DYNEGY INC. - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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EX-99.2 - EXHIBIT 99.2 - DYNEGY INC.	ex99_2.htm
8-K - DYNEGY INC 8-K 3-8-2011 - DYNEGY INC.	form8k.htm

Exhibit 99.1

FOR IMMEDIATE RELEASE

NR11-09

DYNEGY ANNOUNCES 2010 ANNUAL AND FOURTH QUARTER FINANCIAL RESULTS

·	Full-year 2010 Adjusted EBITDA of $539 million down 33 percent period-over-period

2010 net loss attributable to Dynegy Inc. of $234 million compared to 2009 net loss of $1.2 billion

·	Fourth quarter 2010 Adjusted EBITDA of $103 million essentially flat period-over-period

Fourth quarter 2010 net loss attributable to Dynegy Inc. of $164 million compared to fourth quarter 2009 net loss of $355 million

HOUSTON (March 8, 2011) – Dynegy Inc. (NYSE: DYN) today announced that Adjusted EBITDA for 2010 was $539 million, compared to $803 million for 2009. The company also reported a net loss attributable to Dynegy Inc. of $234 million or $(1.95) per diluted share for 2010, compared to a net loss of $1.2 billion or $(7.60) per diluted share for 2009. The net loss in 2010 included asset impairments, a net loss on the sale of the company’s investment in PPEA Holding Company, LLC, merger agreement transaction costs and restructuring charges, partially offset by mark-to-market gains. The net loss in 2009 included asset and goodwill impairments, a net loss on asset sales, mark-to-market losses and debt extinguishment costs.

For the fourth quarter 2010, Adjusted EBITDA was $103 million, compared to $105 million for the fourth quarter 2009. The company also reported a net loss attributable to Dynegy Inc. of $164 million or $(1.36) per diluted share for the fourth quarter 2010, compared to a net loss of $355 million or $(2.33) per diluted share for the fourth quarter 2009. The net loss in the fourth quarter 2010 included a net loss on the sale of the company’s investment in PPEA Holding Company, LLC, merger agreement transaction costs, restructuring charges and mark-to-market losses. The net loss in the fourth quarter 2009 included a net loss on asset sales, mark-to-market losses and debt extinguishment costs.

Period-over-period comparisons of full-year and fourth quarter 2010 results, including items that affected the GAAP measures of net income and net loss, are provided in more detail in the charts below and the schedules that accompany this news release.

2010 Annual and Fourth Quarter Comparative Results

Comparisons of the company’s full-year and fourth quarter results period-over-period are set forth in the table below (in millions of dollars, except per share amounts). The non-GAAP financial measures of EBITDA, Adjusted EBITDA, Adjusted Cash Flow from Operations and Adjusted Free Cash Flow are used by management to evaluate Dynegy's business on an ongoing basis. Definitions, purposes and uses of such non-GAAP measures are included in Item 2.02 to our Current Report on Form 8-K filed with the SEC on March 8, 2011, which is available on the company’s website free of charge at www.dynegy.com. Reconciliations of these measures to the most directly comparable GAAP measures are included in the accompanying schedules to this news release.

	12 Months Ended 12/31/2010			12 Months Ended 12/31/2009
Basic Loss Per Share	$	(1.95	)	$	(7.60	)
Diluted Loss Per Share	$	(1.95	)	$	(7.60	)

Net Loss Attributable to Dynegy Inc.	$	(234	)	$	(1,247	)
Add/(Deduct):
Income Tax Benefit		(197	)		(436	)
Interest Expense and Debt Extinguishment Costs		363			461
Depreciation and Amortization Expense		392			350
EBITDA		324			(872	)
Plus / (Less):
Asset Impairments		173			796
Loss on Sale of PPEA Holding		28			-
Merger Agreement Transaction Costs		26			-
Restructuring Charges		12			-
Plum Point Mark-to-market Gains		(6	)		-
Goodwill Impairment		-			433
Gain on Sale of Heard County		-			(10	)
Loss on LS Power Transactions		-			228
Loss on Sale of Sandy Creek		-			84
Sandy Creek Mark-to-market Gains		-			(21	)
Noncontrolling Interests in Change in Fair Value of Interest Rate Swaps		-			(15	)
Mark-to-market Losses (Gains), Net		(18	)		180
Adjusted EBITDA	$	539		$	803

	3 Months Ended 12/31/2010			3 Months Ended 12/31/2009
Basic Loss Per Share	$	(1.36	)	$	(2.33	)
Diluted Loss Per Share	$	(1.36	)	$	(2.33	)

Net Loss Attributable to Dynegy Inc.	$	(164	)	$	(355	)
Add/(Deduct):
Income Tax Benefit		(117	)		(198	)
Interest Expense and Debt Extinguishment Costs		91			150
Depreciation and Amortization Expense		131			77
EBITDA		(59	)		(326	)
Plus / (Less):
Loss on Sale of PPEA Holding		28			-
Merger Agreement Transaction Costs		16			-
Restructuring Charges		12			-
Asset Impairment		1			3
Loss on LS Power Transactions		-			228
Loss on Sale of Sandy Creek		-			84
Sandy Creek Mark-to-market Gains		-			(1	)
Noncontrolling Interests in Change in Fair Value of Interest Rate Swaps		-			(1	)
Mark-to-market Losses, Net		105			118
Adjusted EBITDA	$	103		$	105

Power Generation

Dynegy’s diversified power generation business includes three business segments: the Midwest, with 5,088 megawatts of generation capacity; the West, with 3,387 megawatts of generation capacity; and the Northeast, with 3,297 megawatts of generation capacity.

Adjusted EBITDA from the power generation segments was $676 million for 2010, compared to $954 million for 2009. Increased contributions from physical transactions due to improved prices and spark spreads were more than offset by decreased contributions from financial transactions due to lower value received on hedging activity. The company was also negatively impacted by less energy and capacity/tolling revenue due to assets sold in the fourth quarter 2009. The sale of assets resulted in lower operating expenses in 2010.

Management does not allocate interest expense and income taxes on a segment level and therefore uses operating income as the most directly comparable GAAP measure. Operating income from the power generation segments was $166 million for 2010, compared to an operating loss of $666 million for 2009.

The following operational and commercial factors influenced the company’s full-year 2010 Adjusted EBITDA as compared to 2009.

Midwest – Adjusted EBITDA decreased 35 percent and production volumes increased 6 percent. There were decreased contributions from financial transactions due to lower value received on hedging activity. This was partially offset by a reduced premium expense due to the purchase of fewer options. Contributions from physical transactions increased primarily due to higher power prices at coal-fired facilities and improved spark spreads at combined-cycle facilities. During the third quarter 2009, energy contributions benefited from the sale and assignment of a multi-year power sales contract. Capacity revenues decreased in 2010 primarily due to the absence of capacity revenues from assets sold in the fourth quarter 2009. The sale of assets resulted in lower operating expenses in 2010. In addition, results were negatively impacted in 2010 by margin lost due to forced outages. Production volumes in 2010 benefited from increased prices and spark spreads. During 2010, the company’s coal fleet achieved in-market availability of 91 percent.

West – Adjusted EBITDA decreased 15 percent and production volumes decreased 51 percent. There were decreased contributions from financial transactions due to lower value received on hedging activity. Physical transactions were less favorable due to compressed spark spreads. Tolling and reliability-must-run revenues decreased primarily as a result of lower contracted prices and less contracted volume at the South Bay facility. The sale of two combined-cycle facilities in the fourth quarter 2009 resulted in lower operating expenses in 2010. The decrease in production volumes primarily can be attributed to the sale of these assets.

Northeast – Adjusted EBITDA decreased 19 percent and production volumes decreased 19 percent. There were decreased contributions from financial transactions due to lower value received on hedging activity. Contributions from physical transactions benefited from improved prices and spark spreads. In addition, energy and capacity revenues were negatively impacted by the sale of an asset in the fourth quarter 2009. The asset sale resulted in lower operating expenses in 2010. The decrease in production volumes can also be attributed to the asset sale in the fourth quarter 2009, partially offset by increased volumes at combined-cycle facilities due to improved spark spreads. The company’s Danskammer coal-fired units achieved in-market availability of 95 percent.

Adjusted Cash Flow from Operations for generation was $938 million for the 12 months ended December 31, 2010, while maintenance and environmental capital expenditures were $115 million and $212 million, respectively. Adjusted Cash Flow from Operations for generation was $728 million for the 12 months ended December 31, 2009, while maintenance and environmental capital expenditures were $175 million and $304 million, respectively. The period-over-period increase in Adjusted Cash Flow from Operations for generation primarily reflects the return of cash collateral from the company’s futures clearing manager due to lower commodity prices and a reduction of margin requirements, as well as the company’s decision to post short-term investments as collateral in substitute of cash. Adjusted Free Cash Flow from the power generation business was $611 million for the 12 months ended December 31, 2010, compared to $249 million for the 12 months ended December 31, 2009.

On a GAAP basis, Cash Flow from Operations for generation was $938 million for the 12 months ended December 31, 2010 and $719 million for the 12 months ended December 31, 2009. Net cash used in investing activities was $534 million for the 12 months ended December 31, 2010. Net cash provided by investing activities was $251 million for the 12 months ended December 31, 2009. Net cash used in financing activities was $69 million for the 12 months ended December 31, 2010 and $608 million for the 12 months ended December 31, 2009.

Other

Other primarily consists of general and administrative expenses, partially offset by interest income. General and administrative expenses were $163 million in 2010, compared to $159 million in 2009. Interest income was $2 million in 2010, compared to $5 million in 2009. In Other, the company reported a $137 million Adjusted loss before interest, taxes and depreciation and amortization ($177 million operating loss) during 2010, compared to an Adjusted loss of $151 million ($168 million operating loss) during 2009. The lower Adjusted loss during 2010 was primarily related to the results of the company’s cost-savings initiative.

Consolidated Interest Expense, Debt Extinguishment Costs and Taxes

The company’s interest expense totaled $363 million for 2010, compared to interest expense and debt extinguishment costs of $461 million for 2009. The lower expense in 2010 was primarily driven by lower outstanding debt balances associated with the 2009 paydown of 2011 and 2012 bond maturities, as well as a related $46 million debt extinguishment charge in 2009, and the deconsolidation of PPEA Holding Company, LLC as provided by new accounting standards that went into effect on January 1, 2010. The income tax benefit from continuing operations was $197 million for 2010, compared to an income tax benefit from continuing operations of $315 million for 2009. The lower income tax benefit in 2010 primarily resulted from the reduced net loss period-over-period.

Liquidity

As of December 31, 2010, Dynegy’s liquidity was $1.8 billion. This consisted of $397 million in cash on hand and $1.4 billion in unused availability under the company’s credit facility.

As of March 3, 2011, liquidity was $1.8 billion, which consisted of $448 million in cash on hand and $1.4 billion in unused availability under the company’s credit facility. The increase in cash on hand is primarily related to the expiration of an agreement and the subsequent release of restricted cash.

Consolidated Cash Flow

Adjusted Cash Flow from Operations totaled an inflow of $455 million for the 12 months ended December 31, 2010. There was a cash inflow of $938 million from the power generation business, offset by outflows of $483 million in Other resulting primarily from interest payments and general and administrative expenses, net of interest income.

For the 12 months ended December 31, 2010, Dynegy’s Adjusted Free Cash Flow was an inflow of $122 million. This consisted of Adjusted Cash Flow from Operations of $455 million, offset by maintenance and environmental capital expenditures of $121 million and $212 million, respectively, the latter of which reflects the company’s continuing investment in environmental upgrades.

For the 12 months ended December 31, 2009, Dynegy’s Adjusted Free Cash Flow was an outflow of $315 million. This consisted of Adjusted Cash Flow from Operations of $170 million, offset by maintenance and environmental capital expenditures of $181 million and $304 million, respectively.

On a GAAP basis, Cash Flow from Operations for the 12 months ended December 31, 2010, and December 31, 2009, was $423 million and $135 million, respectively. Net cash used in investing activities was $534 million for the 12 months ended December 31, 2010. Net cash provided by investing activities was $251 million for the 12 months ended December 31, 2009. Net cash used in financing activities was $69 million for the 12 months ended December 31, 2010, and $608 million for the 12 months ended December 31, 2009.

Guidance Estimates

In light of recent management and board changes that may affect the company’s strategic plans, Dynegy currently does not intend to provide guidance estimates for 2011. Further, the company has not updated nor does it intend to update, or otherwise revise, the financial forecasts (the “Forecasts”) provided in Dynegy’s Solicitation/Recommendation Statement on Schedule 14D-9 (as amended or supplemented from time to time) filed with the SEC by Dynegy on December 30, 2010, and its Preliminary Proxy Statement on Schedule 14A filed with the SEC by Dynegy on January 10, 2011. Consequently, readers of these Forecasts are cautioned not to rely on such Forecasts. The company will reconsider at a later time whether it will provide guidance estimates for 2011 and future years.

About Dynegy Inc.

Through its subsidiaries, Dynegy Inc. produces and sells electric energy, capacity and ancillary services in key U.S. markets. The power generation portfolio consists of approximately 11,800 megawatts of baseload, intermediate and peaking power plants fueled by a mix of natural gas, coal and fuel oil.

Certain statements included in this news release are intended as “forward-looking statements.” These statements include assumptions, expectations, predictions, intentions or beliefs about future events, particularly the statements concerning financial guidance estimates and Dynegy’s plans to update them in the future. While Dynegy does not expect to update these estimates on a quarterly basis or annual basis, it is possible given recent events that Dynegy’s approach may change again in the future regarding guidance.

More information about the risks and uncertainties relating to these forward-looking statements is found in Dynegy’s SEC filings, including its Annual Report on Form 10-K for the year ended December 31, 2010, and its Quarterly Reports on Form 10-Q for the quarters ended March 31, 2010, June 30, 2010, and September 30, 2010, and its Current Reports, all of which are available free of charge on Dynegy’s website at www.dynegy.com. Dynegy expressly disclaims any obligation to update any forward-looking statements contained in this news release to reflect events or circumstances that may arise after the date of this release, except as otherwise required by applicable law.

DYNEGY INC.

REPORTED UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(IN MILLIONS, EXCEPT PER SHARE DATA)

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2010			2009			2010			2009

Revenues	$	451		$	441		$	2,323		$	2,468
Cost of sales		(308	)		(267	)		(1,181	)		(1,194	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(109	)		(146	)		(450	)		(519	)
Depreciation and amortization expense		(131	)		(77	)		(392	)		(335	)
Goodwill impairments		-			-			-			(433	)
Impairments and other charges, exclusive of goodwill impairments shown separately above		(13	)		(3	)		(148	)		(538	)
Loss on sale of assets, net		-			(124	)		-			(124	)
General and administrative expenses		(53	)		(34	)		(163	)		(159	)
Operating loss		(163	)		(210	)		(11	)		(834	)

Losses from unconsolidated investments		(28	)		(84	)		(62	)		(71	)
Interest expense		(91	)		(104	)		(363	)		(415	)
Debt extinguishment costs		-			(46	)		-			(46	)
Other income and expense, net		1			1			4			11
Loss from continuing operations before income taxes		(281	)		(443	)		(432	)		(1,355	)

Income tax benefit		117			168			197			315
Loss from continuing operations		(164	)		(275	)		(235	)		(1,040	)

Income (loss) from discontinued operations, net of tax		-			(81	)		1			(222	)
Net loss		(164	)		(356	)		(234	)		(1,262	)

Less: Net loss attributable to the noncontrolling interests		-			(1	)		-			(15	)
Net loss attributable to Dynegy Inc.	$	(164	)	$	(355	)	$	(234	)	$	(1,247	)

Basic loss per share attributable to Dynegy Inc.:
Loss from continuing operations (1)	$	(1.36	)	$	(1.80	)	$	(1.96	)	$	(6.25	)
Income (loss) from discontinued operations		-			(0.53	)		0.01			(1.35	)
Basic loss per share attributable to Dynegy Inc.	$	(1.36	)	$	(2.33	)	$	(1.95	)	$	(7.60	)

Diluted loss per share attributable to Dynegy Inc.:
Loss from continuing operations (1)	$	(1.36	)	$	(1.80	)	$	(1.96	)	$	(6.25	)
Income (loss) from discontinued operations		-			(0.53	)		0.01			(1.35	)
Diluted loss per share attributable to Dynegy Inc.	$	(1.36	)	$	(2.33	)	$	(1.95	)	$	(7.60	)

Basic shares outstanding			121				152				120				164
Diluted shares outstanding			122				153				121				165

(1)	A reconciliation of basic loss per share from continuing operations attributable to Dynegy Inc. to diluted loss per share from continuing operations attributable to Dynegy Inc. is presented below:

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2010			2009			2010			2009

Loss from continuing operations	$	(164	)	$	(275	)	$	(235	)	$	(1,040	)
Less: Net loss attributable to the noncontrolling interests		-			(1	)		-			(15	)
Loss from continuing operations attributable to Dynegy Inc. for basic and diluted loss per share	$	(164	)	$	(274	)	$	(235	)	$	(1,025	)

Basic weighted-average shares (2)		121			152			120			164

Effect of dilutive securities:
Stock options and restricted stock		1			1			1			1
Diluted weighted-average shares (2)		122			153			121			165


Loss per share from continuing operations attributable to Dynegy Inc.:
Basic	$	(1.36	)	$	(1.80	)	$	(1.96	)	$	(6.25	)

Diluted (3)	$	(1.36	)	$	(1.80	)	$	(1.96	)	$	(6.25	)

(2)	Basic and diluted weighted average shares have been adjusted to reflect the May 25, 2010, one-for-five reverse stock split for all periods presented.

(3)

Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per-share amounts. Accordingly, Dynegy Inc. has utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three and twelve months ended December 31, 2010 and 2009.

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DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

THREE MONTHS ENDED DECEMBER 31, 2010

(UNAUDITED) (IN MILLIONS)

	Power Generation
	GEN - MW			GEN - WE			GEN - NE			OTHER			Total
Net loss attributable to Dynegy Inc.													$	(164	)
Plus / (Less):
Income tax benefit (1)														(117	)
Interest expense														91
Depreciation and amortization expense														131
EBITDA (2)	$	(37	)	$	37		$	(3	)	$	(56	)	$	(59	)
Plus / (Less):
Loss on sale of PPEA Holding (3)		28			-			-			-			28
Merger Agreement transaction costs (4)		-			-			-			16			16
Restructuring charges (5)		4			1			1			6			12
Asset impairment (6)		-			-			1			-			1
Mark-to-market losses, net		98			(12	)		19			-			105
Adjusted EBITDA (2)	$	93		$	26		$	18		$	(34	)	$	103

(1)	Includes $12 million net tax benefit related to a change in California state tax law.

(2)

EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on March 8, 2011, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented below. Management does not allocate interest expenses and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure.

	Power Generation
	GEN - MW			GEN - WE		GEN - NE			OTHER			Total

Operating income (loss)	$	(122	)	$	21	$	(4	)	$	(58	)	$	(163	)
Losses from unconsolidated investments		(28	)		-		-			-			(28	)
Other items, net		1			-		-			-			1
Depreciation and amortization expense		112			16		1			2			131
EBITDA	$	(37	)	$	37	$	(3	)	$	(56	)	$	(59	)

(3)

We recognized a pre-tax charge of approximately $28 million ($17 million after-tax) related to the loss on sale of our investment in PPEA Holding Company, LLC. This charge is included in Losses from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations.

(4)	We incurred $16 million ($10 million after-tax) of expenses in connection with our prior proposed merger with an affiliate of The Blackstone Group. These expenses are included in General and administrative expenses on our Reported Unaudited Condensed Consolidated Statements of Operations.

(5)	We recognized pre-tax charges of approximately $12 million ($7 million after-tax) related to restructuring charges in connection with a reduction in workforce. These charges are included in Impairment and other charges in our Reported Unaudited Condensed Consolidated Statements of Operations.

(6)

We recognized a pre-tax charge of approximately $1 million ($1 million after-tax) related to the asset impairment of our Roseton and Danskammer power generation facilities. This charge is included in Impairment and other charges in our Reported Unaudited Condensed Consolidated Statements of Operations.

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DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

THREE MONTHS ENDED DECEMBER 31, 2009

(UNAUDITED) (IN MILLIONS)

	Power Generation
	GEN - MW			GEN - WE			GEN - NE			OTHER			Total
Net loss attributable to Dynegy Inc.													$	(355	)
Plus / (Less):
Income tax benefit														(198	)
Interest expense and debt extinguishment costs (1)														150
Depreciation and amortization expense														77
EBITDA (2)	$	(120	)	$	(163	)	$	(11	)	$	(32	)	$	(326	)
Plus / (Less):
Asset impairments (3)		-			-			3			-			3
Loss on LS Power Transactions (4)		118			82			28			-			228
Loss on sale of Sandy Creek (5)		-			84			-			-			84
Sandy Creek mark-to-market gains (6)		-			(1	)		-			-			(1	)
Noncontrolling interests in change in fair value of interest rate swaps (7)		(1	)		-			-			-			(1	)
Mark-to-market losses, net		108			8			2			-			118
Adjusted EBITDA (2)	$	105		$	10		$	22		$	(32	)	$	105

(1)

Includes pre-tax charges of $46 million ($29 million after-tax) related to debt extinguishment costs for the 2011 and 2012 senior unsecured debt repayment during the fourth quarter 2009. These charges are included in Debt extinguishment costs on our Reported Unaudited Condensed Consolidated Statements of Operations. Also includes approximately $1 million of income related to the change in fair value of the Plum Point IR swaps. This income is included in Interest expense on our Reported Unaudited Condensed Consolidated Statements of Operations.

(2)

EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on March 8, 2011, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating loss is presented below. Management does not allocate interest expenses and income taxes on a segment level and therefore uses Operating loss as the most directly comparable GAAP measure.

	Power Generation
	GEN - MW			GEN - WE			GEN - NE			OTHER			Total

Operating loss	$	(147	)	$	(9	)	$	(20	)	$	(34	)	$	(210	)
Losses from unconsolidated investments		-			(84	)		-			-			(84	)
Other items, net		-			-			1			-			1
Net loss attributable to the noncontrolling interests		1			-			-			-			1
Depreciation and amortization expense		50			17			8			2			77
EBITDA from continuing operations		(96	)		(76	)		(11	)		(32	)		(215	)
EBITDA from discontinued operations (8)		(24	)		(87	)		-			-			(111	)
EBITDA	$	(120	)	$	(163	)	$	(11	)	$	(32	)	$	(326	)

(3)

We recognized a pre-tax charge of approximately $3 million ($2 million after-tax) related to the impairment of our Roseton and Danskammer power generation facilities as a result of continued expected cash flow losses related to these assets. This charge is included in Impairments and other charges on our Reported Unaudited Condensed Consolidated Statements of Operations and will be further described in our Annual Report on Form 10-K for the year ended December 31, 2010.

(4)	During the fourth quarter 2009, we recognized pre-tax charges of approximately $228 million ($139 million after-tax) related to the loss on sale of assets to LS Power. Below is the breakdown of these assets by region:

	Pre-tax		After-tax
GEN-MW
Renaissance (a)	$	44	$	27
Riverside/Foothills (a)		40		24
Rocky Road (a)		6		4
Tilton (a)		6		4
Bluegrass (b)		22		13
Total	$	118	$	72
GEN-WE
Arlington Valley (b)	$	42	$	26
Griffith (b)		40		24
Total	$	82	$	50
GEN-NE
Bridgeport (a)	$	28	$	17
Total	$	28	$	17

(a) These charges are included in Gain (loss) on sale of assets, net, on our Reported Unaudited Condensed Consolidated Statements of Operations and are described in our Annual Report on Form 10-K for the year ended December 31, 2010.

(b) These charges are included in Income (loss) from discontinued operations, net on our Reported Unaudited Condensed Consolidated Statements of Operations and are described in our Annual Report on Form 10-K for the year ended December 31, 2010.

(5)

We recognized pre-tax charges of approximately $84 million ($51 million after-tax) related to the loss on sale of Dynegy's investment in Sandy Creek to LS Power. These charges are included in Losses from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations.

(6)

We recognized pre-tax income of approximately $1 million ($1 million after-tax) related to the change in fair value of the Sandy Creek Project interest rate swaps. This income is included in Losses from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations.

(7)	We recorded approximately $1 million of noncontrolling interest losses primarily due to the change in fair value of the Plum Point IR swaps. These losses are included in Net loss attributable to the noncontrolling interests on our Reported Unaudited Condensed Consolidated Statements of Operations.

(8)	A reconciliation of EBITDA from discontinued operations to Loss from discontinued operations, net of tax, is presented below.

EBITDA from discontinued operations	$	(111	)
Income tax benefit from discontinued operations		30
Loss from discontinued operations, net of tax	$	(81	)

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DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

TWELVE MONTHS ENDED DECEMBER 31, 2010

(UNAUDITED) (IN MILLIONS)

	Power Generation
	GEN - MW			GEN - WE			GEN - NE			OTHER			Total
Net loss attributable to Dynegy Inc.													$	(234	)
Plus / (Less):
Income tax benefit (1)														(197	)
Interest expense														363
Depreciation and amortization expense														392
EBITDA (2)	$	343		$	185		$	(35	)	$	(169	)	$	324
Plus / (Less):
Impairments (3)		37			-			136			-			173
Loss on sale of PPEA Holding (4)		28			-			-			-			28
Merger Agreement transaction costs (5)		-			-			-			26			26
Restructuring charges (6)		4			1			1			6			12
Plum Point mark-to-market gains (7)		(6	)		-			-			-			(6	)
Mark-to-market gains, net		12			(33	)		3			-			(18	)
Adjusted EBITDA (2)	$	418		$	153		$	105		$	(137	)	$	539

(1)	Includes a benefit of $18 million related to the release of a reserve for uncertain tax positions as a result of completion of an audit, adjustments to tax positions related to prior years and various state settlements and $12 million net tax benefit related to a change in California state tax law.

(2)

	Power Generation
	GEN - MW			GEN - WE		GEN - NE			OTHER			Total

Operating income (loss)	$	108		$	118	$	(60	)	$	(177	)	$	(11	)
Losses from unconsolidated investments		(62	)		-		-			-			(62	)
Other items, net		1			-		1			2			4
Depreciation and amortization expense		296			66		24			6			392
EBITDA from continuing operations		343			184		(35	)		(169	)		323
EBITDA from discontinued operations (8)		-			1		-			-			1
EBITDA	$	343		$	185	$	(35	)	$	(169	)	$	324

(3)

We recognized pre-tax charges of approximately $173 million ($105 million after-tax) related to asset impairments and other charges. These charges consist of pre-tax impairment charges of approximately $134 million ($81 million after-tax) to reduce the carrying value of our Casco Bay facility to its fair value in connection with the prior proposed merger agreement with an affiliate of the Blackstone Group and $2 million ($1 million after-tax) related to the asset impairment of our Roseton and Danskammer power generation facilities. These charges are included in Impairment and other charges in our Reported Unaudited Condensed Consolidated Statements of Operations and will be further described in our Annual Report on Form 10-K for the year ended December 31, 2010. We also recognized a pre-tax charge of approximately $37 million ($23 million after-tax) related to the impairment of our investment in PPEA Holding Company, LLC due to the uncertainty and risk surrounding PPEA's financial structure. This charge is included in Losses from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations and will be further described in our Annual Report on Form 10-K for the year ended December 31, 2010.

(4)

(5)	We incurred $26 million ($16 million after-tax) of expenses in connection with our prior proposed merger with an affiliate of The Blackstone Group. These expenses are included in General and administrative expenses on our Reported Unaudited Condensed Consolidated Statements of Operations.

(6)	We recognized pre-tax charges of approximately $12 million ($7 million after-tax) related to restructuring charges in connection with a reduction in workforce. These charges are included in Impairment and other charges in our Reported Unaudited Condensed Consolidated Statements of Operations.

(7)	We recognized pre-tax income of approximately $6 million ($3 million after-tax) related to the change in fair value of the PPEA Holding interest rate swaps. This income is included in Losses from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations.

(8)	A reconciliation of EBITDA from discontinued operations to Income from discontinued operations, net of tax, is presented below.

EBITDA from discontinued operations	$	1
Depreciation and amortization expense from discontinued operations		-
Income tax expense from discontinued operations		-
Income from discontinued operations, net of tax	$	1

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DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

TWELVE MONTHS ENDED DECEMBER 31, 2009

(UNAUDITED) (IN MILLIONS)

	Power Generation
	GEN - MW			GEN - WE			GEN - NE			OTHER			Total
Net loss attributable to Dynegy Inc.													$	(1,247	)
Plus / (Less):
Income tax benefit (1)														(436	)
Interest expense and debt extinguishment costs (2)														461
Depreciation and amortization expense														350
EBITDA (3)	$	182		$	(507	)	$	(396	)	$	(151	)	$	(872	)
Plus / (Less):
Asset impairments (4)		170			235			391			-			796
Goodwill impairment (5)		76			260			97			-			433
Gain on sale of Heard County (6)		-			(10	)		-			-			(10	)
Loss on LS Power Transactions (7)		118			82			28			-			228
Loss on sale of Sandy Creek (8)		-			84			-			-			84
Sandy Creek mark-to-market gains (9)		-			(21	)		-			-			(21	)
Noncontrolling interests in change in fair value of interest rate swaps (10)		(15	)		-			-			-			(15	)
Mark-to-market losses, net		112			58			10			-			180
Adjusted EBITDA (3)	$	643		$	181		$	130		$	(151	)	$	803

(1)	Includes charges of $21 million related to a change in California state law and charges of $12 million due to revised assumptions around our ability to use certain state deferred tax assets.

(2)

Includes pre-tax charges of $46 million ($29 million after-tax) related to debt extinguishment costs for the 2011 and 2012 senior unsecured debt repayment during the fourth quarter 2009. Also includes approximately $16 million of charges related to the change in fair value of the Plum Point IR swaps. These charges are included in Debt extinguishment costs and Interest expense, respectively, on our Reported Unaudited Condensed Consolidated Statements of Operations.

(3)

EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on March 8, 2011, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating loss is presented below. Management does not allocate interest expenses and income taxes on a segment level and therefore uses Operating loss as the most directly comparable GAAP measure.

	Power Generation
	GEN - MW			GEN - WE			GEN - NE			OTHER			Total

Operating loss	$	(4	)	$	(218	)	$	(444	)	$	(168	)	$	(834	)
Earnings (losses) from unconsolidated investments		-			(72	)		-			1			(71	)
Other items, net		2			3			1			5			11
Net loss attributable to the noncontrolling interests		15			-			-			-			15
Depreciation and amortization expense		215			62			47			11			335
EBITDA from continuing operations		228			(225	)		(396	)		(151	)		(544	)
EBITDA from discontinued operations (11)		(46	)		(282	)		-			-			(328	)
EBITDA	$	182		$	(507	)	$	(396	)	$	(151	)	$	(872	)

(4)

During the second quarter 2009, we recognized pre-tax charges of approximately $202 million ($123 million after-tax) related to asset impairments. These impairments were recorded due to management's conclusion that it was more likely than not that these assets would be sold prior to the end of their previously estimated useful lives. On August 9, 2009, we entered into a purchase and sale agreement with LS Power. At that time, the assets included in the agreement met the criteria of held for sale. As a result, we recognized pre-tax charges of approximately $382 million ($234 million after-tax) related to asset impairments. Below is the breakdown of these asset impairment charges by region:


	Pre-tax		After-tax
GEN-MW
Renaissance (a)	$	65	$	40
Riverside/Foothills (a)		18		11
Rocky Road (a)		22		14
Tilton (a)		42		26
Bluegrass (b)		23		14
Total	$	170	$	105
GEN-WE
Arlington Valley (b)	$	112	$	68
Griffith (b)		123		75
Total	$	235	$	143
GEN-NE
Bridgeport (a)	$	179	$	109
Total	$	179	$	109

(a)These charges are included in Impairments and other charges on our Reported Unaudited Condensed Consolidated Statements of Operations and are described in our Annual Report on Form 10-K for the year ended December 31, 2010.

In addition, GEN-NE also included a $212 million ($132 million after-tax) impairment charge related to our Roseton and Danskammer power generation facilities as a result of continued weakening in forward capacity and forward power prices in certain of the markets in which we operate. This charge is included in Impairments and other charges on our Reported Unaudited Condensed Consolidated Statements of Operations and is described in our Annual Report on Form 10-K for the year ended December 31, 2010.

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(5)

We recognized pre-tax charges of approximately $433 million ($433 million after-tax) related to the impairment of our goodwill . These charges are included in Goodwill impairments on our Reported Unaudited Condensed Consolidated Statement of Operations and are described in our Annual Report on Form 10-K for the year ended December 31, 2010.

(6)	We recognized a pre-tax gain of approximately $10 million ($6 million after-tax) on the sale of our Heard County power generation facility. This gain is included in Income (loss) from discontinued operations, net of tax on our Reported Unaudited Condensed Consolidated Statements of Operations.

(7)	During the fourth quarter 2009, we recognized pre-tax charges of approximately $228 million ($139 million after-tax) related to the loss on sale of assets to LS Power. Below is the breakdown of these assets by region:

	Pre-tax		After-tax
GEN-MW
Renaissance (a)	$	44	$	27
Riverside/Foothills (a)		40		24
Rocky Road (a)		6		4
Tilton (a)		6		4
Bluegrass (b)		22		13
Total	$	118	$	72
GEN-WE
Arlington Valley (b)	$	42	$	26
Griffith (b)		40		24
Total	$	82	$	50
GEN-NE
Bridgeport (a)	$	28	$	17
Total	$	28	$	17

(a)These charges are included in Gain (loss) on sale of assets, net, on our Reported Unaudited Condensed Consolidated Statements of Operations and are described in our Annual Report on Form 10-K for the year ended December 31, 2010.

(b)These charges are included in Loss from discontinued operations, net of tax, on our Reported Unaudited Condensed Consolidated Statements of Operations and will be further described in our Annual Report on Form 10-K for the year ended December 31, 2010.

(8)

(9)

We recognized pre-tax income of approximately $21 million ($13 million after-tax) related to the change in fair value of the Sandy Creek Project interest rate swaps. This income is included in Losses from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations.

(10)	We recorded approximately $15 million of noncontrolling interest losses primarily due to the change in fair value of the Plum Point IR swaps. These losses are included in Net loss attributable to the noncontrolling interests on our Reported Unaudited Condensed Consolidated Statements of Operations.

(11)	A reconciliation of EBITDA from discontinued operations to Loss from discontinued operations, net of tax, is presented below.


EBITDA from discontinued operations	$	(328	)
Depreciation and amortization expense from discontinued operations		(15	)
Income tax benefit from discontinued operations		121
Loss from discontinued operations, net of tax	$	(222	)

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DYNEGY INC.

SUMMARY CASH FLOW INFORMATION (1)

(UNAUDITED) (IN MILLIONS)

	Twelve Months Ended December 31, 2010									Twelve Months Ended December 31, 2009
	GEN			OTHER			Total			GEN			OTHER			Total
Adjusted EBITDA (2)	$	676		$	(137	)	$	539		$	954		$	(151	)	$	803
Interest payments		-			(358	)		(358	)		-			(424	)		(424	)
Cash taxes		-			(7	)		(7	)		-			(4	)		(4	)
Working capital / non-cash adjustments / other changes		262			19			281			(226	)		21			(205	)
Adjusted Cash Flow from Operations (3)		938			(483	)		455			728			(558	)		170
Maintenance capital expenditures		(115	)		(6	)		(121	)		(175	)		(6	)		(181	)
Environmental capital expenditures		(212	)		-			(212	)		(304	)		-			(304	)
Adjusted Free Cash Flow (3)	$	611		$	(489	)	$	122		$	249		$	(564	)	$	(315	)

Net cash provided (used in) Investing Activities							$	(534	)							$	251

Net cash used in Financing Activities							$	(69	)							$	(608	)

(1)

This presentation is intended to demonstrate the relationship between the performance measure of Adjusted EBITDA and the liquidity measure of Adjusted Free Cash Flow. We believe it is useful to our analysts and investors to understand this relationship because it demonstrates how the cash generated by our operations is used to satisfy various liquidity requirements. This presentation is not intended to be a reconciliation of non-GAAP measures pursuant to Regulation G. Such reconciliations of these non-GAAP financial measures to GAAP measures can be found below.

(2)

Adjusted EBITDA is a non-GAAP financial measure. Please refer to Item 2.02 of our Form 8-K filed on March 8, 2011 for definitions, utility and uses of such non-GAAP financial measures. Please see Reported Segmented Results of Operations for the twelve months ended December 31, 2010 and 2009 for a reconciliation of Adjusted EBITDA to Net loss attributable to Dynegy Inc.

(3)

Adjusted Cash Flow from Operations and Adjusted Free Cash Flow are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on March 8, 2011 for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of Adjusted Cash Flow from Operations and Adjusted Free Cash Flow to Cash Flow from Operations is presented below.

	Twelve Months Ended December 31, 2010									Twelve Months Ended December 31, 2009
	GEN			OTHER			Total			GEN			OTHER			Total
Cash Flow from Operations	$	938		$	(515	)	$	423		$	719		$	(584	)	$	135
Legal and regulatory payments		-			6			6			9			7			16
Payment for JV Dissolution		-			-			-			-			19			19
Merger Agreement transaction costs		-			26			26			-			-			-
Adjusted Cash Flow from Operations		938			(483	)		455			728			(558	)		170
Maintenance capital expenditures		(115	)		(6	)		(121	)		(175	)		(6	)		(181	)
Environmental capital expenditures		(212	)		-			(212	)		(304	)		-			(304	)
Adjusted Free Cash Flow	$	611		$	(489	)	$	122		$	249		$	(564	)	$	(315	)

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DYNEGY INC.

OPERATING DATA

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2010			2009			2010			2009
GEN - MW
Million Megawatt Hours Generated (1)		6.9			5.9			26.4			25.0
In Market Availability for Coal Fired Facilities (2)		95	%		94	%		91	%		90	%
Average Capacity Factor for Combined Cycle Facilities (3)		25	%		18	%		26	%		29	%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
Cinergy (CIN Hub)	$	38		$	35		$	42		$	35
Commonwealth Edison (NI Hub)	$	34		$	35		$	41		$	35
PJM West	$	49		$	43		$	54		$	45
Average On-Peak Market Spark Spreads ($/MWh) (5):
PJM West	$	14		$	9		$	19		$	12

GEN - WE
Million Megawatt Hours Generated (6)		1.0			1.3			4.0			8.1
Average Capacity Factor for Combined Cycle Facilities (3)		37	%		27	%		36	%		32	%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
North Path 15 (NP 15)	$	38		$	48		$	40		$	39
Average On-Peak Market Spark Spreads ($/MWh) (5):
North Path 15 (NP 15)	$	7		$	11		$	6		$	8

GEN - NE
Million Megawatt Hours Generated		2.3			2.4			8.3			10.2
In Market Availability for Coal Fired Facilities (2)		96	%		96	%		95	%		95	%
Average Capacity Factor for Combined Cycle Facilities (3)		55	%		49	%		47	%		44	%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
New York - Zone G	$	56		$	50		$	59		$	50
New York - Zone A	$	41		$	36		$	44		$	36
Mass Hub	$	54		$	49		$	56		$	46
Average On-Peak Market Spark Spreads ($/MWh) (5):
New York - Zone A	$	9		$	1		$	9		$	4
Mass Hub	$	15		$	14		$	18		$	12
Fuel Oil	$	(81	)	$	(79	)	$	(72	)	$	(53	)

Average Natural Gas Price - Henry Hub ($/MMBtu) (7)	$	3.78		$	4.25		$	4.38		$	3.92

(1)	Includes our ownership percentage in the MWh generated by our GEN-MW investment in the Plum Point power generation facility for the three and twelve months ended December 31, 2010, respectively.

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

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

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

(5)

Reflects the simple average of the spark spread available to either a 7.0 MMBTU/MWh heat rate natural gas-fired generator or an 11.0 MMBTU/MWh heat fuel oil-fired 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 us.

(6)	Includes our ownership percentage in the MWh generated by our GEN-WE investment in the Black Mountain power generation facility for the three and twelve months ended December 31, 2010 and 2009, respectively.

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

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