Of the $47 million in 2008 mark-to-market losses, $44 million related to positions that settled or will settle in 2008, and the remaining $3 million related to positions that will settle in 2009 and beyond.

	This item was offset by the following:

	•	The addition of the West plants acquired through the Merger – Generated volumes were 2.4 million MWh for the three months ended March 31, 2008, up from 0.1 million MWh for the three months ended March 31, 2007. The volume increase was primarily driven by the West plants acquired on April 2, 2007, which provided total results of $25 million for the three months ended March 31, 2008, exclusive of mark-to-market losses discussed above. Results for the first quarter 2008 were negatively impacted by a forced outage.

Depreciation expense increased from $1 million for the first quarter 2007 to $24 million for the first quarter 2008 primarily as a result of the addition of the West plants.

Power Generation—Northeast Segment. Operating loss for GEN-NE was $21 million for the three months ended March 31, 2008, compared to operating income of $42 million for the three months ended March 31, 2007.

Revenues for the three months ended March 31, 2008 increased by $27 million compared to the three months ended March 31, 2007, cost of sales increased by $74 million and operating and maintenance expense increased by $9 million, resulting in a net decrease of $56 million. The decrease was primarily driven by the following:


	•	Mark-to-market losses – GEN-NE’s results for the three months ended March 31, 2008 included mark-to-market losses of $44 million related to forward sales, compared to losses of $2 million for the three months ended March 31, 2007. Of the $44 million in 2008 mark-to-market losses, $25 million related to positions that settled or will settle in 2008, and the remaining $19 million related to positions that will settle in 2009 and beyond;

	•	Decreased spark spreads – Although on peak market prices in New York Zone G and Zone A increased by 14 percent and eight percent, respectively, spark spreads contracted as a result of higher fuel prices.


		Average market spark spreads decreased 64 percent and five percent for New York Zone A and Mass Hub, respectively; and

	•	Lower volumes – In spite of the addition of the Northeast plants acquired through the Merger on April 2, 2007, generated volumes decreased by five percent, from 2.0 million MWh for the three months ended March 31, 2007 to 1.9 million MWh for the three months ended March 31, 2008. The volumes added by the new Northeast plants were more than offset by a decrease in generated volumes at our Roseton and Independence facilities, which were affected by higher fuel prices and decreased spark spreads.

	These items were partly offset by the following:

	•	The addition of the Northeast plants acquired through the Merger – The Bridgeport and Casco Bay plants acquired on April 2, 2007 provided total results of $9 million for the three months ended March 31, 2008, exclusive of mark-to-market losses discussed above.

Depreciation expense increased from $6 million for the first quarter 2007 to $13 million for the first quarter 2008 as a result of the addition of the Casco Bay and Bridgeport plants.

Other. Dynegy’s Other operating loss for the three months ended March 31, 2008 was $24 million, compared to an operating loss of $59 million for the three months ended March 31, 2007. Operating losses in both periods were comprised primarily of general and administrative expenses and results from our former customer risk management business.

Cost of sales for the three months ended March 31, 2008 included the release of a $9 million liability associated with an assignment of a natural gas transportation contract. Operating and maintenance expense for the three months ended March 31, 2008 included the release of an $8 million of sales and use tax liability.

Dynegy’s consolidated general and administrative expenses were $39 million and $53 million for the three months ended March 31, 2008 and 2007, respectively. General and administrative expenses for the three months ended March 31, 2007 included legal and settlement charges of $17 million resulting from additional activities during the period that negatively affected management’s assessment of the probable and estimable losses associated with the applicable proceedings.

DHI’s other operating loss for the three months ended March 31, 2008 was $24 million, compared to an operating loss of $42 million for the three months ended March 31, 2007. Operating losses in both periods were comprised primarily of general and administrative expenses and results from our former customer risk management business.

Cost of sales for the three months ended March 31, 2008 included the release of a $9 million reserve associated with natural gas transportation contracts. Operating and maintenance expense for the three months ended March 31, 2008 included the release of an $8 million of sales and use tax liability.

DHI’s consolidated general and administrative expenses were $39 million and $36 million for the three months ended March 31, 2008 and 2007, respectively.

Losses from Unconsolidated Investments

Dynegy’s losses from unconsolidated investments were $9 million for the three months ended March 31, 2008, including a $5 million loss related to the GEN-WE investment in Sandy Creek. The remaining $4 million loss related to its investment in DLS Power Development, included in Other. Earnings from unconsolidated investments for the three months ended March 31, 2007 were zero.

DHI’s losses from unconsolidated investments of $5 million for the three months ended March 31, 2008 related to the GEN-WE investment in Sandy Creek. Earnings from unconsolidated investments for the three months ended March 31, 2007 were zero.

Other Items, Net

Dynegy’s other items, net, totaled $20 million of income for the three months ended March 31, 2008, compared to $8 million of income for the three months ended March 31, 2007. Approximately $6 million of the increase was associated with higher interest income due to larger cash balances in 2008. In addition, during the first quarter 2008, we recognized income of $6 million related to insurance proceeds received in excess of the book value of damaged assets.

DHI’s other items, net, totaled $20 million of net income for the three months ended March 31, 2008, compared to $4 million of income for the three months ended March 31, 2007. Approximately $7 million of the increase was primarily associated with higher interest income due to larger cash balances in 2008. In addition, during the first quarter 2008, we recognized income of $6 million related to insurance proceeds received in excess of the book value of damaged assets.

Interest Expense

Dynegy’s and DHI’s interest expense totaled $109 million for the three months ended March 31, 2008, compared to $67 million for the three months ended March 31, 2007. The increase was primarily attributable to the issuance of the $1.65 billion of Senior Unsecured Notes on May 24, 2007, which replaced the project debt assumed in connection with the Merger, and secondarily to the associated growth in the size and utilization of our Fifth Amended and Restated Credit Facility.

Income Tax Benefit (Expense)

Dynegy reported an income tax benefit from continuing operations of $96 million for the three months ended March 31, 2008, compared to an income tax expense from continuing operations of $6 million for the three months ended March 31, 2007. The 2008 effective tax rate was 39 percent, compared to 27 percent in 2007.

DHI reported an income tax benefit from continuing operations of $91 million for the three months ended March 31, 2008, compared to an income tax expense of $11 million from continuing operations for the three months ended March 31, 2007. The 2008 effective tax rate was 37 percent, compared to 31 percent in 2007.

In general, differences between these effective rates and the statutory rate of 35 percent resulted primarily from the effect of state income taxes in the taxing jurisdictions in which our assets operate.

Discontinued Operations

Loss From Discontinued Operations Before Taxes

During the three months ended March 31, 2008, our pre-tax loss from discontinued operations was $1 million, which consisted of a $1 million loss on the sale of the Calcasieu power generation facility. During the three months ended March 31, 2007, our pre-tax loss from discontinued operations was $3 million, which consisted of losses of $3 million from the operation of the CoGen Lyondell power generation facility.

Income Tax Benefit From Discontinued Operations

We recorded an income tax benefit from discontinued operations of $1million and $1 million, respectively, during the three months ended March 31, 2008 and 2007. The effective rates for the three months ended March 31, 2008 and 2007 were 100 percent and 33 percent, respectively. FIN No. 18, “Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28” requires 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 percent.

Outlook

We expect that our future financial results will continue to reflect sensitivity to fuel and commodity prices, market structure and prices for electric energy, ancillary services and capacity, transportation and transmission logistics, weather conditions and IMA. Our commercial team actively manages commodity price risk associated with our unsold power production by trading in the forward markets that are correlated with our assets. We also participate in various regional auctions and bilateral opportunities. Our regional commercial strategies are particularly driven by the types of units that we have within a given region and the operating characteristics of those units.

Our fleet includes a diverse mixture of assets with various fuel, dispatch and merit order characteristics within each of our three regions. Our forward sales decisions are based on market fundamentals relative to each regional fleet profile. Our portfolio of sales agreements include short-term, medium-term and long-term contracts that range to five years and longer. These long-term contracts are generally intended to run to term and may include tolls or long-term power sale agreements related to our development projects. These contracts include terms designed to mitigate risks related to commodity prices and operation of the facilities such as a pass through of fuel costs and limited penalties for unavailability. Medium-term contracts, which range from two to five years, include structured deals and financial products, including options, and are intended to capture value from mid-term price trends but still provide some exposure to expected longer term upward price trends. We seek to commercialize the remainder of our fleet’s output via short-term sales, financial products, including options, spot sales and contract sales, all with a duration of less than two years. We actively manage these positions, which are primarily associated with our baseload facilities, in an attempt to capitalize on commodity price volatility and other value capture opportunities. As a result, our fleet-wide forward sales profile is fluid and subject to change over time.

We entered the year with a substantial portion of the output from our fleet of power generation facilities contracted for 2008. We commercialized nearly all of our output for the remainder of 2008 as we moved forward through the first quarter of 2008 and prices increased. As we look forward to 2009 and beyond, we are actively transacting in 2009 positions and expect to enter 2009 with a substantial portion of the output of our fleet contracted. Based on specific market conditions, at any point in time we may be above or below this level since we actively manage our near-term market positions of less than two years.

To the extent that we choose not to enter into forward sales, the gross margin from our assets is a function of price movements in the coal, natural gas, fuel oil, electric energy and capacity markets.

The following summarizes unique business issues impacting our individual regions’ outlook.

GEN-MW. Our Midwest consent decree requires substantial emission reductions from our Illinois coal-fired power plants and the completion of several supplemental environmental projects in the Midwest. We have achieved all emission reductions scheduled to date under the Consent Decree and are developing plans to install additional emission control equipment to meet future Consent Decree emission limits. We expect our costs associated with the Midwest consent decree projects, which we expect to incur through 2012, to be approximately $960 million, which includes approximately $134 million spent to date. This estimate includes a number of assumptions and uncertainties beyond our control, including an assumption that labor and material costs will increase at four percent per year over the remaining project term.

Our Midwest coal requirements are 100 percent contracted through 2010. For 2008, the prices associated with these contracts are fixed. The new prices that will apply to the 25 percent of our post-2008 requirements that are currently unpriced will become effective January 1, 2009. However, we expect that any price changes will be consistent with DMG’s historical price trend over the past several years.

PJM recently implemented a forward capacity auction, the Reliability Pricing Model. The auction has resulted in a dramatic increase in the value of capacity in not only PJM, but in the neighboring MISO as well. The increase in prices indicates a projected tightening of the supply/demand balance in the near future. More immediately, we benefited from participating in the auction process, resulting in sales of capacity for the following planning years:


	Planning Year		Net Capacity

			(in MWs)
	2008-2009		1,300
	2009-2010		2,650
	2010-2011		2,750

The MISO has delayed implementation of its Ancillary Services Market until September 2008. Upon implementation MISO will administer the Ancillary Services Market through which load-serving entities will procure regulation and contingency reserves.

GEN-WE. Our Arizona facilities recently won competitive solicitations for 10 year term tolling agreements by local utilities beginning with deliveries in 2008 and 2010.

GEN-NE. The majority of our coal supply requirements for 2008 are contracted at a fixed price. We procure certain quantities of coal from various South American suppliers, where political conditions could potentially result in interruptions of commodity exports. However, we continue to maintain sufficient coal and oil inventories and contractual commitments intended to provide us with a stable fuel supply and are considering options to further mitigate cost and supply risks for near and long-term coal supplies.

In New England, the ISO-NE is in the process of restructuring its capacity market and will be transitioning to a forward capacity market in 2010. During the transition from the pre-existing capacity markets in ISO-NE to the forward capacity market, all listed Installed Capacity (“ICAP”) resources will receive monthly capacity payments, adjusted for each Power Year. The transitional payments for capacity commenced in December 2006, with a price of 3.05/KW-month, and gradually rise to $4.10/KW-month through June 1, 2010, when the forward capacity market will be fully effective. The first auction for the 2010 Power Year was held in February 2008, and capacity prices cleared at $4.50/KW-month. The second auction for the 2011 Power Year is planned for the fall of 2008.

Recently, we arrived at a settlement with one of the local taxing jurisdictions in connection with the assessed value of our Roseton and Danskammer generating facilities. While the amount of actual tax savings resulting from the reduction in the assessed value of these facilities will depend on future budgets of the various taxing jurisdictions, the projected savings in property taxes for the period 2008-2012 is approximately $55 million. We will also receive a refund of $3 million for prior years’ property tax payments. We continue to work with local authorities to consider additional settlements relating to taxes paid in prior years.

Regulatory Matters

Climate Change and Greenhouse Gases. The federal government, and many states where we have generation facilities, are considering or implementing regulatory programs intended to reduce emissions of CO2 as a means of addressing climate change issues. The adoption of regulatory programs mandating a substantial reduction in C02 emissions may have a significant impact on us and others in the power generating industry. However, at this time, we are unable to provide an accurate assessment of the extent of the impact that CO2 emission reduction programs will have on us. Any CO2 emission limits that are implemented, whether by the federal or state governments, could have the effect of altering the manner in which generating facilities are dispatched. The extent to which the costs of meeting mandated emission reductions would be borne by power generators, or the ultimate users of electricity, is not known. The specific requirements and timing of any future federal program to regulate CO2 emissions cannot be confidently predicted at this time; however, various states where we have generating facilities have proposed or are in the process of considering or developing regulatory programs to limit CO2 emissions.

GEN-WE. Our assets in California will be subject to various state initiatives. As previously disclosed, we continue to be subject to the California Global Warming Solutions Act, effective January 1, 2007, which requires development of a greenhouse gas control program that will reduce the state’s greenhouse gas emissions to their 1990 levels by 2020. Regulations to achieve required emission reductions are to be adopted by January 2011.

The California State Water Resources Control Board has issued proposed regulations that would require all power plants utilizing sea water for once-through cooling to reduce their intake flow and intake velocity to a level commensurate with that which can be attained by a closed-cycle cooling system. If adopted as proposed, it is likely that South Bay, Morro Bay and Moss Landing Units 6 & 7 would be required to retrofit with a closed-cycle cooling system by 2015 and the Moss Landing Units 1 & 2 by 2018.

GEN-NE. Our assets in New York, Connecticut and Maine are expected to become subject to a state-driven greenhouse gas program known as the Regional Greenhouse Gas Initiative (“RGGI”) as soon as 2009. The participating RGGI states have developed a model rule for regulating greenhouse gas using a cap-and-trade program to reduce carbon emissions by at least 10 percent of current emission levels by the year 2018.

The RGGI rules proposed in Maine and New York would implement CO2 cap-and-trade programs, capping total authorized CO2 emissions from affected power generators beginning in 2009. The proposed rules would require that each affected power generator hold CO2 emission allowances equal to its annual CO2 emissions. Beginning in 2015, the CO2 emission caps and available allowances would be reduced each year until 2018. Compliance with the allowance requirement under a cap-and-trade program could be achieved by reducing emissions, purchasing allowances or securing offset allowances from an approved offset project. Allowances would be distributed to power generators through state auctions. Although the rules governing the procedures and structure of the auctions are still being developed, the intent is to conduct the first auction of CO2 allowances in 2008.

The State of Connecticut also enacted legislation in June 2007 that mandates a cap and trade program for CO2, including a requirement that affected generators purchase the carbon credits needed to operate their facilities through an auction process. The rules governing the procedures and structure of the Connecticut auction process are still being developed.

Please read Note 9—Commitments and Contingencies—Danskammer State Pollutant Discharge Elimination System Permit and —Commitments and Contingencies—Roseton State Pollutant Discharge Elimination System Permit, respectively, for further discussion.

Cash Flow Disclosures

Operating Cash Flow

Dynegy. Dynegy’s cash flow provided by operations totaled $146 million for the three months ended March 31, 2008. During the three months ended March 31, 2008, our power generation business provided positive cash flow from operations of $234 million from the operation of our power generation facilities. Other includes a use of approximately $88 million in cash primarily due to interest payments to service debt, general and administrative expenses and a legal settlement payment previously reserved, partially offset by interest income.

Dynegy’s cash flow provided by operations totaled $44 million for the three months ended March 31, 2007. During the quarter, our power generation business provided positive cash flow from operations of $140 million due to positive earnings for the period. Other includes a net use of approximately $96 million in cash primarily due to interest payments to service debt, general and administrative expenses and cash payments associated with our former customer risk management business.

DHI. DHI’s cash flow provided by operations totaled $146 million for the three months ended March 31, 2008. During the three months ended March 31, 2008, our power generation business provided positive cash flow from operations of $234 million from the operation of our power generation facilities. Other includes a use of approximately $88 million in cash primarily due to interest payments to service debt, general and administrative expense and a legal settlement payment previously reserved, partially offset by interest income.

DHI’s cash flow provided by operations totaled $43 million for the three months ended March 31, 2007. During the quarter, our power generation business provided positive cash flow from operations of $140 million due to positive earnings for the period. Other includes a net use of approximately $97 million in cash primarily due to interest payments to service debt, general and administrative expenses and cash payments associated with our former customer risk management business.

Capital Expenditures and Investing Activities

Dynegy. Dynegy’s cash used in investing activities during the three months ended March 31, 2008 totaled $95 million. Capital spending of $131 million was primarily comprised of $115 million, $3 million and $10 million for our GEN-MW, GEN-WE and GEN-NE segments, respectively. Capital spending for the GEN-MW segment includes $54 million associated with the construction of the Plum Point facility, which is provided by non-recourse project financing. The remaining capital spending for the GEN-MW segment primarily related to maintenance and environmental projects, while spending in the GEN-NE and GEN-WE segments primarily related to maintenance projects. In addition, there was approximately $3 million of capital expenditures in Other. Dynegy also made $6 million in contributions to DLS Power Holdings during the three months ended March 31, 2008. Additionally, there was a $25 million cash outflow due to changes in restricted cash balances. These cash outflows were partially offset by $56 million of proceeds, net of transaction costs, from the sale of the Calcasieu power generating facility, $6 million of insurance proceeds and $4 million of proceeds from the liquidation of an investment.

Dynegy’s cash used in investing activities during the three months ended March 31, 2007 totaled $26 million. Capital spending of $34 million was primarily comprised of $23 million, $5 million and $3 million in the GEN-MW, GEN-WE and GEN-NE segments, respectively. The capital spending for each segment primarily related to maintenance and environmental capital projects. In addition, there was approximately $3 million of capital expenditures in Other related to corporate information technology projects. Cash outflows associated with capital spending were partly offset by a $9 million decrease in the Independence restricted cash balance.

DHI. DHI’s cash used in investing activities during the three months ended March 31, 2008 totaled $92 million. Capital spending of $131 million was primarily comprised of $115 million, $3 million and $10 million for our GEN-MW, GEN-WE and GEN-NE segments, respectively. Capital spending for the GEN-MW segment includes $54 million associated with the construction of the Plum Point facility, which is provided by non-recourse project financing. The remaining capital spending for the GEN-MW segment primarily related to maintenance and environmental projects, while spending in the GEN-NE and GEN-WE segments primarily related to maintenance projects. In addition, there was approximately $3 million of capital expenditures in Other. Additionally, there was a $25 million cash outflow due to changes in restricted cash balances. These cash outflows were partially offset by $56 million of proceeds, net of transaction costs, from the sale of the Calcasieu power generating facility, $1 million of affiliate transactions and $6 million of insurance proceeds.

DHI’s cash used in investing activities during the three months ended March 31, 2007 totaled $33 million. Capital spending of $34 million was primarily comprised of $23 million, $5 million and $3 million in the GEN-MW, GEN-WE and GEN-NE segments, respectively. The capital spending for each segment primarily related to maintenance and environmental capital projects. In addition, there was approximately $3 million of capital expenditures in Other related to corporate information technology projects. Cash outflows associated with capital spending were partly offset by a $9 million decrease in the Independence restricted cash balance.

Financing Activities

Dynegy. Dynegy’s cash provided by financing activities during the three months ended March 31, 2008 totaled $50 million, which primarily related to proceeds from long-term borrowings under the Plum Point Credit Agreement Facility.

Dynegy’s cash used in financing activities during the three months ended March 31, 2007 totaled $20 million, resulting primarily from a principal payment on the Sithe Energies debt.

DHI. DHI’s cash provided by financing activities during the three months ended March 31, 2008 totaled $50 million, which primarily related to proceeds from long-term borrowings under the Plum Point Credit Agreement Facility.

DHI’s cash used in financing activities during the three months ended March 31, 2007 totaled $70 million, resulting primarily from a $50 million dividend payment to Dynegy and a $19 million principal payment on the Sithe Energies debt.

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 Three Months Ended March 31, 2008

	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2008	$	(100	)
Risk-management losses recognized through the income statement in the period, net		(271	)
Cash paid related to risk-management contracts settled in the period, net		1
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other (2)		(33	)


Fair value of portfolio at March 31, 2008	$	(403	)



(1)	Our modeling methodology has been consistently applied.

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

The net risk management liability of $403 million is the aggregate of the following line items on our unaudited 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. During the period from December 31, 2007 to March 31, 2008, our Current Assets—Assets from risk-management activities and Current Liabilities—Liabilities from risk-management activities increased by $1.4 billion and $1.6 billion, respectively. This increase was primarily a result of increased volumes of purchases and sales of commodities via financial instruments. These amounts are reflected gross on our condensed consolidated balance sheets, as we do not offset fair value amounts recognized for derivative instruments executed with the same counterparties under a master netting agreement. However, a substantial portion of the financial instruments are with the same counterparty, resulting in a significantly smaller increase in our net risk-management liability, as denoted above. For further information regarding our counterparty credit exposure associated with risk-management accounts, please see Item 3. Quantitative and Qualitative Disclosures about Market Risk—Credit Risk.

Risk-Management Asset and Liability Disclosures. The following tables depict the mark-to-market value and cash flow components of our net risk-management liabilities at March 31, 2008 and December 31, 2007. 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 Liabilities (1)


	Total			2008 (2)			2009			2010			2011		2012		Thereafter

	(in millions)
March 31, 2008	$	(335	)	$	(242	)	$	(85	)	$	(15	)	$	2	$	1	$	4
December 31, 2007		(66	)		(30	)		(29	)		(12	)		1		1		3


Increase (decrease) (3)	$	(269	)	$	(212	)	$	(56	)	$	(3	)	$	1	$	—	$	1



(1)	The table reflects the fair value of our net risk-management liability position, which considers time value, credit, price and other reserves necessary to determine fair value. These amounts exclude the fair value


	associated with certain derivative instruments designated as hedges. The net risk-management liabilities at March 31, 2008 of $403 million on the unaudited condensed consolidated balance sheets include the $335 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)	Amounts represent April 1 to December 31, 2008 values in the March 31, 2008 row and January 1 to December 31, 2008 values in the December 31, 2007 row.

(3)	The increase in the net risk management liability is due to an increase in the volume of outstanding positions during the three months ended March 31, 2008 as well as a significant increase in the prices associated with these positions.

Cash Flow Components of Net Risk-Management Liabilities


	Three Months Ended March 31, 2008			Nine Months Ended December 31, 2008			Total 2008			2009			2010			2011			2012		Thereafter

	(in millions)
March 31, 2008 (1)	$	(6	)	$	(225	)	$	(231	)	$	(80	)	$	(14	)	$	1		$	1	$	5
December 31, 2007								(28	)		(27	)		(12	)		2			1		5


Increase (decrease)							$	(203	)	$	(53	)	$	(2	)	$	(1	)	$	—	$	—



(1)	The cash flow values for 2008 reflect realized cash flows for the three months ended March 31, 2008 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.

The following table provides an assessment of net contract values by year as of March 31, 2008, based on our valuation methodology:

Net Fair Value of Risk-Management Portfolio


	Total			2008			2009			2010			2011		2012		Thereafter

	(in millions)
Market quotations (1)	$	(344	)	$	(278	)	$	(68	)	$	(5	)	$	2	$	1	$	4
Prices based on models		(59	)		(32	)		(17	)		(10	)		—		—		—


Total (2)	$	(403	)	$	(310	)	$	(85	)	$	(15	)	$	2	$	1	$	4



(1)	Prices obtained from actively traded, liquid markets for commodities other than natural gas positions. All natural gas positions for all periods are contained in this line based on available market quotations.

(2)	The market quotations and prices based on models categorization differs from the SFAS No. 157 categories of Level 1, Level 2 and Level 3 due to the application of the different methodologies. Please see Note 4—Risk Management Activities, Derivatives and Financial Instruments—Fair Value Measurements for further discussion.

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-Q/A includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements” by both Dynegy and DHI. 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:


	•	beliefs about commodity pricing and generation volumes;

	•	sufficiency of and access to coal, fuel oil and natural gas inventories and transportation;

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

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

	•	beliefs and assumptions about weather, economic conditions and the demand for electricity;

	•	expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations, including those relating to climate change;

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

	•	strategies to address our substantial leverage or to access the capital markets;

	•	beliefs and assumptions relating to liquidity;

	•	beliefs and expectations regarding financing, development and timing of any and all joint venture projects;

	•	anticipated benefits of diversifying our operations;

	•	expectations regarding capital expenditures, interest expense and other payments;

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

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

	•	expectations and estimates regarding the Midwest consent decree and the associated costs; and

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

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

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1—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” of Dynegy’s and DHI’s Form 10-K for a complete description of our critical accounting policies, with respect to which there have been no other material changes since the filing of such Form 10-K.

Item 4—CONTROLS AND PROCEDURES—DYNEGY INC. AND DYNEGY HOLDINGS INC.

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 Dynegy’s and DHI’s management, including their Chief Executive Officer and their Chief Financial Officer, of the effectiveness of the design and operation of the consolidated enterprise’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). This evaluation included consideration of the various processes carried out under the direction of Dynegy’s disclosure committee in an effort to ensure that information required to be disclosed in the consolidated enterprise’s SEC reports is recorded, processed, summarized and reported within the time periods specified by the SEC. This evaluation also considered the work completed as of the end of the first quarter 2008 relating to Dynegy’s and DHI’s compliance with Section 404 of the Sarbanes-Oxley Act of 2002.

In connection with the restatement of our unaudited condensed consolidated financial statements for the quarter ended March 31, 2008 to correct a misstatement of revenues that was offset in cost of sales, we reevaluated our disclosure controls and procedures. In connection with the preparation of this Form 10-Q/A, an evaluation of the effectiveness of the design and operation of the consolidated enterprise’s disclosure controls and procedures was carried out under the supervision and with the participation of Dynegy’s and DHI’s management, including their Chief Executive Officer and their Chief Financial Officer. In making this evaluation, our management considered the material weakness below. Based on this evaluation, Dynegy’s and DHI’s CEO and CFO concluded that Dynegy’s and DHI’s disclosure controls and procedures were not effective as of March 31, 2008.

Notwithstanding the material weakness that existed at March 31, 2008, 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.

Material Weakness Related to Revenues and Cost of Sales

Subsequent to the filing of our Quarterly Report on Form 10-Q for the period ended March 31, 2008, we identified a misstatement of revenues that was offset in cost of sales for the three months ended March 31, 2008. Accordingly, in this Form 10-Q/A, we have restated our unaudited condensed consolidated financial statements. For further information, please see the Introductory Note in the accompanying unaudited condensed consolidated financial statements.

As a result of this misstatement, we have concluded that we did not maintain effective controls as of March 31, 2008 over the accuracy of our revenues and cost of sales amounts. Our processes, procedures and controls related to the calculation and analysis of the presentation of revenues and cost of sales related to energy trading

activities on a net basis were not effective to ensure that the revenues and cost of sales amounts were accurately reflected in the financial statements at March 31, 2008. This control deficiency resulted in the restatement of our March 31, 2008 financial statements by a material amount. Therefore, we concluded that this control deficiency, as of March 31, 2008, constitutes a material weakness.

In order to remediate this material weakness, we have implemented the following steps: (i) further formalized and documented the change management procedures surrounding the quarterly revenue netting calculation; (ii) expanded the management review of the calculation; and (iii) formalized and documented additional analysis to be performed on our revenues and cost of sales amounts.

Changes in Internal Controls Over Financial Reporting

Other than as noted above in this Item 4, there were no changes in the consolidated enterprise’s internal control over financial reporting that have materially affected or are reasonably likely to materially affect the consolidated enterprise’s internal control over financial reporting during the first quarter 2008.

DYNEGY INC. and DYNEGY HOLDINGS INC.

PART II. OTHER INFORMATION

Item 6—EXHIBITS—DYNEGY INC. AND DYNEGY HOLDINGS INC.

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


	Exhibit Number		Description

	10.1		Dynegy Inc. Executive Severance Pay Plan, as amended and restated, effective January 1, 2008 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on January 4, 2008, File No. 001-33443).

	10.2		Dynegy Inc. Executive Change in Control Severance Pay Plan effective April 3, 2008 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on April 8, 2008, File No. 001-33443).

	*10.3		Dynegy Inc. Change in Control Severance Pay Plan effective April 3, 2008.

	10.4		Dynegy Excise Tax Reimbursement Policy, effective January 1, 2008 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on January 4, 2008, File No. 001-33443).

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

	*10.6		Form of Non-Qualified Stock Option Award Agreement Between Dynegy Inc., all of its affiliates and Jason Hochberg.

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

	*10.8		Form of Restricted Stock Award Agreement between Dynegy Inc., all of its affiliates and Jason Hochberg.

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

	*10.10		Form of Performance Award Agreement between Dynegy Inc., all of its affiliates and Jason Hochberg.

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

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

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

	*10.14		Form of Performance Award Agreement.

	*10.15		Twelfth Amendment to the Dynegy Inc. 401(K) Savings Plan.

	*10.16		Thirteenth Amendment to the Dynegy Inc. 401(K) Savings Plan.


	Exhibit Number		Description

	*10.17		Fourteenth Amendment to the Dynegy Inc. 401(K) Savings Plan.

	*10.18		Fifteenth Amendment to the Dynegy Inc. 401(K) Savings Plan

	*10.19		Sixth Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan

	*10.20		Seventh Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan

	*10.21		Ninth Amendment to the Dynegy Midwest Generation, Inc. 401(K) Savings Plan

	*10.22		Ninth Amendment to the Dynegy Midwest Generation, Inc. 401(K) Savings Plan for Employees Covered Under a Collective Bargaining Agreement

	*10.23		Ninth Amendment to the Extant, Inc. 401(K) Plan

	*10.24		Tenth Amendment to the Extant, Inc. 401(K) Plan

	*10.25		Tenth Amendment to the Dynegy Inc. Retirement Plan

	*10.26		Eleventh Amendment to the Dynegy Inc. Retirement Plan

	*10.27		Twelfth Amendment to the Dynegy Inc. Retirement Plan

	*10.28		Thirteenth Amendment to the Dynegy Inc. Retirement Plan

	*10.29		Fourteenth Amendment to the Dynegy Inc. Retirement Plan

	*10.30		Seventh Amendment to the Dynegy Midwest Generation, Inc. Retirement Income Plan for Employees Covered Under a Collective Bargaining Agreement

	*10.31		Eighth Amendment to the Dynegy Northeast Generation, Inc. Retirement Income Plan

	*10.32		Ninth Amendment to the Dynegy Northeast Generation, Inc. Retirement Income Plan

	*10.33		Amended and Restated Dynegy Inc. Severance Pay Plan

	**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.

	**31.1(a)		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.

	**31.2(a)		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.


	Exhibit Number		Description

	†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.

	†32.1(a)		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.

	†32.2(a)		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.


	*	Previously filed with the Quarterly Report on Form 10-Q for the period ended March 31, 2008 filed on May 8, 2008.

	**	Filed herewith.

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

DYNEGY INC. and DYNEGY HOLDINGS INC.

SIGNATURES

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


		DYNEGY INC.

Date: July 25, 2008	By:	/s/ HOLLI C. NICHOLS

		Holli C. Nichols
		Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)

		DYNEGY HOLDINGS INC.

Date: July 25, 2008	By:	/s/ HOLLI C. NICHOLS

		Holli C. Nichols
		Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)