Attached files
| file | filename |
|---|---|
| 8-K - DYNEGY INC 8-K 5-9-2011 - DYNEGY INC. | form8k.htm |
| EX-99.2 - EXHIBIT 99.2 - DYNEGY INC. | ex99_2.htm |
Exhibit 99.1
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FOR IMMEDIATE RELEASE
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NR11-16
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DYNEGY ANNOUNCES FIRST QUARTER 2011 FINANCIAL RESULTS
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·
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First quarter 2011 Adjusted EBITDA was $87 million
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·
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First quarter 2011 net loss was $77 million, compared to net income of $145 million in the first quarter 2010
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HOUSTON (May 9, 2011) – Dynegy Inc. (NYSE: DYN) today announced that Adjusted EBITDA for the first quarter 2011 was $87 million, compared to $152 million for the first quarter 2010. The company also reported a net loss of $77 million or $(0.64) per diluted share for the first quarter 2011, compared to net income of $145 million or $1.20 per diluted share for the first quarter 2010. Lower revenues in the first quarter 2011 included mark-to-market gains of $3 million ($1.8 million after tax). During the first quarter 2010, results included mark-to-market gains of $253 million ($152 million after tax). In addition, the net loss in the first quarter 2011 included an increase in depreciation and amortization expense of approximately $50 million ($31 million after tax) related to the Vermilion power generation facility, which is currently out of operation and in preparation for mothball status.
“While recognizing the current challenging market conditions, Dynegy’s leadership is committed to moving forward with necessary changes that we believe will lead to long-term value for Dynegy stockholders,” said E. Hunter Harrison, interim President and Chief Executive Officer of Dynegy Inc. “Our Board’s Finance and Restructuring Committee is also undertaking a comprehensive review of Dynegy’s various restructuring alternatives with the assistance of outside advisers. The end goal is the creation of a sustainable power generation business that will be in position to benefit from future improvements in the power markets. At the same time, we have sharpened our focus on essential business activities, and are committed to being an efficient, low-cost provider of electricity, while maintaining high standards in terms of safety and reliability.”
First Quarter Comparative Results
A comparison of the company’s first 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 May 9, 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.
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3 Months Ended 3/31/2011
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3 Months Ended 3/31/2010
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|||||||
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Basic Earnings (Loss) Per Share
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$ | (0.64 | ) | $ | 1.21 | |||
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Diluted Earnings (Loss) Per Share
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$ | (0.64 | ) | $ | 1.20 | |||
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Net Income (Loss)
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$ | (77 | ) | $ | 145 | |||
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Add Back:
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||||||||
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Income Tax Expense (Benefit)
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(60 | ) | 65 | |||||
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Interest Expense
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89 | 89 | ||||||
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Depreciation and Amortization Expense
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126 | 75 | ||||||
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EBITDA
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78 | 374 | ||||||
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Plus / (Less):
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||||||||
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Merger Agreement Termination Fee and Other Legal Expenses
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9 | - | ||||||
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Executive Separation Agreement Expenses
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3 | - | ||||||
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Asset Impairment
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- | 37 | ||||||
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Plum Point Mark-to-Market Gains
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- | (6 | ) | |||||
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Mark-to-Market Gains, Net
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(3 | ) | (253 | ) | ||||
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Adjusted EBITDA
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$ | 87 | $ | 152 | ||||
Power Generation
Dynegy’s diversified power generation business includes three business segments: the Midwest, with approximately 4,900 megawatts of generation capacity; the West, with approximately 3,400 megawatts of generation capacity; and the Northeast, with approximately 3,300 megawatts of generation capacity.
Adjusted EBITDA from the power generation segments was $114 million for the first quarter 2011, compared to $185 million for the first quarter 2010. During the first quarter 2011, increased contributions from physical transactions due to improved spark spreads and fewer planned outages were more than offset by decreased contributions from financial transactions due to lower value received from hedging activity. Also during the first quarter 2011, the company was negatively impacted by lower tolling revenue and the net sale of fewer options.
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. The operating loss from the power generation segments was $7 million for the first quarter 2011, compared to operating income of $365 million for the first quarter 2010.
The following operational and commercial factors influenced the company’s first quarter 2011 Adjusted EBITDA as compared to the first quarter 2010.
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·
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Midwest – Adjusted EBITDA decreased 25 percent and production volumes increased 12 percent. Contributions from physical transactions increased due to fewer planned outages and improved spark spreads that benefited the combined-cycle facilities, while financial transactions were less favorable due to the reduced value of hedging activity. Tolling revenues were lower due to the early termination of the Kendall toll in 2010. The increase in production volumes is primarily attributed to fewer planned outages and improved spark spreads that benefited the combined-cycle facilities. During the first quarter 2011, the company’s coal fleet achieved in-market availability of 92 percent.
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·
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West – Adjusted EBITDA decreased 92 percent and production volumes decreased 71 percent. Revenues declined as a result of the net sale of fewer options at lower premiums. The decrease in production volumes is primarily attributed to compressed spark spreads.
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·
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Northeast – Adjusted EBITDA decreased 17 percent and production volumes were essentially flat period-over-period. Contributions from physical transactions increased due to higher prices and improved spark spreads, partially offset by an outage at the Casco Bay facility. Financial transactions were less favorable due to the reduced value of hedging activity. The company’s Danskammer coal units achieved in-market availability of 95 percent.
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Adjusted Cash Flow from Operations for generation was $171 million for the three months ended March 31, 2011, while maintenance and environmental capital expenditures were $25 million and $41 million, respectively. Adjusted Cash Flow from Operations for generation was $537 million for the three months ended March 31, 2010, while maintenance and environmental capital expenditures were $30 million and $69 million, respectively. Adjusted Free Cash Flow from the power generation business was $105 million for the three months ended March 31, 2011, compared to $438 million for the three months ended March 31, 2010.
On a GAAP basis, Cash Flow from Operations for generation for the three months ended March 31, 2011, and March 31, 2010, was $167 million and $537 million, respectively. The decline in Cash Flow from Operations for generation was largely due to a decrease in cash received from the company’s collateral clearing agent as a result of changes in the value of financial positions, which were significantly impacted in 2010 by decreasing power prices. Net cash used in investing activities was $47 million for the three months ended March 31, 2011, and $241 million for the three months ended March 31, 2010. Net cash provided by financing activities was $1 million for the three months ended March 31, 2011, and zero for the three months ended March 31, 2010.
Other
Other primarily consists of general and administrative expenses, partially offset by interest income. General and administrative expenses were $40 million in the first quarter 2011, compared to $31 million in the first quarter 2010. The period-over-period increase in general and administrative expenses primarily resulted from merger agreement transaction expenses, termination fees, legal fees and executive separation agreement expenses. Interest income was less than $1 million for both the first quarter 2011 and the first quarter 2010. In Other, the company reported a $27 million Adjusted loss before interest, taxes and depreciation and amortization ($42 million operating loss) during the first quarter 2011, compared to an Adjusted loss before interest, taxes and depreciation and amortization of $33 million ($34 million operating loss) during the first quarter 2010.
Consolidated Interest Expense and Taxes
The company’s interest expense totaled $89 million for both the first quarter 2011 and the first quarter 2010. The income tax benefit from continuing operations was $60 million for the first quarter 2011, compared to an income tax expense from continuing operations of $65 million for the first quarter 2010. The income tax benefit in the first quarter 2011 primarily resulted from the net loss during the period.
Liquidity and Debt
As of March 31, 2011, Dynegy’s liquidity was approximately $1.4 billion. This consisted of approximately $400 million in cash on hand and short-term investments and approximately $1 billion in unused availability under the company’s credit facility.
As of May 2, 2011, liquidity was approximately $1.2 billion, which consisted of approximately $250 million in cash on hand and short-term investments and approximately $930 million in unused availability under the company’s credit facility. The decrease in liquidity from March 31, 2011, primarily resulted from an increase in the posting of letters of credit and the payment of scheduled debt obligations.
Consolidated Cash Flow
Adjusted Cash Flow from Operations totaled an inflow of $100 million for the three months ended March 31, 2011. There was a cash inflow of $171 million from the power generation business, offset by outflows of $71 million in Other resulting primarily from interest payments and general and administrative expenses, net of interest income.
For the three months ended March 31, 2011, Dynegy’s Adjusted Free Cash Flow was an inflow of $34 million. This consisted of Adjusted Cash Flow from Operations of $100 million, offset by maintenance and environmental capital expenditures of $25 million and $41 million, respectively, the latter of which reflects the company’s continuing investment in environmental upgrades.
For the three months ended March 31, 2010, Dynegy’s Adjusted Free Cash Flow was an inflow of $358 million. This consisted of Adjusted Cash Flow from Operations of $458 million, offset by maintenance and environmental capital expenditures of $31 million and $69 million, respectively.
On a GAAP basis, Cash Flow from Operations for the three months ended March 31, 2011, and March 31, 2010, was $83 million and $458 million, respectively. The decline in Cash Flow from Operations was largely due to a decrease in cash received from the company’s collateral clearing agent as a result of changes in the value of financial positions, which were significantly impacted in 2010 by decreasing power prices. Net cash used in investing activities was $47 million for the three months ended March 31, 2011, and $241 million for the three months ended March 31, 2010. Net cash provided by financing activities was $1 million for the three months ended March 31, 2011, and zero for the three months ended March 31, 2010.
About Dynegy Inc.
Through its subsidiaries, Dynegy Inc. produces and sells electric energy, capacity and ancillary services in key U.S. markets. The power generation portfolio consists of approximately 11,600 megawatts of baseload, intermediate and peaking power plants fueled by a mix of natural gas, coal and fuel oil.
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 Dynegy’s leadership, long-term value for stockholders, restructuring alternatives, the sustainability of the power generation business, improvements in the power markets and Dynegy’s commitment to being an efficient, safe, reliable and low-cost electric provider. 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) Dynegy's ability to address its substantial leverage on favorable terms and its ability to access the capital markets when needed; (ii) the ability of management to execute any new or revised business plan approved by Dynegy’s Board of Directors; (iii) the timing and anticipated benefits to be achieved through Dynegy's restructuring activities and cost savings program; (iv) beliefs and assumptions relating to liquidity, available borrowing capacity and capital resources generally; (v) 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; (vi) beliefs about commodity pricing and generation volumes; (vii) anticipated liquidity in the regional power and fuel markets in which Dynegy transacts, 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; (viii) sufficiency of, access to and costs associated with coal, fuel oil and natural gas inventories and transportation thereof; (ix) 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; (x) the effectiveness of Dynegy's strategies to capture opportunities presented by changes in commodity prices and to manage its exposure to energy price volatility; (xi) beliefs and assumptions about weather and general economic conditions; (xii) beliefs regarding the U.S. economy, its trajectory and its impacts, as well as Dynegy's stock price; (xiii) expectations regarding Dynegy's revolver capacity, credit facility compliance, collateral demands, capital expenditures, interest expense and other payments; (xiv) Dynegy's focus on safety and its ability to efficiently operate its assets so as to maximize its revenue generating opportunities and operating margins; (xv) beliefs about the outcome of legal, regulatory, administrative and legislative matters; and (xvi) expectations and estimates regarding capital and maintenance expenditures, including the Midwest Consent Decree and its associated costs. 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)
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Three Months Ended
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March 31,
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2011
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2010
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Revenues
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$ | 505 | $ | 858 | ||||
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Cost of sales
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(278 | ) | (308 | ) | ||||
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Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below
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(110 | ) | (113 | ) | ||||
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Depreciation and amortization expense
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(126 | ) | (75 | ) | ||||
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General and administrative expenses
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(40 | ) | (31 | ) | ||||
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Operating income (loss)
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(49 | ) | 331 | |||||
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Losses from unconsolidated investments
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- | (34 | ) | |||||
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Interest expense
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(89 | ) | (89 | ) | ||||
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Other income and expense, net
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1 | 1 | ||||||
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Income (loss) from continuing operations before income taxes
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(137 | ) | 209 | |||||
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Income tax benefit (expense)
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60 | (65 | ) | |||||
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Income (loss) from continuing operations
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(77 | ) | 144 | |||||
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Income from discontinued operations, net of tax
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- | 1 | ||||||
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Net income (loss)
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$ | (77 | ) | $ | 145 | |||
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Basic earnings (loss) per share:
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Earnings (loss) from continuing operations (1)
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$ | (0.64 | ) | $ | 1.20 | |||
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Income from discontinued operations
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- | 0.01 | ||||||
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Basic earnings (loss) per share
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$ | (0.64 | ) | $ | 1.21 | |||
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Diluted earnings (loss) per share:
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Earnings (loss) from continuing operations (1)
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$ | (0.64 | ) | $ | 1.19 | |||
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Income from discontinued operations
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- | 0.01 | ||||||
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Diluted earnings (loss) per share
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$ | (0.64 | ) | $ | 1.20 | |||
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Basic shares outstanding
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121 | 120 | ||||||
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Diluted shares outstanding
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121 | 121 | ||||||
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(1)
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A reconciliation of basic earnings (loss) per share from continuing operations to diluted earnings (loss) per share from continuing operations is presented below:
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Three Months Ended
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March 31,
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2011
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2010
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Income (loss) from continuing operations for basic and diluted earnings (loss) per share
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$ | (77 | ) | $ | 144 | |||
| Basic weighted-average shares (2) | 121 | 120 | ||||||
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Effect of dilutive securities:
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Stock options and restricted stock
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- | 1 | ||||||
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Diluted weighted-average shares (2)
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121 | 121 | ||||||
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Earnings (loss) per share from continuing operations:
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Basic
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$ | (0.64 | ) | $ | 1.20 | |||
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Diluted (3)
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$ | (0.64 | ) | $ | 1.19 | |||
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(2)
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Basic and diluted weighted average shares for the three months ended March 31, 2010, have been adjusted to reflect the May 25, 2010, one-for-five reverse stock split.
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(3)
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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 months ended March 31, 2011.
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- more -
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
THREE MONTHS ENDED MARCH 31, 2011
(UNAUDITED) (IN MILLIONS)
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Power Generation
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GEN - MW
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GEN - WE
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GEN - NE
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OTHER
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Total
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Net loss
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$ | (77 | ) | |||||||||||||||||
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Plus / (Less):
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Income tax benefit (1)
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(60 | ) | ||||||||||||||||||
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Interest expense
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89 | |||||||||||||||||||
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Depreciation and amortization expense
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126 | |||||||||||||||||||
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EBITDA (2)
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$ | 97 | $ | 18 | $ | 2 | $ | (39 | ) | $ | 78 | |||||||||
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Plus / (Less):
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Merger agreement termination fee and other legal expenses (3)
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- | - | - | 9 | 9 | |||||||||||||||
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Executive separation agreement expenses (4)
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- | - | - | 3 | 3 | |||||||||||||||
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Mark-to-market (gains) losses, net
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(1 | ) | (15 | ) | 13 | - | (3 | ) | ||||||||||||
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Adjusted EBITDA (2)
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$ | 96 | $ | 3 | $ | 15 | $ | (27 | ) | $ | 87 | |||||||||
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(1)
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Includes $9 million net tax benefit related to an increase in state NOLs due to acceptance of amended returns partially offset by a $3 million net tax expense due to an increase in the Illinois statutory rate.
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(2)
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EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on May 9, 2011, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented below. Management does not allocate interest expenses and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure.
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Power Generation
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GEN - MW
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GEN - WE
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GEN - NE
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OTHER
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Total
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Operating income (loss)
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$ | (3 | ) | $ | 1 | $ | (5 | ) | $ | (42 | ) | $ | (49 | ) | ||||||
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Depreciation and amortization expense
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100 | 17 | 7 | 2 | 126 | |||||||||||||||
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Other items, net
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- | - | - | 1 | 1 | |||||||||||||||
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EBITDA
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$ | 97 | $ | 18 | $ | 2 | $ | (39 | ) | $ | 78 | |||||||||
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(3)
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We incurred $9 million ($6 million after-tax) of expense related to the Icahn merger agreement termination fee and other legal expenses. This expense is included in General and administrative expenses on our Reported Unaudited Condensed Consolidated Statements of Operations.
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(4)
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We incurred $3 million ($2 million after-tax) of expense related to executive separation agreements. This expense is included in General and administrative expenses on our Reported Unaudited Condensed Consolidated Statements of Operations.
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- more -
REPORTED SEGMENTED RESULTS OF OPERATIONS
THREE MONTHS ENDED MARCH 31, 2010
(UNAUDITED) (IN MILLIONS)
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Power Generation
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GEN - MW
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GEN - WE
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GEN - NE
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OTHER
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Total
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Net income
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$ | 145 | ||||||||||||||||||
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Plus / (Less):
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Income tax expense (1)
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65 | |||||||||||||||||||
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Interest expense
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89 | |||||||||||||||||||
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Depreciation and amortization expense
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75 | |||||||||||||||||||
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EBITDA (2)
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$ | 276 | $ | 62 | $ | 69 | $ | (33 | ) | $ | 374 | |||||||||
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Plus / (Less):
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Asset impairment (3)
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37 | - | - | - | 37 | |||||||||||||||
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Plum Point mark-to-market gains (4)
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(6 | ) | - | - | - | (6 | ) | |||||||||||||
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Mark-to-market gains, net
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(179 | ) | (23 | ) | (51 | ) | - | (253 | ) | |||||||||||
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Adjusted EBITDA (2)
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$ | 128 | $ | 39 | $ | 18 | $ | (33 | ) | $ | 152 | |||||||||
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(1)
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Includes a benefit of $16 million related to the release of a reserve for uncertain tax positions upon completion of an audit.
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(2)
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EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on May 9, 2011, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented below. Management does not allocate interest expenses and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure.
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Power Generation
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GEN - MW
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GEN - WE
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GEN - NE
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OTHER
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Total
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Operating income (loss)
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$ | 260 | $ | 45 | $ | 60 | $ | (34 | ) | $ | 331 | |||||||||
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Losses from unconsolidated investments
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(34 | ) | - | - | - | (34 | ) | |||||||||||||
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Other items, net
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- | - | 1 | - | 1 | |||||||||||||||
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Depreciation and amortization expense
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50 | 16 | 8 | 1 | 75 | |||||||||||||||
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EBITDA from continuing operations
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276 | 61 | 69 | (33 | ) | 373 | ||||||||||||||
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EBITDA from discontinued operations (5)
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- | 1 | - | - | 1 | |||||||||||||||
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EBITDA
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$ | 276 | $ | 62 | $ | 69 | $ | (33 | ) | $ | 374 | |||||||||
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(3)
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We recognized a pre-tax charge of approximately $37 million ($23 million after-tax) related to the impairment of our investment in PPEA Holding Company, LLC due to the uncertainty and risk surrounding PPEA's financial structure. This charge is included in Losses from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations.
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(4)
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We recognized pre-tax income of approximately $6 million ($4 million after-tax) related to the change in fair value of the Plum Point Project interest rate swaps. This income is included in Losses from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations.
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(5)
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A reconciliation of EBITDA from discontinued operations to Income from discontinued operations, net of tax, is presented below.
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EBITDA from discontinued operations
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$ | 1 | ||
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Income tax expense from discontinued operations
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- | |||
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Income from discontinued operations, net of tax
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$ | 1 |
- more -
DYNEGY INC.
SUMMARY CASH FLOW INFORMATION (1)
(UNAUDITED) (IN MILLIONS)
|
Three Months Ended March 31, 2011
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Three Months Ended March 31, 2010
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GEN
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OTHER
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Total
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GEN
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OTHER
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Total
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Adjusted EBITDA (2)
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$ | 114 | $ | (27 | ) | $ | 87 | $ | 185 | $ | (33 | ) | $ | 152 | ||||||||||
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Interest payments
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- | (15 | ) | (15 | ) | - | (15 | ) | (15 | ) | ||||||||||||||
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Cash taxes
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- | - | - | - | (3 | ) | (3 | ) | ||||||||||||||||
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Working capital / non-cash adjustments / other changes
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57 | (29 | ) | 28 | 352 | (28 | ) | 324 | ||||||||||||||||
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Adjusted Cash Flow from Operations (3)
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171 | (71 | ) | 100 | 537 | (79 | ) | 458 | ||||||||||||||||
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Maintenance capital expenditures
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(25 | ) | - | (25 | ) | (30 | ) | (1 | ) | (31 | ) | |||||||||||||
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Environmental capital expenditures
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(41 | ) | - | (41 | ) | (69 | ) | - | (69 | ) | ||||||||||||||
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Adjusted Free Cash Flow (3)
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$ | 105 | $ | (71 | ) | $ | 34 | $ | 438 | $ | (80 | ) | $ | 358 | ||||||||||
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Net cash used in Investing Activities
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$ | (47 | ) | $ | (241 | ) | ||||||||||||||||||
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Net cash provided by Financing Activities
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$ | 1 | $ | - | ||||||||||||||||||||
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(1)
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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.
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(2)
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Adjusted EBITDA is a non-GAAP financial measure. Please refer to Item 2.02 of our Form 8-K filed on May 9, 2011, for definitions, utility and uses of such non-GAAP financial measures. Please see Reported Segmented Results of Operations for the three months ended March 31, 2011 and the three months ended March 31, 2010, for a reconciliation of Adjusted EBITDA to Net income (loss).
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(3)
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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 May 9, 2011, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of Adjusted Cash Flow from Operations and Adjusted Free Cash Flow to Cash Flow from Operations is presented below.
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Three Months Ended March 31, 2011
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Three Months Ended March 31, 2010
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GEN
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OTHER
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Total
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GEN
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OTHER
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Total
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|||||||||||||||||||
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Cash Flow from Operations
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$ | 167 | $ | (84 | ) | $ | 83 | $ | 537 | $ | (79 | ) | $ | 458 | ||||||||||
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Merger agreement termination fee and other legal costs
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- | 9 | 9 | - | - | - | ||||||||||||||||||
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Executive separation agreement payments
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- | 3 | 3 | - | - | - | ||||||||||||||||||
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Legal and regulatory payments
|
4 | 1 | 5 | - | - | - | ||||||||||||||||||
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Adjusted Cash Flow from Operations
|
171 | (71 | ) | 100 | 537 | (79 | ) | 458 | ||||||||||||||||
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Maintenance capital expenditures
|
(25 | ) | - | (25 | ) | (30 | ) | (1 | ) | (31 | ) | |||||||||||||
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Environmental capital expenditures
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(41 | ) | - | (41 | ) | (69 | ) | - | (69 | ) | ||||||||||||||
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Adjusted Free Cash Flow
|
$ | 105 | $ | (71 | ) | $ | 34 | $ | 438 | $ | (80 | ) | $ | 358 | ||||||||||
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DYNEGY INC.
OPERATING DATA
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Three Months Ended
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March 31,
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2011
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2010
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GEN - MW
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Million Megawatt Hours Generated
|
7.2 | 6.4 | ||||||
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In Market Availability for Coal Fired Facilities (1)
|
92 | % | 94 | % | ||||
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Average Capacity Factor for Combined Cycle Facilities (2)
|
30 | % | 16 | % | ||||
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Average Quoted On-Peak Market Power Prices ($/MWh) (3):
|
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Cinergy (Cin Hub)
|
$ | 41 | $ | 42 | ||||
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Commonwealth Edison (NI Hub)
|
$ | 39 | $ | 42 | ||||
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PJM West
|
$ | 51 | $ | 52 | ||||
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Average On-Peak Market Spark Spreads ($/MWh) (4):
|
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|
PJM West
|
$ | 11 | $ | 9 | ||||
|
GEN - WE
|
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|
Million Megawatt Hours Generated (5)
|
0.4 | 1.4 | ||||||
|
Average Capacity Factor for Combined Cycle Facilities (2)
|
15 | % | 58 | % | ||||
|
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
|
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|
North Path 15 (NP 15)
|
$ | 35 | $ | 47 | ||||
|
Average On-Peak Market Spark Spreads ($/MWh) (4):
|
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|
North Path 15 (NP 15)
|
$ | 3 | $ | 7 | ||||
|
GEN - NE
|
||||||||
|
Million Megawatt Hours Generated
|
1.5 | 1.5 | ||||||
|
In Market Availability for Coal Fired Facilities (1)
|
95 | % | 92 | % | ||||
|
Average Capacity Factor for Combined Cycle Facilities (2)
|
32 | % | 28 | % | ||||
|
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
|
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|
New York - Zone G
|
$ | 64 | $ | 57 | ||||
|
New York - Zone A
|
$ | 42 | $ | 40 | ||||
|
Mass Hub
|
$ | 65 | $ | 55 | ||||
|
Average On-Peak Market Spark Spreads ($/MWh) (4):
|
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|
New York - Zone A
|
$ | 8 | $ | - | ||||
|
Mass Hub
|
$ | 17 | $ | 9 | ||||
|
Fuel Oil
|
$ | (98 | ) | $ | (72 | ) | ||
|
Average Natural Gas Price - Henry Hub ($/MMBtu) (6)
|
$ | 4.16 | $ | 5.15 | ||||
|
(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 either a 7.0 MMBTU/MWh heat rate natural gas-fired generator or an 11.0 MMBTU/MWh heat fuel oil-fired generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price and does not reflect spark spreads available to us.
|
|
(5)
|
Includes our ownership percentage in the MWh generated by our GEN-WE investment in the Black Mountain power generation facility for the three months ended March 31, 2011, and the three months ended March 31, 2010, respectively.
|
|
(6)
|
Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
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