Dynegy Announces Third Quarter 2010 Financial Results

  • Third quarter 2010 Adjusted EBITDA down 58 percent period-over-period
    • Financial transactions less favorable due to the reduced value of hedging activities; Increased contributions from physical transactions in the Midwest and Northeast related to improved prices and spark spreads
    • Overall decrease in production volumes primarily attributable to assets sold in the fourth quarter 2009 and compressed spark spreads in the West; partially offset by increased volumes in the Midwest and Northeast due to improved prices and spark spreads
  • Third quarter 2010 net loss attributable to Dynegy Inc. of $24 million, compared to a net loss attributable to Dynegy Inc. of $212 million in the third quarter 2009
  • Company narrows 2010 earnings guidance estimates

HOUSTON--()--Dynegy Inc. (NYSE: DYN) today announced that Adjusted EBITDA for the third quarter 2010 was $159 million, compared to $377 million for the third quarter 2009. The company also reported a net loss attributable to Dynegy Inc. of $24 million or $(0.20) per diluted share for the third quarter 2010, compared to a net loss of $212 million or $(1.26) per diluted share for the third quarter 2009. The net loss in the third quarter 2010 included an asset impairment charge of $134 million ($81 million after tax) and $132 million of mark-to-market gains ($79 million after tax) associated with forward power sales. The net loss in the third quarter 2009 was primarily driven by asset impairment charges of $383 million ($235 million after tax) and mark-to-market losses of $128 million ($78 million after tax) associated with forward power sales.

A comparison of the company’s third quarter results period-over-period, including items that affected the GAAP measures of net income and net loss, is provided in more detail in the table below and the schedules that accompany this news release.

Third Quarter Comparative Results

A comparison of the company’s third quarter results period-over-period is 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 November 8, 2010, 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.

     

3 Months
Ended
9/30/2010

3 Months
Ended
9/30/2009

Basic Earnings (Loss) Per Share Attributable to Dynegy Inc. $

(0.20

) $ (1.26 )
Diluted Earnings (Loss) Per Share Attributable to Dynegy Inc. $

(0.20

) $ (1.26 )
 
Net Loss Attributable to Dynegy Inc. $

(24

) $ (212 )
Add Back:
  Income Tax Benefit

(17

) (118 )
Interest Expense 92 115
Depreciation and Amortization Expense   96       87  
EBITDA

147

(128 )
Plus / (Less):
Impairment Charges 134 383
Merger Agreement Transaction Costs 10 -
Sandy Creek Mark-to-Market Losses - 5
Non-Controlling Interests in Changes in Fair Value of Interest Rate Swaps - (11 )
Mark-to-Market Losses (Gains), Net   (132 )     128  
Adjusted EBITDA $

159

    $ 377  
 

Power Generation

Dynegy’s diversified power generation business includes three business segments: the Midwest, with approximately 5,200 megawatts of generation capacity; the West, with approximately 3,700 megawatts of generation capacity; and the Northeast, with approximately 3,300 megawatts of generation capacity.

Adjusted EBITDA from the power generation segments was $203 million for the third quarter 2010, compared to $420 million for the third quarter 2009.

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 $106 million for the third quarter 2010, which reflected an asset impairment charge of $134 million ($81 million after tax) and mark-to-market gains of $132 million ($79 million after tax). This compares to operating income of $40 million for the third quarter 2009. Operating income during the third quarter 2009 reflected $383 million in impairment charges ($235 million after tax), as well as mark-to-market losses of $128 million ($78 million after tax).

The following operational and commercial factors influenced the company’s third quarter 2010 Adjusted EBITDA as compared to the third quarter 2009. Included in the business segment discussion are references to energy contributions. Energy contributions include both physical and financial transactions. Physical transactions consist of generation sales, while financial transactions refer to hedging activities that include financial swaps and options activity.

  • Midwest – Adjusted EBITDA decreased 54 percent and production volumes increased by 11 percent. Financial transactions were less favorable due to the reduced value of hedging activity, partially offset by a reduced premium expense due to the purchase of fewer options. Contributions from physical transactions increased primarily due to improved prices and spark spreads. In addition, capacity revenues were lower due to decreased pricing in MISO, as well as the absence of capacity revenues from assets sold in the fourth quarter 2009. Also during the third quarter 2009, energy contributions benefited from the sale and assignment of a multi-year power sales contract. During the third quarter 2010, the company’s coal fleet achieved in-market availability of 91 percent.
  • West – Adjusted EBITDA decreased 50 percent and production volumes declined 72 percent. Financial transactions were less favorable as a result of reduced premium revenue due to the sale of fewer options. Tolling revenues were lower due to the absence of revenues from assets sold in the fourth quarter 2009. In addition, there was less revenue from the South Bay facility due to the timing of reliability-must-run payments in 2010 versus tolling payments in 2009. The decrease in production volumes can be attributed to the sale of two assets in the fourth quarter 2009 and compressed spark spreads.
  • Northeast – Adjusted EBITDA decreased 44 percent and production volumes increased 14 percent. Financial transactions were less favorable due to the reduced value of hedging activity and reduced premium revenue due to the sale of fewer options. Contributions from physical transactions benefited from improved prices and spark spreads. In addition, energy and capacity revenues were negatively impacted by the sale of assets in the fourth quarter 2009. The company’s Danskammer coal units achieved in-market availability of 96 percent. The increase in production volumes can be attributed to improved prices and spark spreads related to warmer weather, additional ancillary service sales at Independence and improved gas supply that benefited the Roseton facility.

Adjusted Cash Flow from Operations for generation was $992 million for the nine months ended September 30, 2010, while maintenance and environmental capital expenditures were $100 million and $164 million, respectively. Adjusted Cash Flow from Operations for generation was $690 million for the nine months ended September 30, 2009, while maintenance and environmental capital expenditures were $103 million and $241 million, respectively. Adjusted Free Cash Flow from the power generation business was $728 million for the nine months ended September 30, 2010, compared to $346 million for the nine months ended September 30, 2009.

On a GAAP basis, Cash Flow from Operations for generation was $992 million for the nine months ended September 30, 2010, and $683 million for the nine months ended September 30, 2009. Net cash used in investing activities was $614 million for the nine months ended September 30, 2010, compared to net cash used in investing activities of $341 million for the nine months ended September 30, 2009. Net cash used in financing activities was $36 million for the nine months ended September 30, 2010. Net cash provided by financing activities was $47 million for the nine months ended September 30, 2009.

Other

Other primarily consists of general and administrative expenses, partially offset by interest income. General and administrative expenses were $51 million in the third quarter 2010, compared to $42 million in the third quarter 2009. The period-over-period increase in general and administrative expenses primarily resulted from $10 million in merger agreement transaction costs. Interest income was less than $1 million for both the third quarter 2010 and the third quarter 2009. In Other, the company reported a $44 million Adjusted loss before interest, taxes and depreciation and amortization ($56 million operating loss) during the third quarter 2010, compared to an Adjusted loss before interest, taxes and depreciation and amortization of $43 million ($47 million operating loss) during the third quarter 2009.

Consolidated Interest Expense and Taxes

The company’s interest expense totaled $92 million for the third quarter 2010, compared to an interest expense of $115 million for the third quarter 2009. The lower interest expense in the third quarter 2010 was primarily driven by lower outstanding debt balances associated with the paydown of 2011 and 2012 bond maturities and the deconsolidation of PPEA Holding Company, LLC as provided by new accounting standards that went into effect on January 1, 2010. This was partially offset by the issuance of $235 million of senior unsecured notes in connection with a strategic transaction in the fourth quarter 2009, as well as higher rates on the company’s variable-rate debt. The income tax benefit from continuing operations was $17 million for the third quarter 2010, compared to an income tax benefit from continuing operations of $34 million for the third quarter 2009. The lower income tax benefit in the third quarter 2010 primarily resulted from the reduced net loss period-over-period.

Liquidity and Debt

As of September 30, 2010, Dynegy’s liquidity was approximately $2.1 billion. This consisted of approximately $675 million in cash on hand and short-term investments and approximately $1.4 billion in unused availability under the company’s credit facilities. The approximately $1.4 billion in unused availability under the company’s credit facilities reflects a decrease in revolver availability of approximately $50 million due to covenant limitations as determined by a calculation performed based on September 30, 2010, financial data. Available capacity may be further reduced based on the company’s ratio of secured debt to Adjusted EBITDA at December 31, 2010.

As of November 1, 2010, liquidity was approximately $2 billion, which consisted of approximately $645 million in cash on hand and short-term investments and approximately $1.4 billion in unused availability under the company’s credit facilities.

Using the latest available commodity price curves, Dynegy projects potential non-compliance with certain credit facility financial covenants based on forecast earnings as of June 30, 2011. To avoid such non-compliance, Dynegy expects to proactively amend, extend or refinance its credit facilities during the next six months. There can be no assurance that such activity will result in amended, extended or refinanced facilities or as to our ability to continue to satisfy the covenants contained in such facilities in the absence of such amendment, extension or refinancing thereof.

As of September 30, 2010, Dynegy’s net debt and other obligations totaled approximately $4 billion. This included net cash on hand and short-term investments of approximately $675 million and restricted cash of $850 million.

Consolidated Cash Flow

Adjusted Cash Flow from Operations totaled an inflow of $683 million for the nine months ended September 30, 2010. There was a cash inflow of $992 million from the power generation business, offset by outflows of $309 million in Other resulting primarily from general and administrative expenses and interest payments, net of interest income.

For the nine months ended September 30, 2010, Dynegy’s Adjusted Free Cash Flow was an inflow of $413 million. Capital expenditures included maintenance and environmental capital expenditures of $106 million and $164 million, respectively, the latter of which reflects the company’s continuing investment in environmental upgrades.

For the nine months ended September 30, 2009, Dynegy’s Adjusted Free Cash Flow was an outflow of $13 million. This consisted of Adjusted Cash Flow from Operations of $336 million, offset by maintenance and environmental capital expenditures of $108 million and $241 million, respectively.

On a GAAP basis, Cash Flow from Operations for the nine months ended September 30, 2010, and September 30, 2009, was $670 million and $304 million, respectively. Net cash used in investing activities for the nine months ended September 30, 2010, and September 30, 2009, was $614 million and $341 million, respectively. Net cash used in financing activities was $36 million for the nine months ended September 30, 2010. Net cash provided by financing activities was $47 million for the nine months ended September 30, 2009.

2010 Guidance Estimates

On August 6, 2010, the company provided Adjusted EBITDA, Adjusted Cash Flow from Operations and Adjusted Free Cash Flow ranges for 2010. In today’s news release, the company is narrowing those ranges to reflect greater certainty around its full-year estimates given that only two months remain in 2010. The new ranges are:

  • A range of Adjusted EBITDA of $500 million to $530 million;
  • A range of Adjusted Cash Flow from Operations of $255 million to $285 million; and
  • A range of Adjusted Free Cash Flow of $(90) million to $(60) million.

The guidance estimates for the most directly comparable measures on a GAAP basis include:

  • A range of Net Loss of $(200) million to $(180) million;
  • A range of Cash Flow from Operations of $245 million to $275 million;
  • Net Cash used in Investing Activities of $(685) million; and
  • Net Cash used in Financing Activities of $(65) million.

These estimates reflect quoted forward commodity price curves as of October 4, 2010. These estimates also reflect assumptions regarding, among other things, sales volumes, fuel costs and other operational and commercial activities. Commodity prices fluctuate throughout the year, which creates changes to cash collateral postings. Therefore, the company does not adjust guidance estimates for working capital until prices settle at year-end.

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 12,200 megawatts of baseload, intermediate and peaking power plants fueled by a mix of natural gas, coal and fuel oil.

Cautionary Statement Regarding Forward-Looking Statements

This release contains statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as "forward-looking statements". All statements included or incorporated by reference in this release, 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: (i) the timing and anticipated benefits to be achieved through our 2010-2013 company-wide cost savings program; (ii) beliefs and assumptions relating to liquidity, available borrowing capacity and capital resources generally; (iii) expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations to which we are, or could become, subject; (iv) beliefs about commodity pricing and generation volumes; (v) anticipated liquidity in the regional power and fuel markets in which we transact, including the extent to which such liquidity could be affected by poor economic and financial market conditions or new regulations and any resulting impacts on financial institutions and other current and potential counterparties; (vi) sufficiency of, access to and costs associated with coal, fuel oil and natural gas inventories and transportation thereof; (vii) beliefs and assumptions about market competition, generation capacity and regional supply and demand characteristics of the wholesale power generation market, including the potential for a market recovery over the longer term; (viii) the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility; (ix) beliefs and assumptions about weather and general economic conditions; (x) beliefs regarding the U.S. economy, its trajectory and its impacts, as well as Dynegy’s stock price; (xi) projected operating or financial results, including anticipated cash flows from operations, revenues and profitability; (xii) beliefs and expectations regarding the Plum Point Project; (xiii) expectations regarding our revolver capacity, credit facility compliance, collateral demands, capital expenditures, interest expense and other payments; (xiv) our focus on safety and our ability to efficiently operate our assets so as to maximize our revenue generating opportunities and operating margins; (xv) beliefs about the outcome of legal, regulatory, administrative and legislative matters; (xvi) expectations and estimates regarding capital and maintenance expenditures, including the Midwest Consent Decree and its associated costs; and (xvii) uncertainties associated with the proposed merger of Dynegy and an affiliate of Blackstone (the “Merger”), including uncertainties relating to the anticipated timing of filings and approvals relating to the Merger and the sale by an affiliate of Blackstone of certain assets to NRG Energy, Inc. (the "NRG Sale"), the outcome of legal proceedings that have been or may be instituted against Dynegy and/or others relating to the Merger and/or the NRG Sale, the expected timing of completion of the Merger and the NRG Sale, the satisfaction of the conditions to the consummation of the Merger and the NRG Sale and the ability to complete the Merger and the NRG Sale.

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.

ADDITIONAL INFORMATION AND WHERE TO FIND IT

In connection with the Merger, Dynegy filed a definitive proxy statement with the SEC on October 4, 2010, and commenced mailing the definitive proxy statement and form of proxy to the stockholders of Dynegy. BEFORE MAKING ANY VOTING DECISION, DYNEGY'S STOCKHOLDERS ARE URGED TO READ THE DEFINITIVE PROXY STATEMENT REGARDING THE MERGER CAREFULLY AND IN ITS ENTIRETY BECAUSE IT CONTAINS IMPORTANT INFORMATION ABOUT THE PROPOSED MERGER. Dynegy’s stockholders are able to obtain, without charge, a copy of the definitive proxy statement and other relevant documents filed with the SEC from the SEC’s website at http://www.sec.gov. Dynegy’s stockholders are also able to obtain, without charge, a copy of the definitive proxy statement and other relevant documents by directing a request by mail or telephone to Dynegy Inc., Attn: Corporate Secretary, 1000 Louisiana Street, Suite 5800, Houston, Texas 77002, telephone: (713) 507-6400, or from Dynegy’s website, http://www.dynegy.com.

PARTICIPANTS IN THE SOLICITATION

Dynegy and its directors and officers may be deemed to be participants in the solicitation of proxies from Dynegy’s stockholders with respect to the Merger. Information about Dynegy’s directors and executive officers and their ownership of Dynegy’s common stock is set forth in the proxy statement for Dynegy’s 2010 Annual Meeting of Stockholders, which was filed with the SEC on April 2, 2010. Stockholders may obtain additional information regarding the interests of Dynegy and its directors and executive officers in the Merger, which may be different than those of Dynegy’s stockholders generally, by reading the definitive proxy statement filed with the SEC on October 4, 2010 and other relevant documents regarding the Merger when filed with the SEC.

 
DYNEGY INC.
REPORTED UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE DATA)
       
Three Months Ended
September 30,
Nine Months Ended
September 30,
2010 2009 2010 2009
 
Revenues $ 775 $ 673 $ 1,872 $ 2,027
Cost of sales (334 ) (286 ) (873 ) (927 )
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below (110 ) (121 ) (341 ) (373 )
Depreciation and amortization expense (96 ) (83 ) (261 ) (258 )
Goodwill impairments - - - (433 )
Impairments and other charges, exclusive of goodwill impairments shown separately above (134 ) (148 ) (135 ) (535 )
General and administrative expenses   (51 )   (42 )   (110 )   (125 )
Operating income (loss) 50 (7 ) 152 (624 )
 
Earnings (losses) from unconsolidated investments - (8 ) (34 ) 13
Interest expense (92 ) (115 ) (272 ) (311 )
Other income and expense, net   1     2     3     10  
Loss from continuing operations before income taxes (41 ) (128 ) (151 ) (912 )
 
Income tax benefit   17     34     80     147  
Loss from continuing operations (24 ) (94 ) (71 ) (765 )
 
Income (loss) from discontinued operations, net of tax   -     (129 )   1     (141 )
Net loss (24 ) (223 ) (70 ) (906 )
 
Less: Net loss attributable to the noncontrolling interests   -     (11 )   -     (14 )
Net loss attributable to Dynegy Inc. $ (24 ) $ (212 ) $ (70 ) $ (892 )
 
Basic loss per share attributable to Dynegy Inc.:
Loss from continuing operations (1) $ (0.20 ) $ (0.49 ) $ (0.59 ) $ (4.47 )
Income (loss) from discontinued operations   -     (0.77 )   0.01     (0.84 )
Basic loss per share attributable to Dynegy Inc. $ (0.20 ) $ (1.26 ) $ (0.58 ) $ (5.31 )
 
Diluted loss per share attributable to Dynegy Inc.:
Loss from continuing operations (1) $ (0.20 ) $ (0.49 ) $ (0.59 ) $ (4.47 )
Income (loss) from discontinued operations   -     (0.77 )   0.01     (0.84 )
Diluted loss per share attributable to Dynegy Inc. $ (0.20 ) $ (1.26 ) $ (0.58 ) $ (5.31 )
 
Basic shares outstanding 120 168 120 168
Diluted shares outstanding 121 169 121 169
 
 
(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
September 30,
Nine Months Ended
September 30,
2010 2009 2010 2009
 
Loss from continuing operations $ (24 ) $ (94 ) $ (71 ) $ (765 )
Less: Net loss attributable to the noncontrolling interests   -     (11 )   -     (14 )
Loss from continuing operations attributable to Dynegy Inc. for basic and diluted loss per share $ (24 ) $ (83 ) $ (71 ) $ (751 )
 
Basic weighted-average shares (2) 120 168 120 168
 
Effect of dilutive securities:

 

Stock options and restricted stock   1     1     1     1  
Diluted weighted-average shares (2)   121     169     121     169  
 
 
Loss per share from continuing operations attributable to Dynegy Inc.:

 

Basic $ (0.20 ) $ (0.49 ) $ (0.59 ) $ (4.47 )
 

 

Diluted (3) $ (0.20 ) $ (0.49 ) $ (0.59 ) $ (4.47 )
 
(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 nine months ended September 30, 2010 and 2009.
 
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2010
(UNAUDITED) (IN MILLIONS)
           
Power Generation    
GEN - MW GEN - WE GEN - NE OTHER Total
Net loss attributable to Dynegy Inc. $ (24 )
Plus / (Less):
Income tax benefit (17 )
Interest expense 92
Depreciation and amortization expense   96  
EBITDA (1) $ 206 $ 78 $ (83 ) $ (54 ) $ 147
Plus / (Less):
Asset impairment (2) - - 134 - 134
Transaction fees (3) - -

 

-

 

10

 

10
Mark-to-market gains, net   (90 )   (22 )   (20 )   -     (132 )
Adjusted EBITDA (1) $ 116   $ 56   $ 31   $ (44 ) $ 159  
 
 
 
(1) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 8, 2010, 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) $ 135 $ 61 $ (90 ) $ (56 ) $ 50
Other items, net - - - 1 1
Depreciation and amortization expense   71     17     7     1     96  
EBITDA $ 206   $ 78   $ (83 ) $ (54 ) $ 147  
 
 
(2) During the third quarter 2010, we recognized a pre-tax impairment charge 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 NRG purchase and sales agreement. 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 Quarterly Report on Form 10-Q for the quarter ended September 30, 2010.
 
(3) During the third quarter 2010, we incurred $10 million ($6 million after-tax) of expenses in connection with our proposed merger with an affiliate of Blackstone. These expenses are included in General and administrative expenses on our Reported Unaudited Condensed Consolidated Statements of Operations.
 
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2009
(UNAUDITED) (IN MILLIONS)
         
Power Generation    
GEN - MW GEN - WE GEN - NE OTHER Total
Net loss attributable to Dynegy Inc. $ (212 )
Plus / (Less):
Income tax benefit (118 )
Interest expense (1) 115
Depreciation and amortization expense   87  
EBITDA (2) $ 73 $ (167 ) $ 9 $ (43 ) $ (128 )
Plus / (Less):
Asset impairments (3) 147 235 1 - 383
Sandy Creek mark-to-market losses (4) - 5 - - 5
Noncontrolling interests in change in fair value of interest rate swaps (5) (11 ) - - - (11 )
Mark-to-market losses, net   44     39     45   -     128  
Adjusted EBITDA (2) $ 253   $ 112   $ 55 $ (43 ) $ 377  
 
(1) Includes approximately $15 million of charges related to the change in fair value of the Plum Point IR swaps. These charges are 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 November 8, 2010, 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) $ 5 $ 34 $ 1 $ (47 ) $ (7 )
Losses from unconsolidated investments - (8 ) - - (8 )
Other items, net - 1 - 1 2
Net loss attributable to the noncontrolling interests 11 - - - 11
Depreciation and amortization expense   57     15     8   3     83  
EBITDA from continuing operations 73 42 9 (43 ) 81
EBITDA from discontinued operations (6)   -     (209 )   -   -     (209 )
EBITDA $ 73   $ (167 ) $ 9 $ (43 ) $ (128 )
 
 
(3) 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 the asset impairment charges by region:
 
Pre-tax After-tax
GEN-MW
Renaissance $ 65 $ 40
Riverside/Foothills 18 11
Rocky Road 22 14
Tilton   42     26  
Total (a) $ 147   $ 91  
GEN-WE
Arlington Valley $ 112 $ 68
Griffith   123     75  
Total (b) $ 235   $ 143  
 
(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, 2009.
 
(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, 2009.
 
In addition, GEN-NE also included a $1 million ($1 million after-tax) impairment charge related to 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 is described in our Annual Report on Form 10-K for the year ended December 31, 2009.
 
(4) We recognized pre-tax losses of approximately $5 million ($3 million after-tax) related to the change in fair value of the Sandy Creek Project interest rate swaps. This loss is included in Earnings (losses) from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations.
 
(5) We recorded approximately $11 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.
 
(6) A reconciliation of EBITDA from discontinued operations to Loss from discontinued operations, net of tax, is presented below.
 
EBITDA from discontinued operations $ (209 )
Depreciation and amortization expense from discontinued operations (4 )
Income tax benefit from discontinued operations   84  
Loss from discontinued operations, net of tax $ (129 )
 
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2010
(UNAUDITED) (IN MILLIONS)
           
Power Generation    
GEN - MW GEN - WE GEN - NE OTHER Total
Net loss attributable to Dynegy Inc. $ (70 )
Plus / (Less):
Income tax benefit (1) (80 )
Interest expense 272
Depreciation and amortization expense   261  
EBITDA (2) $ 380 $ 148 $ (32 ) $ (113 ) $ 383
Plus / (Less):
Asset impairments (3) 37 - 135 - 172
Plum Point mark-to-market gains (4) (6 ) - - - (6 )
Transaction fees (5) - - - 10 10
Mark-to-market gains, net   (86 )   (21 )   (16 )   -     (123 )
Adjusted EBITDA (2) $ 325   $ 127   $ 87   $ (103 ) $ 436  
 
(1) Includes a benefit of $18 million related to the release of a reserve for uncertain tax positions upon completion of an audit.
 
(2) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 8, 2010, 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) $ 230 $ 97 $ (56 ) $ (119 ) $ 152
Losses from unconsolidated investments (34 ) - - - (34 )
Other items, net - - 1 2 3
Depreciation and amortization expense   184     50     23     4     261  
EBITDA from continuing operations 380 147 (32 ) (113 ) 382
EBITDA from discontinued operations (6)   -     1     -     -     1  
EBITDA $ 380   $ 148   $ (32 ) $ (113 ) $ 383  
 
(3)

We recognized pre-tax charges of approximately $172 million ($105 million after-tax) related to asset impairments. 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 NRG purchase and sales agreement and $1 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 Quarterly report on Form 10-Q for the quarterly period ended September 30, 2010. We also recognized a pre-tax charge of approximately $37 million ($23 million after-tax) related to the impairment of Dynegy's investment in PPEA Holding Company, LLC due to the uncertainty and risk surrounding PPEA's financial structure.

This charge is included in Earnings (losses) from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations and will be further described in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2010.

 
(4) We recognized pre-tax income of approximately $6 million ($3 million after-tax) related to the change in fair value of the Plum Point Project interest rate swaps. This income is included in Earnings (losses) from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations.
 
(5) During the third quarter 2010, we incurred $10 million ($6 million after-tax) of expenses in connection with our proposed merger with an affiliate of Blackstone. These expenses are included in General and administrative expenses on our Reported Unaudited Condensed Consolidated Statements of Operations.
 
(6) 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  
 
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2009
(UNAUDITED) (IN MILLIONS)
         
Power Generation    
GEN - MW GEN - WE GEN - NE OTHER Total
Net loss attributable to Dynegy Inc. $ (892 )
Plus / (Less):
Income tax benefit (1) (238 )
Interest expense (2) 311
Depreciation and amortization expense   273  
EBITDA (3) $ 302 $ (344 ) $ (385 ) $ (119 ) $ (546 )
Plus / (Less):
Asset impairments (4) 170 235 388 - 793
Goodwill impairment (5) 76 260 97 - 433
Gain on sale of Heard County (6) - (10 ) - - (10 )
Sandy Creek mark-to-market gains (7) - (20 ) - - (20 )
Noncontrolling interests in change in fair value of interest rate swaps (8) (14 ) - - - (14 )
Mark-to-market losses, net   4     50     8     -     62  
Adjusted EBITDA (3) $ 538   $ 171   $ 108   $ (119 ) $ 698  
 
(1) Includes additional expenses primarily due to $151 million nondeductible goodwill, $21 million due to a change in state income tax law and $10 million due to revised assumptions around the ability to utilize certain state deferred tax assets.
 
(2) Includes approximately $17 million of charges related to the change in fair value of the Plum Point IR swaps. These charges are included in the Interest expense 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 10-Q filed on November 8, 2010, 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) $ 143 $ (209 ) $ (424 ) $ (134 ) $ (624 )
Earnings from unconsolidated investments - 12 - 1 13
Other items, net 2 3 - 5 10
Net loss attributable to the noncontrolling interests 14 - - - 14
Depreciation and amortization expense   165     45     39     9     258  
EBITDA from continuing operations 324 (149 ) (385 ) (119 ) (329 )
EBITDA from discontinued operations (9)   (22 )   (195 )   -     -     (217 )
EBITDA $ 302   $ (344 ) $ (385 ) $ (119 ) $ (546 )
 
 
(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, 2009.
 
(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, 2009.
 
In addition, GEN-NE also included a $209 million ($129 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, 2009.
 
(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, 2009.

 
(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) We recognized pre-tax income of approximately $20 million ($12 million after-tax) related to the change in fair value of the Sandy Creek Project interest rate swaps. This income is included in Earnings (losses) from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations.
 
(8) We recorded approximately $14 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.
 
(9) A reconciliation of EBITDA from discontinued operations to Loss from discontinued operations, net of tax, is presented below.
 
EBITDA from discontinued operations $ (217 )
Depreciation and amortization expense from discontinued operations (15 )
Impairments -
Income tax benefit from discontinued operations   91  
Loss from discontinued operations, net of tax $ (141 )
 
DYNEGY INC.
SUMMARY CASH FLOW INFORMATION (1)
(UNAUDITED) (IN MILLIONS)
           
Nine Months Ended September 30, 2010 Nine Months Ended September 30, 2009
GEN OTHER Total GEN OTHER Total
Adjusted EBITDA (2) $ 539 $ (103 ) $ 436 $ 817 $ (119 ) $ 698
Interest payments (3) - (195 ) (195 ) - (231 ) (231 )
Cash taxes - (7 ) (7 ) - (3 ) (3 )
Working capital / non-cash adjustments / other changes   453     (4 )   449     (127 )   (1 )   (128 )
Adjusted Cash Flow from Operations (4) 992 (309 ) 683 690 (354 ) 336
Maintenance capital expenditures (100 ) (6 ) (106 ) (103 ) (5 ) (108 )
Environmental capital expenditures   (164 )   -     (164 )   (241 )   -     (241 )
Adjusted Free Cash Flow (4) $ 728   $ (315 ) $ 413   $ 346   $ (359 ) $ (13 )
   
Net cash used in Investing Activities $ (614 ) $ (341 )
   
Net cash provided by (used in) Financing Activities $ (36 ) $ 47  
 
 
(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 November 8, 2010 for definitions, utility and uses of such non-GAAP financial measures. Please see Reported Segmented Results of Operations for the nine months ended September 30, 2010 and 2009 for a reconciliation of Adjusted EBITDA to Net loss attributable to Dynegy Inc.
 
(3) Includes $6 million of interest payments related to Plum Point for the nine months ended September 30, 2009.
 
(4) 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 November 8, 2010 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.
 
Nine Months Ended September 30, 2010 Nine Months Ended September 30, 2009
GEN OTHER Total GEN OTHER Total
Cash Flow from Operations $ 992 $ (322 ) $ 670 $ 683 $ (379 ) $ 304
Legal and regulatory payments - 3 3 7 6 13
Payment for JV Dissolution - - - - 19 19
Transaction fees   -     10     10     -     -     -  
Adjusted Cash Flow from Operations 992 (309 ) 683 690 (354 ) 336
Maintenance capital expenditures (100 ) (6 ) (106 ) (103 ) (5 ) (108 )
Environmental capital expenditures   (164 )   -     (164 )   (241 )   -     (241 )
Adjusted Free Cash Flow $ 728   $ (315 ) $ 413   $ 346   $ (359 ) $ (13 )
 
DYNEGY INC.
OPERATING DATA
       
 
Three Months Ended
September 30,
Nine Months Ended
September 30,
2010 2009 2010 2009
GEN - MW
Million Megawatt Hours Generated (1) 7.4 6.7 19.4 19.2
In Market Availability for Coal Fired Facilities (2) 91% 92% 90% 89%
Average Capacity Factor for Combined Cycle Facilities (3) 41% 38% 27% 32%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
Cinergy (CIN Hub) $ 48 $ 31 $ 44 $ 35
Commonwealth Edison (NI Hub) $ 49 $ 31 $ 43 $ 34
PJM West $ 65 $ 40 $ 56 $ 45
Average On-Peak Market Spark Spreads ($/MWh) (5):
PJM West $ 33 $ 16 $ 20 $ 13
 
GEN - WE
Million Megawatt Hours Generated (6) 1.1 4.0 3.0 6.8
Average Capacity Factor for Combined Cycle Facilities (3) 32% 60% 36% 36%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
North Path 15 (NP 15) $ 39 $ 38 $ 41 $ 36
Average On-Peak Market Spark Spreads ($/MWh) (5):
North Path 15 (NP 15) $ 8 $ 12 $ 6 $ 8
 
GEN - NE
Million Megawatt Hours Generated 3.0 2.6 6.0 7.8
In Market Availability for Coal Fired Facilities (2) 96% 95% 94% 94%
Average Capacity Factor for Combined Cycle Facilities (3) 65% 44% 43% 44%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
New York - Zone G $ 70 $ 44 $ 60 $ 50
New York - Zone A $ 53 $ 29 $ 45 $ 36
Mass Hub $ 66 $ 37 $ 57 $ 45
Average On-Peak Market Spark Spreads ($/MWh) (5):
New York - Zone A $ 19 $ 4 $ 9 $ 5
Mass Hub $ 34 $ 13 $ 20 $ 11
Fuel Oil $

(59

)

$

(72

)

$

(69

)

$

(45

)

 
Average Natural Gas Price - Henry Hub ($/MMBtu) (7) $ 4.28 $ 3.15 $ 4.58 $ 3.80
 
(1) Includes 0.1 MWh related to our ownership percentage in the MWh generated by our GEN-MW investment in the Plum Point power generation facility for the three and nine months ended September 30, 2010.
 
(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 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 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 nine months ended September 30, 2010 and 2009, respectively.
 
(7) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
 
DYNEGY INC.
2010 EARNINGS ESTIMATES (1)
(IN MILLIONS)
                         
Power Generation        
GEN - MW GEN - WE GEN - NE Total GEN OTHER Total
Adjusted Gross Margin (2) $ 615 $ 630 $ 245 $ 250 $ 240 $ 250 $ 1,100 $ 1,130 $ - $ - $ 1,100 $ 1,130
Operating Expenses (205 ) (205 ) (100 ) (100 ) (160 ) (160 ) (465 ) (465 ) - - (465 ) (465 )
General and Administrative Expense - - - - - - - - (135 ) (135 ) (135 ) (135 )
Other Items, Net   -       -     -       -     -       -     -       -           -       -  
Adjusted EBITDA (2) $ 410     $ 425   $ 145     $ 150   $ 80     $ 90   $ 635     $ 665   $ (135 )   $ (135 ) $ 500     $ 530  
 
2010 CASH FLOW ESTIMATES (1) (3)
(IN MILLIONS)
 
GEN OTHER Total
Adjusted EBITDA (2) $ 635 $ 665 $ (135 ) $ (135 ) $ 500 $ 530
Cash Interest Payments - - (360 ) (360 ) (360 ) (360 )
Cash Tax Payments - - (5 ) (5 ) (5 ) (5 )
Collateral - - 175 175 175 175
Working Capital / Other Changes   (60 )     (60 )   5       5     (55 )     (55 )
Adjusted Cash Flow from Operations (4) 575 605 (320 ) (320 ) 255 285
Maintenance Capital Expenditures (110 ) (110 ) (10 ) (10 ) (120 ) (120 )
Environmental Capital Expenditures (200 ) (200 ) - - (200 ) (200 )
Capitalized Interest   (25 )     (25 )   -       -     (25 )     (25 )
Adjusted Free Cash Flow (4) $ 240     $ 270   $ (330 )   $ (330 ) $ (90 )   $ (60 )
     
Net Cash Used in Investing Activities $ (685 )   $ (685 )
     
Net Cash Used in Financing Activities $ (65 )   $ (65 )
 
(1) 2010 estimates are based on quoted forward commodity price curves using a $4.39/MMBtu gas price as of October 4, 2010. Actual results may vary materially from these estimates based on changes in commodity prices, among other things, including operational activities, legal settlements, financing or investing activities and other uncertain or unplanned items. Reduced 2010 and forward adjusted EBITDA or free cash flow could result from potential divestitures of (a) non-core assets where the earnings potential is limited, or (b) assets where the value that can be captured through a divestiture is believed to outweigh the benefits of continuing to own or operate such assets. Divestitures could also result in impairment charges.
 
(2)

EBITDA, Adjusted EBITDA and Adjusted Gross Margin are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 8, 2010 for definitions, utility and uses of such non-GAAP financial measures. Reconciliations of consolidated EBITDA and Adjusted EBITDA to Net loss attributable to Dynegy Inc. and Adjusted Gross Margin to Operating income (loss) are 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. Accordingly, a reconciliation of EBITDA and Adjusted EBITDA to Operating Income (loss) on a segment level is also presented below.

 
 
Power Generation    
GEN - MW GEN - WE GEN - NE Total GEN OTHER Total
 
Operating Income (Loss) $ 195 $ 210 $ 95 $ 100 $ (75 ) $ (65 ) $ 215 $ 245 $ (155 ) $ (155 ) $ 60 $ 90
Losses From Unconsolidated Investments (35 ) (35 ) - - - - (35 ) (35 ) - - (35 ) (35 )
Other Items, Net - - - - - - - - - - - -
Add: Depreciation and Amortization Expense   285       285     65       65     30       30     380       380     10       10     390       390  
EBITDA $ 445 $ 460 $ 160 $ 165 $ (45 ) $ (35 ) $ 560 $ 590 $ (145 ) $ (145 ) $ 415 $ 445
Plus / (Less):
Asset impairment 40 40 - - 135 135 175 175 - - 175 175
Plum Point Mark-to-Market Gains (5 ) (5 ) - - - - (5 ) (5 ) - - (5 ) (5 )
Transaction fees - - - - - - - - 10 10 10 10
Mark-to-Market Gains, net   (70 )     (70 )   (15 )     (15 )   (10 )     (10 )   (95 )     (95 )   -       -     (95 )     (95 )
Adjusted EBITDA $ 410     $ 425   $ 145     $ 150   $ 80     $ 90   $ 635     $ 665   $ (135 )   $ (135 ) $ 500     $ 530  
 
Power Generation    
GEN - MW GEN - WE GEN - NE Total GEN OTHER Total
Adjusted Gross Margin $ 615 $ 630 $ 245 $ 250 $ 240 $ 250 $ 1,100 $ 1,130 $ - $ - $ 1,100 $ 1,130
Asset impairment - - - - (135 ) (135 ) (135 ) (135 ) - - (135 ) (135 )
Mark-to-Market Gains, net 70 70 15 15 10 10 95 95 - - 95 95
Operating Expenses (205 ) (205 ) (100 ) (100 ) (160 ) (160 ) (465 ) (465 ) - - (465 ) (465 )
Depreciation and Amortization Expense (285 ) (285 ) (65 ) (65 ) (30 ) (30 ) (380 ) (380 ) (10 ) (10 ) (390 ) (390 )
General and Administrative Expenses   -       -     -       -     -       -     -       -     (145 )     (145 )   (145 )     (145 )
Operating Income (Loss) $ 195     $ 210   $ 95     $ 100   $ (75 )   $ (65 ) $ 215     $ 245   $ (155 )   $ (155 ) $ 60     $ 90  
 
Total
Net Loss attributable to Dynegy Inc. $ (200 ) $ (180 )
Add Back:
Income Tax Benefit (150 ) (140 )
Interest Expense 375 375
Depreciation and Amortization Expense   390       390  
EBITDA $ 415 $ 445
Plus / (Less):
Asset Impairment 175 175
Plum Point Mark-to-Market Gains (5 ) (5 )
Transaction fees 10 10
Mark-to-Market Gains, net   (95 )     (95 )
Adjusted EBITDA $ 500     $ 530  
 
(3) This presentation is not intended to be a reconciliation of non-GAAP measures pursuant to Regulation G.
 
(4) 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 November 8, 2010, 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.
 
GEN OTHER Total
Cash Flow From Operations $ 575 $ 605 $ (330 ) $ (330 ) $ 245 $ 275
Payment for Transaction fees   -       -     10       10     10       10  
Adjusted Cash Flow From Operations 575 605 (320 ) (320 ) 255 285
Maintenance Capital Expenditures (110 ) (110 ) (10 ) (10 ) (120 ) (120 )
Environmental Capital Expenditures (200 ) (200 ) - - (200 ) (200 )
Capitalized Interest   (25 )     (25 )   -       -     (25 )     (25 )
Adjusted Free Cash Flow $ 240     $ 270   $ (330 )   $ (330 ) $ (90 )   $ (60 )

Contacts

Dynegy Inc., Houston
Media:
David Byford, 713-767-5800
or
Analysts:
Laura Hrehor, 713-507-6466
or
Joele Frank, Wilkinson Brimmer Katcher
Judy Wilkinson or Matt Sherman, 212-355-4449
or
Mackenzie Partners, Inc.
Mark Harnett or Bob Marese, 212-929-5500

Sharing

Contacts

Dynegy Inc., Houston
Media:
David Byford, 713-767-5800
or
Analysts:
Laura Hrehor, 713-507-6466
or
Joele Frank, Wilkinson Brimmer Katcher
Judy Wilkinson or Matt Sherman, 212-355-4449
or
Mackenzie Partners, Inc.
Mark Harnett or Bob Marese, 212-929-5500