HOUSTON--(BUSINESS WIRE)--Dynegy Inc. (NYSE: DYN) today announced a net loss of $75 million, or $(0.61) per diluted common share, during the quarter ended September 30, 2011, compared to a net loss of $24 million, or $(0.20) per diluted share, during the same period in 2010. Operating income for the third quarter of 2011 was $5 million, compared to operating income of $50 million during the third quarter 2010. These results include pre-tax, unrealized, net mark-to-market losses of $13 million ($8 million after-tax) and income of $132 million ($79 million after-tax) in the third quarter of 2011 and 2010, respectively. Additionally, results from the third quarter 2010 include after-tax impairment charges of $81 million related to the Casco Bay asset impairment. Adjusted EBITDA for the third quarter of 2011 totaled $106 million, a decrease of $53 million compared to the third quarter 2010. Lower generation for both the Coal and Gas segments together with lower realized prices and spark spreads contributed to weaker quarter over quarter performance. Reduced capacity prices and lower revenues from fewer hedging opportunities also contributed to weaker 2011 financial performance. These reductions were partially offset by a decrease in general and administrative expenses of $19 million as a result of ongoing cost savings and PRIDE initiatives.
Net loss for the nine months ended September 30, 2011 totaled $268 million, or $(2.20) per diluted common share, compared to a net loss of $70 million or $(0.58) per diluted common share during the same period in 2010. Operating loss for the first nine months of 2011 was $150 million compared to operating income of $152 million during the same period in 2010. These results include pre-tax, unrealized, net mark-to-market losses of $140 million and income of $123 million during the nine months ended September 30, 2011 and 2010, respectively. Adjusted EBITDA for the first nine months of 2011 was $295 million compared to $436 million during the same period in 2010. The reduced operating results can be attributed to lower spark spreads in the Northeast and California, lower tolling and capacity payments, lower revenues from hedging activities and lower generation volumes. While operating expenses and general and administrative expenses decreased by $18 million and $13 million, respectively, due to the Vermilion mothballing, the South Bay retirement, the timing of outages, and lower salary and benefit costs; this was insufficient to offset the impact of lower revenues.
“Several milestones in Dynegy’s restructuring occurred during the third quarter. Our portfolios were realigned by fuel type and financed at the operating level, we initiated our PRIDE operating improvement program, and we made significant progress in addressing our legacy debt load,” said Robert C. Flexon, President and Chief Executive Officer of Dynegy. “Our PRIDE initiative has already contributed to the Company’s liquidity and earnings through the re-establishment of the first lien collateral arrangement and lower fixed operating costs. Despite these significant changes during the quarter, our operating teams remained focused on safe and reliable operations and performed well.”
Third Quarter Comparative Results
The non-GAAP financial measures of EBITDA and Adjusted EBITDA 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 of our Current Report on Form 8-K filed with the SEC on November 14, 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.
| Three Months Ended September 30, 2011 | ||||||||||||||||||||
| Coal | Gas | DNE | Other | Total | ||||||||||||||||
| Basic Loss Per Share | $ | (0.61 | ) | |||||||||||||||||
| Diluted Loss Per Share | $ | (0.61 | ) | |||||||||||||||||
| Net loss | $ | (75 | ) | |||||||||||||||||
| Plus / (Less): | ||||||||||||||||||||
| Income tax benefit | (48 | ) | ||||||||||||||||||
| Interest expense and debt extinguishment costs | 128 | |||||||||||||||||||
| Depreciation and amortization expense | 73 | |||||||||||||||||||
| EBITDA | $ | 43 | $ | 61 | $ | (27 | ) | $ | 1 | $ | 78 | |||||||||
| Plus / (Less): | ||||||||||||||||||||
| Restructuring costs | 4 | 11 | - | - | 15 | |||||||||||||||
| Mark-to-market (income) losses, net | 3 | (20 | ) | 26 | 4 | 13 | ||||||||||||||
| Adjusted EBITDA | $ | 50 | $ | 52 | $ | (1 | ) | $ | 5 | $ | 106 | |||||||||
| Three Months Ended September 30, 2010 | ||||||||||||||||||||
| Coal | Gas | DNE | Other | Total | ||||||||||||||||
| Basic Loss Per Share | $ | (0.20 | ) | |||||||||||||||||
| Diluted Loss Per Share | $ | (0.20 | ) | |||||||||||||||||
| Net loss | $ | (24 | ) | |||||||||||||||||
| Plus / (Less): | ||||||||||||||||||||
| Income tax benefit | (17 | ) | ||||||||||||||||||
| Interest expense | 92 | |||||||||||||||||||
| Depreciation and amortization expense | 96 | |||||||||||||||||||
| EBITDA | $ | 145 | $ | (2 | ) | $ | 18 | $ | (14 | ) | $ | 147 | ||||||||
| Plus / (Less): | ||||||||||||||||||||
| Asset impairments | - | 134 | - | - | 134 | |||||||||||||||
| Merger agreement transaction costs | - | - | - | 10 | 10 | |||||||||||||||
| Mark-to-market (income) losses, net | (74 | ) | (43 | ) | (16 | ) | 1 | (132 | ) | |||||||||||
| Adjusted EBITDA | $ | 71 | $ | 89 | $ | 2 | $ | (3 | ) | $ | 159 | |||||||||
Segment Review of Results Period-Over-Period
In August 2011, Dynegy reorganized its operations into three segments: 1) Coal, a 3,132 megawatt fleet of primarily coal based power plants located in the Midwest, 2) Gas, a 6,771 megawatt fleet of natural gas plants located primarily in California and the Northeast, and 3) DNE, 1,570 megawatts of leased natural gas and coal facilities and 123 megawatts of owned gas and oil peaking facilities. The Company has recast its segment information for all prior periods to reflect this reorganization. General and administrative expenses are allocated to each segment. Management does not allocate interest expense and income taxes on a segment level and therefore uses operating income (loss) as the most directly comparable GAAP measure to Adjusted EBITDA when performance is discussed on a segment level.
Coal –Operating income was $4 million compared to $85 million during the third quarters of 2011 and 2010, respectively. Adjusted EBITDA totaled $50 million during the third quarter 2011 compared to $71 million during the same period in 2010. Lower hedged prices and a 12% reduction in generation volumes resulted in the lower quarterly results compared to 2010.
Gas –Operating income was $28 million compared to an operating loss of $37 million during the third quarters of 2011 and 2010, respectively. A $134 million pre-tax asset impairment of the Casco Bay facility in the third quarter of 2010 is included in the operating loss for 2010. Adjusted EBITDA for the Gas segment was $52 million during the third quarter 2011 compared to $89 million during the same period in 2010. While higher tolling revenues offset the loss of the South Bay RMR status in California and weaker capacity prices in the Northeast, the Gas segment’s results were driven primarily by lower power prices and spark spreads in the Company’s key markets which resulted in lower generation volumes and lower energy margin. Additionally, the Gas segment saw lower contributions from commercial activities.
DNE –Operating loss was $27 million compared to operating income of $18 million during the third quarters of 2011 and 2010, respectively. The majority of the decrease is due to a net change in mark-to-market results from income of $16 million in 2010 to a loss of $26 million in 2011. Adjusted EBITDA was $(1) million for the quarter and was relatively flat compared to the corresponding period in 2010.
Liquidity and Debt
As of September 30, 2011, Dynegy’s consolidated liquidity was $1,168 million which included $881 million in unrestricted cash and cash equivalents, $150 million in letter of credit capacity and $137 million in unused collateral.
As previously announced, both the Gas and Coal segments entered into new five year credit agreements on August 5, 2011. The Gas segment’s term loan totaled $1,100 million while the Coal segment’s term loan was for $600 million. These credit agreements not only refinanced outstanding indebtedness of the Company, but also provided significant liquidity to the two operating companies. Additionally, on September 26, 2011, the Company completed a cash tender offer for $192 million of bonds associated with Sithe Independence LLC, a wholly-owned subsidiary of Dynegy Power, LLC. As part of the refinancing, Sithe returned $43 million in previously restricted cash and $83 million in letters of credit to the Gas segment.
During the quarter, the company also executed first lien collateral agreements with hedging counterparties which enabled the Coal and Gas segments to replace previously posted cash collateral with liens on their assets. As a result of these new arrangements, the Company was able to reduce outstanding collateral related to hedging activities by $131 million through September 30, 2011.
Between September 30 and November 8, 2011, $30 in previously posted collateral was returned to the Company as a result of the first lien structure. Together the Sithe tender and the first lien program have resulted in a total of $287 million in restricted cash and collateral returned between August 5 and November 8, 2011.
| September 30, 2011 | ||||||||||||||||
| DPC | DMG | Other | Total | |||||||||||||
| (in millions) | ||||||||||||||||
| LC capacity, inclusive of required reserves | $ | 530 | $ | 103 | $ | 27 | $ | 660 | ||||||||
| Less: Required reserves | (15 | ) | (3 | ) | (1 | ) | (19 | ) | ||||||||
| Less: Outstanding letters of credit | (389 | ) | (76 | ) | (26 | ) | (491 | ) | ||||||||
| LC availability | 126 | 24 | — | 150 | ||||||||||||
| Cash and cash equivalents | 172 | 249 | 460 | 881 | ||||||||||||
| Collateral posting account | 101 | 36 | — | 137 | ||||||||||||
| Total available liquidity | $ | 399 | $ | 309 | $ | 460 | $ | 1,168 | ||||||||
Consolidated Cash Flow
Cash flow from operations for the nine months ended September 30, 2011, was $50 million after posting $66 million of cash collateral to the Company’s futures clearing managers and bilateral counterparties, as compared to cash flow from operations for the first nine months of 2010 of $670 million after the return of $353 million of net cash collateral from the Company’s futures clearing manager and bilateral counterparties. The year-over-year difference is driven by lower operating results in 2011 compared to 2010 and a $379 million net change in collateral associated with broker margins in support of the Company’s hedging program.
Cash flow from investing activities totaled $159 million during the first nine months of 2011 compared to cash flow used by investing activities of $614 million in 2010. For the nine months ended September 30, 2011, capital expenditures totaled $185 million, including $60 million in maintenance capital expenditures and $125 million in environmental capital expenditures, the latter of which reflects the Company’s continuing investment in environmental upgrades as part of the Consent Decree. During the first nine months of 2010, capital expenditures totaled $270 million, with $106 million in maintenance capital expenditures and $164 million in environmental capital expenditures. Additional changes in cash flow from investing can be attributed in part to the restructuring activities completed during the quarter, as well as to liquidation and maturity of short-term investments of cash in 2011.
Cash flow from financing activities totaled $381 million during the first nine months of 2011 compared to a use of $36 million during the first nine months of 2010 due to several refinancing activities completed during the third quarter 2011.
Dynegy PRIDE
During Dynegy’s August 8, 2011 earnings call, management announced a new cost and performance initiative: Dynegy PRIDE (Producing Results through Innovation by Dynegy Employees). As a result of the Company’s continued focus on PRIDE, significant future opportunities to streamline costs and enhance performance have been identified. We expect our combined general and administrative and cash operating expenses to decrease by $49 million in recurring expenses from 2010 to 2011 attributable to the combined benefit of prior cost management efforts and PRIDE.
Restructuring Update
On November 7, 2011, Dynegy and its direct wholly-owned subsidiary, Dynegy Holdings, LLC (DH) reached an agreement with a group of investors holding over $1.4 billion of senior notes issued by DH regarding a framework for the consensual restructuring of over $4.0 billion of obligations owed by DH. In addition, DH and four of its wholly owned subsidiaries – Dynegy Northeast Generation, Inc., Hudson Power, L.L.C., Dynegy Danskammer, L.L.C. (Danskammer) and Dynegy Roseton, L.L.C. (Roseton) – filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court.
First day motions in the case were heard on November 8, 2011 and the Bankruptcy Court provided the debtors with the authority to continue providing pay and benefits to employees, paying suppliers for post-petition goods and services, and continuing certain other payments and policies on an interim basis. The Bankruptcy Court is expected to hear motions related to the rejection of the Roseton and Danskammer leases and other matters on December 2, 2011.
Investor Conference Call/Web Cast
Dynegy will discuss its third quarter 2011 financial results during an investor conference call and web cast today, November 14, 2011, at 9 a.m. ET/8 a.m. CT. Participants may access the web cast and the related presentation materials in the “Investor Relations” section of www.dynegy.com.
About Dynegy Inc.
Dynegy Inc.’s subsidiaries produce and sell electric energy, capacity and ancillary services in key U.S. markets. The Dynegy Power, LLC power generation portfolio consists of approximately 6,771 megawatts of primarily natural gas-fired intermediate and peaking power generation facilities, the Dynegy Midwest Generation, LLC portfolio consists of approximately 3,132 megawatts of primarily coal-fired baseload power plants, and a separate portfolio consists of approximately 1,693 megawatts from two power plants which are primarily natural gas-fired peaking and baseload coal generation facilities.
This press release contains statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as "forward-looking statements," particularly those statements concerning the filing of the Chapter 11 cases for certain of Dynegy’s subsidiaries and the ability of the Chapter 11 process to address legacy financial obligations of those subsidiaries, the restructuring support agreement, Dynegy's first lien collateral arrangement and cost savings initiative “PRIDE” and the anticipated effects on the balance sheet and fixed cost structure, and Dynegy's commitment to safety, capital structure management, PRIDE initiatives and excellent commercial and plant operations. Discussion of risks and uncertainties that could cause actual results to differ materially from current projections, forecasts, estimates and expectations of Dynegy is contained in Dynegy's filings with the Securities and Exchange Commission (the "SEC"). Specifically, Dynegy makes reference to, and incorporates herein by reference, the section entitled "Risk Factors" in its most recent Form 10-K and subsequent reports on Form 10-Q. In addition to the risks and uncertainties set forth in Dynegy's SEC filings, the forward-looking statements described in this press release could be affected by, among other things, (i) beliefs and assumptions regarding our ability to continue as a going concern; (ii) ability to obtain approval of the Bankruptcy Court with respect to the debtors’ motions in the Chapter 11 cases prosecuted from time to time and to develop, prosecute, confirm and consummate one or more plans of reorganization with respect to the Chapter 11 cases and to consummate all the transactions contemplated by the Restructuring Support Agreement (iii) the anticipated effectiveness of the overall restructuring activities and any additional strategies to address our liquidity and our capital resources including accessing the capital markets; (iv) limitations on our ability to utilize previously incurred federal net operating losses or alternative minimum tax credits; (v) the timing and anticipated benefits to be achieved through Dynegy's company-wide cost savings programs, including its PRIDE initiative; (vi) beliefs and assumptions relating to liquidity, available borrowing capacity and capital resources generally, 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; (vii) 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 Dynegy is, or could become, subject; (viii) beliefs, assumptions and projections regarding the demand for power, generation volumes and commodity pricing, including natural gas prices and the impact on such prices from shale gas proliferation and the timing of a recovery in natural gas prices, if any; (ix) sufficiency of, access to and costs associated with coal, fuel oil and natural gas inventories and transportation thereof; (x) beliefs and assumptions about market competition, generation capacity and regional supply and demand characteristics of the wholesale power generation market, including the anticipation of higher market pricing over the longer term; (xi) beliefs and assumptions regarding our ability to enhance or protect long-term value for stockholders; (xii) the effectiveness of Dynegy's strategies to capture opportunities presented by changes in commodity prices and to manage its exposure to energy price volatility; (xiii) beliefs and assumptions about weather and general economic conditions; (xiv) expectations regarding Dynegy's compliance with its new credit facilities, including collateral demands, interest expense and other payments; (xv) projected operating or financial results, including anticipated cash flows from operations, revenues and profitability, Dynegy's focus on safety and its ability to efficiently operate its assets so as to capture revenue generating opportunities and operating margins; (xvi) beliefs about the outcome of legal, regulatory, administrative and legislative matters; and (xvii) expectations regarding performance standards and estimates regarding capital and maintenance expenditures, including the Consent Decree and its associated costs and performance standards. Any or all of Dynegy's 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 Dynegy's control.
| DYNEGY INC. | ||||||||||||||||
| REPORTED UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS | ||||||||||||||||
| (IN MILLIONS, EXCEPT PER SHARE DATA) | ||||||||||||||||
| Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| Revenues | $ | 516 | $ | 775 | $ | 1,347 | $ | 1,872 | ||||||||
| Cost of sales | (298 | ) | (334 | ) | (801 | ) | (873 | ) | ||||||||
| Gross margin | 218 | 441 | 546 | 999 | ||||||||||||
| Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below | (107 | ) | (110 | ) | (323 | ) | (341 | ) | ||||||||
| Depreciation and amortization expense | (73 | ) | (96 | ) | (274 | ) | (261 | ) | ||||||||
| Impairments and other charges | (1 | ) | (134 | ) | (2 | ) | (135 | ) | ||||||||
| General and administrative expenses | (32 | ) | (51 | ) | (97 | ) | (110 | ) | ||||||||
| Operating income (loss) | 5 | 50 | (150 | ) | 152 | |||||||||||
| Losses from unconsolidated investments | - | - | - | (34 | ) | |||||||||||
| Interest expense | (107 | ) | (92 | ) | (285 | ) | (272 | ) | ||||||||
| Debt extinguishment costs | (21 | ) | - | (21 | ) | - | ||||||||||
| Other income and expense, net | - | 1 | 4 | 3 | ||||||||||||
| Loss from continuing operations before income taxes | (123 | ) | (41 | ) | (452 | ) | (151 | ) | ||||||||
| Income tax benefit | 48 | 17 | 184 | 80 | ||||||||||||
| Loss from continuing operations | (75 | ) | (24 | ) | (268 | ) | (71 | ) | ||||||||
| Income from discontinued operations, net of tax | - | - | - | 1 | ||||||||||||
| Net loss | $ | (75 | ) | $ | (24 | ) | $ | (268 | ) | $ | (70 | ) | ||||
| Basic loss per share: | ||||||||||||||||
| Loss from continuing operations (1) | $ | (0.61 | ) | $ | (0.20 | ) | $ | (2.20 | ) | $ | (0.59 | ) | ||||
| Income from discontinued operations | - | - | - | 0.01 | ||||||||||||
| Basic loss per share | $ | (0.61 | ) | $ | (0.20 | ) | $ | (2.20 | ) | $ | (0.58 | ) | ||||
| Diluted loss per share: | ||||||||||||||||
| Loss from continuing operations (1) | $ | (0.61 | ) | $ | (0.20 | ) | $ | (2.20 | ) | $ | (0.59 | ) | ||||
| Income from discontinued operations | - | - | - | 0.01 | ||||||||||||
| Diluted loss per share | $ | (0.61 | ) | $ | (0.20 | ) | $ | (2.20 | ) | $ | (0.58 | ) | ||||
| Basic shares outstanding | 122 | 120 | 122 | 120 | ||||||||||||
| Diluted shares outstanding | 122 | 121 | 122 | 121 | ||||||||||||
| (1) A reconciliation of basic loss per share from continuing operations to diluted loss per share from continuing operations is presented below: | ||||||||||||||||
|
Three Months Ended |
Nine Months Ended | |||||||||||||||
|
September 30, |
September 30, | |||||||||||||||
|
2011 |
2010 | 2011 | 2010 | |||||||||||||
| Loss from continuing operations for basic and diluted loss per share | $ | (75 | ) | $ | (24 | ) | $ | (268 | ) | $ | (71 | ) | ||||
| Basic weighted-average shares (2) | 122 | 120 | 122 | 120 | ||||||||||||
| Effect of dilutive securities: | ||||||||||||||||
| Stock options and restricted stock | - | 1 | - | 1 | ||||||||||||
| Diluted weighted-average shares (2) | 122 | 121 | 122 | 121 | ||||||||||||
| Loss per share from continuing operations | ||||||||||||||||
| Basic | $ | (0.61 | ) | $ | (0.20 | ) | $ | (2.20 | ) | $ | (0.59 | ) | ||||
| Diluted (3) | $ | (0.61 | ) | $ | (0.20 | ) | $ | (2.20 | ) | $ | (0.59 | ) | ||||
| (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, 2011 and 2010. | ||||||||||||||||
| DYNEGY INC. | ||||||||||||||||||
| REPORTED SEGMENTED RESULTS OF OPERATIONS | ||||||||||||||||||
| THREE MONTHS ENDED SEPTEMBER 30, 2011 | ||||||||||||||||||
| (UNAUDITED) (IN MILLIONS) | ||||||||||||||||||
| Three Months Ended September 30, 2011 | ||||||||||||||||||
| Coal | Gas | DNE | Other | Total | ||||||||||||||
| Net loss | $ | (75 | ) | |||||||||||||||
| Plus / (Less): | ||||||||||||||||||
| Income tax benefit | (48 | ) | ||||||||||||||||
| Interest expense & debt extinguishment costs | 128 | |||||||||||||||||
| Depreciation and amortization expense | 73 | |||||||||||||||||
| EBITDA (1) | $ | 43 | $ | 61 | $ | (27 | ) | $ | 1 | $ | 78 | |||||||
| Plus / (Less): | ||||||||||||||||||
| Restructuring costs (2) | 4 | 11 | - | - | 15 | |||||||||||||
| Mark-to-market (income) losses, net | 3 | (20 | ) | 26 | 4 | 13 | ||||||||||||
| Adjusted EBITDA (1) | $ | 50 | $ | 52 | $ | (1 | ) | $ | 5 | $ | 106 | |||||||
|
(1) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 14, 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. |
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| Three Months Ended September 30, 2011 | ||||||||||||||||||
| Coal | Gas | DNE | Other | Total | ||||||||||||||
| Operating income (loss) | $ | 4 | $ | 28 | $ | (27 | ) | $ | - | $ | 5 | |||||||
| Depreciation and amortization expense | 39 | 33 | - | 1 | 73 | |||||||||||||
| EBITDA | $ | 43 | $ | 61 | $ | ( 27 | ) | $ | 1 | $ | 78 | |||||||
|
(2) During the third quarter 2011, we incurred $15 million ($9 million after-tax) of expenses in connection with our debt restructuring. Of these expenses, $8 million are included in Revenues and $7 million are included in General and administrative expenses on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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| DYNEGY INC. | ||||||||||||||||||||||||||||
| REPORTED SEGMENTED RESULTS OF OPERATIONS | ||||||||||||||||||||||||||||
| THREE MONTHS ENDED SEPTEMBER 30, 2010 | ||||||||||||||||||||||||||||
| (UNAUDITED) (IN MILLIONS) | ||||||||||||||||||||||||||||
| Three Months Ended September 30, 2010 | ||||||||||||||||||||||||||||
| Coal | Gas | DNE | Other | Total | ||||||||||||||||||||||||
| Net loss | $ | (24 | ) | |||||||||||||||||||||||||
| Plus / (Less): | ||||||||||||||||||||||||||||
| Income tax benefit | (17 | ) | ||||||||||||||||||||||||||
| Interest expense | 92 | |||||||||||||||||||||||||||
| Depreciation and amortization expense | 96 | |||||||||||||||||||||||||||
| EBITDA (1) | $ 145 | $ (2 | ) |
$ 18 |
$ (14 |
) | $ | 147 | ||||||||||||||||||||
| Plus / (Less): | ||||||||||||||||||||||||||||
| Asset impairments (2) | - | 134 | - | - | 134 | |||||||||||||||||||||||
| Merger agreement transaction costs (3) | - | - | - | 10 | 10 | |||||||||||||||||||||||
| Mark-to-market (income) loss, net | (74 | ) | (43 | ) | (16 | ) | 1 | (132 | ) | |||||||||||||||||||
| Adjusted EBITDA (1) | $ 71 | $ 89 | $ 2 | $ (3 | ) | $ | 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 14, 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. |
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| Three Months Ended September 30, 2010 | ||||||||||||||||||||||||||||
| Coal | Gas | DNE | Other | Total | ||||||||||||||||||||||||
| Operating income (loss) | $ 85 | $ (37 | ) | $ 18 | $ (16 | ) | $ | 50 | ||||||||||||||||||||
| Other items, net | - | - | - | 1 | 1 | |||||||||||||||||||||||
| Depreciation and amortization expense | 60 | 35 | - | 1 | 96 | |||||||||||||||||||||||
| EBITDA | $ 145 | $ (2 | ) | $ 18 | $ (14 | ) | $ | 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. | ||||||||||||||||||||||||||||
| (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 | ||||||||||||||||||||||||||||
| NINE MONTHS ENDED SEPTEMBER 30, 2011 | ||||||||||||||||||||||||||||
| (UNAUDITED) (IN MILLIONS) | ||||||||||||||||||||||||||||
| Nine Months Ended September 30, 2011 | ||||||||||||||||||||||||||||
| Coal | Gas | DNE | Other | Total | ||||||||||||||||||||||||
| Net loss | $ (268 | ) | ||||||||||||||||||||||||||
| Plus / (Less): | ||||||||||||||||||||||||||||
| Income tax benefit (1) | (184 | ) | ||||||||||||||||||||||||||
| Interest expense and debt extinguishment costs | 306 | |||||||||||||||||||||||||||
| Depreciation and amortization expense | 274 | |||||||||||||||||||||||||||
| EBITDA (2) | $ 96 | $ 110 | $ (65 | ) | $ | (13 | ) | $ 128 | ||||||||||||||||||||
| Plus / (Less): | ||||||||||||||||||||||||||||
| Merger agreement termination fee, restructuring costs and other expenses (3) | 4 | 11 | - | 12 | 27 | |||||||||||||||||||||||
| Mark-to-market losses, net | 75 | 14 | 47 | 4 | 140 | |||||||||||||||||||||||
| Adjusted EBITDA (2) | $ 175 | $ 135 | $ (18 | ) | $ | 3 | $ 295 | |||||||||||||||||||||
| (1) Includes a benefit of $9 million related to an increase in state NOLs due to the acceptance of amended returns, partially offset by an expense of $3 million related to an increase in Illinois statutory rate. | ||||||||||||||||||||||||||||
|
(2) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 14, 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. |
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| Nine Months Ended September 30, 2011 | ||||||||||||||||||||||||||||
| Coal | Gas | DNE | Other | Total | ||||||||||||||||||||||||
| Operating income (loss) | $ (73 | ) | $ 9 | $ (65 | ) | $ | (21 | ) | $ (150 | ) | ||||||||||||||||||
| Other items, net | - | 1 | - | 3 | 4 | |||||||||||||||||||||||
| Depreciation and amortization expense | 169 | 100 | - | 5 | 274 | |||||||||||||||||||||||
| EBITDA | $ 96 | $ 110 | $ (65 | ) | $ | (13 | ) | $ 128 | ||||||||||||||||||||
|
(3) We incurred $15 million ($9 million after-tax) of expense related to our debt restructuring, $9 million ($6 million after-tax) of expense related to the Icahn merger agreement termination fee and other legal expenses and $3 million ($2 million after-tax) of expense related to executive separation agreements. Of these expenses, $8 million are included in Revenues and $19 million are included in General and administrative expenses on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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| DYNEGY INC. | |||||||||||||||||||
| REPORTED SEGMENTED RESULTS OF OPERATIONS | |||||||||||||||||||
| NINE MONTHS ENDED SEPTEMBER 30, 2010 | |||||||||||||||||||
| (UNAUDITED) (IN MILLIONS) | |||||||||||||||||||
| Nine Months Ended September 30, 2010 | |||||||||||||||||||
| Coal | Gas | DNE | Other | Total | |||||||||||||||
| Net loss | $ | (70 | ) | ||||||||||||||||
| Plus / (Less): | |||||||||||||||||||
| Income tax benefit (1) | (80 | ) | |||||||||||||||||
| Interest expense | 272 | ||||||||||||||||||
| Depreciation and amortization expense | 261 | ||||||||||||||||||
| EBITDA (2) | $ | 292 | $ | 107 | $ | 32 | $ | (48 | ) | $ | 383 | ||||||||
| Plus / (Less): | |||||||||||||||||||
| Asset impairments (3) | - | 134 | 1 | 37 | 172 | ||||||||||||||
| Plum Point mark-to-market gains (4) | - | - | - | (6 | ) | (6 | ) | ||||||||||||
| Merger agreement transaction costs (5) | - | - | - | 10 | 10 | ||||||||||||||
| Mark-to-market (income) losses, net | (113 | ) | 19 | (41 | ) | 12 | (123 | ) | |||||||||||
| Adjusted EBITDA (2) | $ | 179 | $ | 260 | $ | (8 | ) | $ | 5 | $ | 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 14, 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. |
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| Nine Months Ended September 30, 2010 | |||||||||||||||||||
| Coal | Gas | DNE | Other | Total | |||||||||||||||
| Operating income (loss) | $ | 138 | $ | 2 | $ | 32 | $ | (20 | ) | $ | 152 | ||||||||
| Losses from unconsolidated investments | - | - | - | (34 | ) | (34 | ) | ||||||||||||
| Other items, net | - | 1 | - | 2 | 3 | ||||||||||||||
| Depreciation and amortization expense | 154 | 103 | - | 4 | 261 | ||||||||||||||
| EBITDA from continuing operations | 292 | 106 | 32 | (48 | ) | 382 | |||||||||||||
| EBITDA from discontinued operations (6) | - | 1 | - | - | 1 | ||||||||||||||
| EBITDA | $ | 292 | $ | 107 | $ | 32 | $ | (48 | ) | $ | 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. 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 Losses from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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| (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 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. | ||||||||
| SUMMARY CASH FLOW INFORMATION (1) | ||||||||
| THREE MONTHS ENDED SEPTEMBER 30, 2011 and 2010 | ||||||||
| (UNAUDITED) (IN MILLIONS) | ||||||||
| Three Months Ended September 30, | ||||||||
| 2011 | 2010 | |||||||
| Adjusted EBITDA (2) | $ | 106 | $ | 159 | ||||
| Interest payments | (40 | ) | (16 | ) | ||||
| Cash taxes | - | (1 | ) | |||||
| Collateral | 26 | 98 | ||||||
| Working capital / non-cash adjustments / other changes | 44 | 62 | ||||||
| Cash Flow from Operations | 136 | 302 | ||||||
| Maintenance capital expenditures | (14 | ) | (26 | ) | ||||
| Environmental capital expenditures | (43 | ) | (43 | ) | ||||
| Free Cash Flow | $ | 79 | $ | 233 | ||||
| Net cash provided by (used in) Investing Activities | $ | 254 | $ | (93 | ) | |||
| Net cash provided by Financing Activities | $ | 92 | $ | - | ||||
|
(1) This presentation is intended to demonstrate the relationship between the performance measure of Adjusted EBITDA and the liquidity measure of 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. A reconciliation of Free Cash Flow to Cash Flow from Operations is presented above. Please refer to Item 2.02 of our Form 8-K filed on November 14, 2011, for definitions, utility and uses of such non-GAAP financial measures. |
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| (2) Adjusted EBITDA is a non-GAAP financial measure. Please refer to Item 2.02 of our Form 8-K filed on November 14, 2011, 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, 2011 and 2010 for a reconciliation of Adjusted EBITDA to Net loss. | ||||||||
| DYNEGY INC. | ||||||||
| SUMMARY CASH FLOW INFORMATION (1) | ||||||||
| Nine Months Ended September 30, 2011 and 2010 | ||||||||
| (UNAUDITED) (IN MILLIONS) | ||||||||
| Nine Months Ended September 30, | ||||||||
| 2011 | 2010 | |||||||
| Adjusted EBITDA (2) | $ | 295 | $ | 436 | ||||
| Interest payments | (202 | ) | (195 | ) | ||||
| Cash taxes | - | (7 | ) | |||||
| Collateral | (66 | ) | 353 | |||||
| Working capital / non-cash adjustments / other changes | 23 | 83 | ||||||
| Cash Flow from Operations | 50 | 670 | ||||||
| Maintenance capital expenditures | (60 | ) | (106 | ) | ||||
| Environmental capital expenditures | (125 | ) | (164 | ) | ||||
| Free Cash Flow | $ | (135 | ) | $ | 400 | |||
| Net cash provided by (used in) Investing Activities | $ | 159 | $ | (614 | ) | |||
| Net cash provided by (used in) Financing Activities | $ | 381 | $ | (36 | ) | |||
| (1) This presentation is intended to demonstrate the relationship between the performance measure of Adjusted EBITDA and the liquidity measure of 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. A reconciliation of Free Cash Flow to Cash Flow from Operations is presented above. Please refer to Item 2.02 of our Form 8-K filed on November 14, 2011, for definitions, utility and uses of such non-GAAP financial measures. | ||||||||
| (2) Adjusted EBITDA is a non-GAAP financial measure. Please refer to Item 2.02 of our Form 8-K filed on November 14, 2011, 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, 2011 and 2010 for a reconciliation of Adjusted EBITDA to Net loss. | ||||||||
| DYNEGY INC. | ||||||||||||||||
| OPERATING DATA | ||||||||||||||||
| Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| Coal | ||||||||||||||||
| Million Megawatt Hours Generated | 5.1 | 5.8 | 16.9 | 16.3 | ||||||||||||
| In Market Availability for Coal Fired Facilities (1) | 92 | % | 91 | % | 93 | % | 90 | % | ||||||||
| Average Quoted On-Peak Market Power Prices ($/MWh) (3): | ||||||||||||||||
| Cinergy (CIN Hub) | $ | 47 | $ | 48 | $ | 44 | $ | 44 | ||||||||
| Gas | ||||||||||||||||
| Million Megawatt Hours Generated (5) | 4.4 | 4.7 | 9.6 | 10.3 | ||||||||||||
| Average Capacity Factor for Combined Cycle Facilities (2) | 44 | % | 47 | % | 33 | % | 35 | % | ||||||||
| Average Quoted On-Peak Market Power Prices ($/MWh) (3): | ||||||||||||||||
| Commonwealth Edison (NI Hub) | $ | 48 | $ | 49 | $ | 44 | $ | 43 | ||||||||
| PJM West | $ | 58 | $ | 65 | $ | 55 | $ | 56 | ||||||||
| North Path 15 (NP 15) | $ | 40 | $ | 39 | $ | 36 | $ | 41 | ||||||||
| New York - Zone A | $ | 47 | $ | 53 | $ | 43 | $ | 45 | ||||||||
| Mass Hub | $ | 56 | $ | 66 | $ | 57 | $ | 57 | ||||||||
| Average Market Spark Spreads ($/MWh) (4): | ||||||||||||||||
| PJM West | $ | 28 | $ | 33 | $ | 21 | $ | 20 | ||||||||
| North Path 15 (NP 15) | $ | 7 | $ | 8 | $ | 3 | $ | 6 | ||||||||
| New York - Zone A | $ | 14 | $ | 19 | $ | 10 | $ | 9 | ||||||||
| Mass Hub | $ | 23 | $ | 34 | $ | 19 | $ | 20 | ||||||||
| Average Natural Gas Price - Henry Hub ($/MMBtu) (6) | $ | 4.13 | $ | 4.28 | $ | 4.21 | $ | 4.58 | ||||||||
| DNE | ||||||||||||||||
| Million Megawatt Hours Generated | 0.5 | 0.9 | 1.1 | 1.7 | ||||||||||||
| In Market Availability for Coal Fired Facilities (1) | 94 | % | 96 | % | 95 | % | 94 | % | ||||||||
| Average Capacity Factor - Coal | 37 | % | 63 | % | 34 | % | 54 | % | ||||||||
| Average Capacity Factor - Gas | 7 | % | 12 | % | 4 | % | 5 | % | ||||||||
| Average Quoted On-Peak Market Power Prices ($/MWh) (3): | ||||||||||||||||
| New York - Zone G | $ | 63 | $ | 70 | $ | 61 | $ | 60 | ||||||||
| Average Market Spark Spreads ($/MWh) (4): | ||||||||||||||||
| Fuel Oil | $ | (119 | ) | $ | (59 | ) | $ | (116 | ) | $ | (69 | ) | ||||
| (1) Reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. | ||||||||||||||||
| (2) Reflects actual production as a percentage of available capacity. | ||||||||||||||||
| (3) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized. | ||||||||||||||||
| (4) Reflects the simple average of the spark spread available to a 7.0 MMBtu / MWh heat rate generator or an 11.0 MMBtu / MWh heat rate 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. | ||||||||||||||||
| (5) Includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility for the three and nine months ended September 30, 2011 and 2010, respectively. | ||||||||||||||||
| (6) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. | ||||||||||||||||