EBITDA for the Midwest segment was $682 million in 2007, compared to EBITDA of $378 million in 2006. The increase in EBITDA in 2007 was primarily driven by higher volumes, including volumes from the Kendall and Ontelaunee plants acquired from LS Power, and increased prices.
2007 results also included a $39 million pre-tax gain on the sale of a portion of the company’s ownership interest in the Plum Point facility. Dynegy, which continues to manage the facility’s construction, now owns approximately 140 megawatts of the 665-megawatt facility.
Results were also impacted by mark-to-market losses of $36 million, a $25 million charge in connection with Illinois rate relief legislation and $9 million of minority interest expense related to interest rate swap agreements. 2006 results included $110 million in pre-tax impairment charges related to the Bluegrass generation facility and mark-to-market earnings of $15 million.
Average actual on-peak market power prices in Cin Hub increased to $61 per megawatt-hour during 2007 from $52 per megawatt-hour in 2006. As a result of the acquisition of assets from LS Power, the company now has a stronger presence in PJM West, where the natural gas spark spread increased to an average of $16.63 per megawatt-hour during 2007, compared to $10.43 per megawatt-hour in 2006.
Volumes generated by the Midwest segment increased 16 percent to 25 million megawatt-hours in 2007, compared to 21.5 million megawatt-hours in 2006.
Beginning in the second quarter 2007, the company’s former South segment was renamed the West segment. The West segment now includes six assets acquired from LS Power, as well as three legacy Dynegy facilities and the Sandy Creek project, which is under construction. EBITDA for the West segment was $439 million in 2007, compared to a loss before interest expense, taxes and depreciation and amortization of $34 million in 2006. These results included contributions from the CoGen Lyondell facility until the completion of its sale on August 1, 2007, and included the Calcasieu facility, the sale of which is expected to close in early 2008.
2007 results included $230 million in EBITDA from discontinued operations, primarily related to the gain on the sale of CoGen Lyondell. In addition, results significantly benefited from the contributions of former LS Power assets. Earnings in 2007 also included a $10 million gain from the sale of a portion of the company’s Sandy Creek ownership interest and mark-to-market earnings of approximately $44 million.
2006 results included a $40 million pre-tax loss in discontinued operations, primarily related to an impairment charge associated with the Calcasieu peaking facility.
The company did not have a significant presence in the West during 2006. For informational purposes, the natural gas spark spread in North Path 15 increased to an average of $16.24 per megawatt-hour during 2007, compared to $13.77 per megawatt-hour in 2006.
Volumes generated by the West segment increased to 11.1 million megawatt-hours during 2007, compared to 0.9 million megawatt-hours in 2006. These volumes exclude the CoGen Lyondell and Calcasieu facilities. The two facilities, which are recorded as discontinued operations, generated 1.8 million megawatt-hours during 2007, compared to 3.0 million megawatt-hours during 2006.
Northeast segment
EBITDA for the Northeast segment was $209 million in 2007, compared to EBITDA of $88 million in 2006. The increase in 2007 EBITDA was primarily driven by higher volumes due to the addition of the Bridgeport and Casco Bay assets, as well as increased run-times at all of the company’s Northeast facilities. Additionally, 2007 results included mark-to-market losses of $40 million, compared to $26 million of mark-to-market losses in 2006.
For informational purposes, the natural gas spark spread in Mass Hub, where the company did not have a presence in 2006, rose to an average of $23.13 per megawatt-hour during 2007, compared to $18.60 per megawatt-hour during 2006.
Sales volumes generated by the Northeast segment increased to 9.4 million megawatt hours during 2007, compared to 4.4 million megawatt hours in 2006. Significantly, volumes at the Roseton facility increased 150 percent compared to 2006, from 0.4 million megawatt-hours in 2006 to 1.0 million megawatt-hours in 2007.
Customer Risk Management Business
EBITDA for the Customer Risk Management segment totaled $29 million in 2007, compared to EBITDA of $34 million in 2006. 2007 results included a $31 million gain associated with the acquisition of the Kendall facility. Upon the completion of the LS Power merger, the Kendall facility’s power tolling contract with the company’s CRM segment became an intercompany agreement.
Results for 2007 and 2006 also included income from discontinued operations of $15 million and $23 million, respectively, primarily related to the favorable settlement of a legacy receivable, offset by legal and settlement charges of approximately $15 million and $53 million, respectively.
4
Other
Other primarily consists of general and administrative expenses and legal and settlement charges, partially offset by interest income. In Other, the company recorded a $139 million loss before interest expense, taxes and depreciation and amortization during 2007, compared to a loss of $100 million during 2006. During 2007, general and administrative expenses were higher as a result of the increased headcount and related expenses associated with the LS Power transaction. This increase was partially offset by greater interest income earned in 2007 due to higher restricted cash balances. 2007 results also included a charge of $21 million related to legal and settlement charges.
Consolidated Interest Expense, Debt Conversion Costs and Taxes
Interest expense and debt conversion costs totaled $384 million for 2007, compared to $631 million in 2006. In 2007, there were no debt conversion and transaction costs, while 2006 results included debt conversion and transaction costs of $249 million. 2006 results also included the acceleration of financing costs of $36 million resulting from the company’s liability management program, as well as a $36 million charge associated with the Sithe Subordinated Debt Exchange. These decreases were offset by increases in 2007 interest expense due to the debt assumed in conjunction with the LS Power combination, which was partially offset by income of $39 million related to interest rate swap agreements.
The 2007 income tax expense from continuing operations was $151 million, compared to an income tax benefit from continuing operations of $152 million for 2006. The 2007 income tax expense, representing an effective rate of 57 percent, includes the impact of a higher anticipated effective state tax rate on the company’s state deferred taxes as a result of changes in levels of business activity in the states where Dynegy does business.
Liquidity
As of December 31, 2007, Dynegy’s liquidity was approximately $1.4 billion. This consisted of $328 million in cash on hand and $1.1 billion in unused availability under the company’s credit facility.
Cash Flow
The company generated cash flow from operations, including working capital changes, of $341 million for 2007. This consisted of a cash inflow of $934 million from the power generation business, which was partially offset by a cash outflow of $563 million in Other resulting primarily from interest payments
5
and general and administrative expenses. In addition, the Customer Risk Management segment had net cash outflows of $30 million, which largely related to gas purchases to satisfy legacy positions.
Cash outflows for maintenance and environmental capital expenditures were $218 million. For 2007, Dynegy’s free cash flow (cash flow from operations less maintenance and environmental capital expenditures) was $123 million. For 2006, the cash outflow from operations was $194 million and maintenance and environmental capital expenditures were $155 million, resulting in a free cash outflow of $349 million.
2008 Cash Flow and Earnings Estimates
On December 12, 2007, Dynegy provided cash flow and earnings estimates for 2008. Those estimates were based on quoted forward commodity price curves as of October 30, 2007. In connection with today’s announcement, Dynegy is updating its 2008 estimates to reflect quoted forward commodity price curves as of January 29, 2008. The new estimates also reflect assumptions regarding, among other things, sales volumes, fuel costs and other operational activities.
The company’s expected 2008 operating cash flow range decreased to $510 million to $610 million from the previous estimate of $585 million to $685 million. The reduction is primarily related to the following changes from the previous estimate:
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| • | $40 million reduction due to the receipt of cash in 2007 associated with 2008 forward sales positions. This cash was originally planned to be received in 2008; |
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| • | $25 million reduction due to deferral of legal settlement and tax payments from 2007 to 2008; and |
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| • | $10 million reduction related to lower interest income, partially offset by lower interest expense, as a result of decreased interest rates. |
In addition to the changes noted above, there were two additional adjustments to free cash flow. First, the company redefined the definition of free cash flow to better reflect the cash-generating ability of the business relative to the company’s required capital expenditure program. The new definition includes cash flow from operations less maintenance and environmental capital expenditures. Previously, free cash flow was defined as cash flow from operations less cash flow from investing activities. This change in definition resulted in a $40 million reduction in 2008 estimated free cash flow due to the elimination from the calculation of items such as net proceeds from asset sales, changes in restricted cash and development capital expenditures. Second, environmental capital expenditures were increased by $35 million due to updated estimates related to previously disclosed environmental investments. The company’s anticipated
6
range of free cash flow is now $100 million to $200 million, down from the previous estimate of $250 million to $350 million.
The company’s expected 2008 EBITDA range decreased to approximately $1.0 billion to $1.1 billion from the previous estimate of approximately $1.1 billion to $1.2 billion. This reduction is primarily related to the following changes from the previous estimate:
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| • | $38 million reduction due to recognition of mark-to-market gains in 2007 related to 2008 forward sales positions; and |
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| • | $20 million reduction due to lower interest rates, which results in lower interest income. |
Investor Conference Call/Web Cast
Dynegy will discuss its 2007 results during an investor conference call and web cast today, February 27, at 9 a.m. ET/8 a.m. CT. Participants may access the web cast and the related presentation materials on the “Investor Relations” section of www.dynegy.com.
About Dynegy Inc.
Dynegy Inc. produces and sells electric energy, capacity and ancillary services in key U.S. markets. The company’s power generation portfolio consists of approximately 20,000 megawatts of baseload, intermediate and peaking power plants fueled by a mix of coal, fuel oil and natural gas. DYNC
Certain statements included in this news release are intended as “forward-looking statements.” These statements include assumptions, expectations, predictions, intentions or beliefs about future events, particularly the statements concerning: Dynegy’s operating performance and positioning for the future; options relating to Dynegy’s building or expansion projects; any statements regarding anticipated earnings or cash flows; Dynegy’s commercial strategy; future growth opportunities; and Dynegy’s estimated financial results for 2008. Historically, Dynegy’s performance has deviated, in some cases materially, from its cash flow and earnings estimates and Dynegy cautions that actual future results may vary materially from those expressed or implied in any forward-looking statements. While Dynegy would expect to update these estimates on a quarterly basis, it does not intend to update these estimates during any quarter because definitive information regarding its quarterly financial results is not available until after the books for the quarter have been closed. Accordingly, Dynegy expects to provide updates only after it has closed the books and reported the results for a particular quarter, or otherwise as may be required by applicable law.
Dynegy cautions that actual future results may vary materially from those expressed or implied in any forward-looking statements. Specifically, Dynegy cautions that: market fundamentals and trends may not be to Dynegy’s benefit or as Dynegy anticipates and may result in reduced options for deploying capital and potentially lower rates of return; Dynegy’s asset base may not perform at the level anticipated; changes in commodity prices for fuel and power may negatively impact Dynegy; growth opportunities may not appear or materialize; and uncertainties exist regarding environmental regulations, litigation and other legal, legislative or regulatory developments and their potential impacts on Dynegy’s businesses. More information about the risks and uncertainties relating to these forward-looking statements are found in Dynegy’s SEC filings, including its Annual Report on Form 10-K for the year ended December 31, 2006, as amended, its Quarterly Report on Form 10-Q for the quarters ended March 31, 2007, June 30, 2007, and September 30, 2007 and its Current Reports, which are available free of charge on the SEC’s web site at http://www.sec.gov. Dynegy expressly disclaims any obligation to update any forward-looking statements contained in this news release to reflect events or circumstances that may arise after the date of this release, except as otherwise required by applicable law.
7
DYNEGY INC.
REPORTED UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE DATA)
| | | | | | | | | | | | | |
| | Three Months Ended
December 31, | | Twelve Months Ended
December 31, | |
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| | 2007 | | 2006 | | 2007 | | 2006 | |
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Revenues | | $ | 724 | | $ | 343 | | $ | 3,103 | | $ | 1,770 | |
Cost of sales, exclusive of depreciation and amortization shown separately below | | | (535 | ) | | (229 | ) | | (2,013 | ) | | (1,136 | ) |
Depreciation and amortization expense | | | (93 | ) | | (53 | ) | | (325 | ) | | (217 | ) |
Impairment and other charges | | | — | | | (12 | ) | | — | | | (119 | ) |
Gain on sale of assets, net | | | 39 | | | — | | | 43 | | | 3 | |
General and administrative expenses | | | (40 | ) | | (36 | ) | | (203 | ) | | (196 | ) |
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Operating income | | | 95 | | | 13 | | | 605 | | | 105 | |
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Losses from unconsolidated investments | | | (9 | ) | | (7 | ) | | (3 | ) | | (1 | ) |
Interest expense | | | (116 | ) | | (72 | ) | | (384 | ) | | (382 | ) |
Debt conversion costs | | | — | | | — | | | — | | | (249 | ) |
Other income and expense, net | | | 23 | | | 13 | | | 49 | | | 54 | |
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Income (loss) from continuing operations before income taxes | | | (7 | ) | | (53 | ) | | 267 | | | (473 | ) |
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Income tax (expense) benefit | | | (56 | ) | | 2 | | | (151 | ) | | 152 | |
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Income (loss) from continuing operations | | | (63 | ) | | (51 | ) | | 116 | | | (321 | ) |
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Income (loss) from discontinued operations, net of tax | | | 17 | | | (7 | ) | | 148 | | | (13 | ) |
Cumulative effect of change in accounting principle, net of tax | | | — | | | — | | | — | | | 1 | |
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Net income (loss) | | $ | (46 | ) | $ | (58 | ) | $ | 264 | | $ | (333 | ) |
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Less: Preferred stock dividends | | | — | | | — | | | — | | | 9 | |
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Net income (loss) applicable to common stockholders | | $ | (46 | ) | $ | (58 | ) | $ | 264 | | $ | (342 | ) |
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Earnings before interest, taxes, and depreciation and amortization (EBITDA) (1) | | $ | 213 | | $ | 57 | | $ | 1,220 | | $ | 366 | |
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Basic earnings (loss) per share: | | | | | | | | | | | | | |
Income (loss) from continuing operations (2) | | $ | (0.08 | ) | $ | (0.10 | ) | $ | 0.15 | | $ | (0.72 | ) |
Income (loss) from discontinued operations | | | 0.02 | | | (0.02 | ) | | 0.20 | | | (0.03 | ) |
Cumulative effect of change in accounting principle | | | — | | | — | | | — | | | — | |
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Basic earnings (loss) per share | | $ | (0.06 | ) | $ | (0.12 | ) | $ | 0.35 | | $ | (0.75 | ) |
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Diluted earnings (loss) per share: | | | | | | | | | | | | | |
Income (loss) from continuing operations (2) | | $ | (0.08 | ) | $ | (0.10 | ) | $ | 0.15 | | $ | (0.72 | ) |
Income (loss) from discontinued operations | | | 0.02 | | | (0.02 | ) | | 0.20 | | | (0.03 | ) |
Cumulative effect of change in accounting principle | | | — | | | — | | | — | | | — | |
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Diluted earnings (loss) per share | | $ | (0.06 | ) | $ | (0.12 | ) | $ | 0.35 | | $ | (0.75 | ) |
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Basic shares outstanding | | | 836 | | | 495 | | | 750 | | | 459 | |
Diluted shares outstanding | | | 838 | | | 497 | | | 752 | | | 509 | |
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(1) | EBITDA is a non-GAAP financial measure. Consolidated EBITDA can be reconciled to Net income (loss) using the following calculation: Net income (loss) plus Income tax expense (benefit), Interest expense and Depreciation and amortization expense equals EBITDA. Management and some members of the investment community utilize EBITDA to measure financial performance on an ongoing basis. However, EBITDA should not be used in lieu of GAAP measures such as net income and cash flow from operations. A reconciliation of EBITDA to Operating income and Net income (loss) for the periods presented is included below. |
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| | Three Months Ended
December 31, | | Twelve Months Ended
December 31, | |
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| | 2007 | | 2006 | | 2007 | | 2006 | |
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Operating income | | $ | 95 | | $ | 13 | | $ | 605 | | $ | 105 | |
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Add: Depreciation and amortization expense, a component of operating income | | | 93 | | | 53 | | | 325 | | | 217 | |
Losses from unconsolidated investments | | | (9 | ) | | (7 | ) | | (3 | ) | | (1 | ) |
Other income and expense, net | | | 23 | | | 13 | | | 49 | | | 54 | |
EBITDA from discontinued operations (3) | | | 11 | | | (15 | ) | | 244 | | | (10 | ) |
Cumulative effect of change in accounting principle, pre-tax | | | — | | | — | | | — | | | 1 | |
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Earnings before interest, taxes, and depreciation and amortization (EBITDA) | | | 213 | | | 57 | | | 1,220 | | | 366 | |
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Depreciation and amortization expense, a component of operating income | | | (93 | ) | | (53 | ) | | (325 | ) | | (217 | ) |
Depreciation and amortization expense from discontinued operations | | | — | | | (3 | ) | | (5 | ) | | (13 | ) |
Interest expense | | | (116 | ) | | (72 | ) | | (384 | ) | | (631 | ) |
Income tax (expense) benefit from continuing operations | | | (56 | ) | | 2 | | | (151 | ) | | 152 | |
Income tax (expense) benefit from discontinued operations | | | 6 | | | 11 | | | (91 | ) | | 10 | |
Income tax benefit on cumulative effect of change in accounting principle | | | — | | | — | | | — | | | — | |
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Net income (loss) | | $ | (46 | ) | $ | (58 | ) | $ | 264 | | $ | (333 | ) |
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(2) | See “Reported Unaudited Basic and Diluted Earnings (Loss) Per Share From Continuing Operations” for a reconciliation of basic earnings (loss) per share from continuing operations to diluted earnings (loss) per share from continuing operations. |
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(3) | A reconciliation of EBITDA from discontinued operations to Income (loss) from discontinued operations, net of tax, for the periods presented is included below. |
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| | Three Months Ended
December 31, | | Twelve Months Ended
December 31, | |
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| | 2007 | | 2006 | | 2007 | | 2006 | |
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EBITDA from discontinued operations | | $ | 11 | | $ | (15 | ) | $ | 244 | | $ | (10 | ) |
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Depreciation and amortization expense from discontinued operations | | | — | | | (3 | ) | | (5 | ) | | (13 | ) |
Income tax (expense) benefit from discontinued operations | | | 6 | | | 11 | | | (91 | ) | | 10 | |
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Income (loss) from discontinued operations, net of tax | | $ | 17 | | $ | (7 | ) | $ | 148 | | $ | (13 | ) |
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DYNEGY INC.
REPORTED UNAUDITED BASIC AND DILUTED EARNINGS (LOSS) PER SHARE FROM CONTINUING OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE DATA)
| | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended
December 31, | | Twelve Months Ended
December 31, | |
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| | 2007 | | 2006 | | 2007 | | 2006 | |
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Income (loss) from continuing operations | | | $ | (63 | ) | | | $ | (51 | ) | | | $ | 116 | | | | $ | (321 | ) | |
Less: convertible preferred stock dividends | | | | — | | | | | — | | | | | — | | | | | 9 | | |
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Income (loss) from continuing operations for basic earnings (loss) per share | | | | (63 | ) | | | | (51 | ) | | | | 116 | | | | | (330 | ) | |
Effect of dilutive securities: | | | | | | | | | | | | | | | | | | | | | |
Interest on convertible subordinated debentures | | | | — | | | | | — | | | | | — | | | | | 3 | | |
Dividends on Series C convertible preferred stock | | | | — | | | | | — | | | | | — | | | | | 9 | | |
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Income (loss) from continuing operations for diluted earnings (loss) per share | | | $ | (63 | ) | | | $ | (51 | ) | | | $ | 116 | | | | $ | (318 | ) | |
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Basic weighted-average shares | | | | 836 | | | | | 495 | | | | | 750 | | | | | 459 | | |
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Effect of dilutive securities: | | | | | | | | | | | | | | | | | | | | | |
Stock options and restricted stock | | | | 2 | | | | | 2 | | | | | 2 | | | | | 2 | | |
Convertible subordinated debentures | | | | — | | | | | — | | | | | — | | | | | 20 | | |
Series C convertible preferred stock | | | | — | | | | | — | | | | | — | | | | | 28 | | |
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Diluted weighted-average shares | | | | 838 | | | | | 497 | | | | | 752 | | | | | 509 | | |
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Earnings (loss) per share from continuing operations: | | | | | | | | | | | | | | | | | | | | | |
Basic | | | $ | (0.08 | ) | | | $ | (0.10 | ) | | | $ | 0.15 | | | | $ | (0.72 | ) | |
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Diluted (1) | | | $ | (0.08 | ) | | | $ | (0.10 | ) | | | $ | 0.15 | | | | $ | (0.72 | ) | |
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(1) | When an entity has a net loss from continuing operations, SFAS No. 128, “Earnings per Share,” prohibits the inclusion of potential common shares in the computation of diluted per-share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three months ended December 31, 2007 and 2006 and for the twelve months ended December 31, 2006. |
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DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended December 31, 2007 | |
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| | Power Generation | | | | | | | | | | |
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| | GEN - MW | | GEN - WE | | GEN - NE | | CRM | | OTHER | | Total | |
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Operating income (loss) | | | $ | 96 | | | | $ | 25 | | | | $ | 16 | | | | $ | 2 | | | | $ | (44 | ) | | | $ | 95 | | |
Losses from unconsolidated investments | | | | — | | | | | (6 | ) | | | | — | | | | | — | | | | | (3 | ) | | | | (9 | ) | |
Other items, net | | | | 1 | | | | | — | | | | | — | | | | | — | | | | | 22 | | | | | 23 | | |
Add: Depreciation and amortization expense, a component of operating income (loss) | | | | 51 | | | | | 24 | | | | | 15 | | | | | — | | | | | 3 | | | | | 93 | | |
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EBITDA from continuing operations (1) | | | | 148 | | | | | 43 | | | | | 31 | | | | | 2 | | | | | (22 | ) | | | | 202 | | |
EBITDA from discontinued operations, pre-tax (2) | | | | — | | | | | 12 | | | | | — | | | | | — | | | | | (1 | ) | | | | 11 | | |
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EBITDA (1) | | | $ | 148 | | | | $ | 55 | | | | $ | 31 | | | | $ | 2 | | | | $ | (23 | ) | | | $ | 213 | | |
Depreciation and amortization expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (93 | ) | |
Interest expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (116 | ) | |
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Pre-tax income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4 | | |
Income tax expense (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (50 | ) | |
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Net loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | (46 | ) | |
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| | Three Months Ended December 31, 2006 | |
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| | Power Generation | | | | | | | | | | |
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| | GEN - MW | | GEN - WE | | GEN - NE | | CRM | | OTHER | | Total | |
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Operating income (loss) | | | $ | 49 | | | | $ | — | | | | $ | (4 | ) | | | $ | 10 | | | | $ | (42 | ) | | | $ | 13 | | |
Losses from unconsolidated investments | | | | — | | | | | (7 | ) | | | | — | | | | | — | | | | | — | | | | | (7 | ) | |
Other items, net | | | | 1 | | | | | — | | | | | 3 | | | | | 3 | | | | | 6 | | | | | 13 | | |
Add: Depreciation and amortization expense, a component of operating income (loss) | | | | 42 | | | | | 2 | | | | | 6 | | | | | — | | | | | 3 | | | | | 53 | | |
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EBITDA from continuing operations (1) | | | | 92 | | | | | (5 | ) | | | | 5 | | | | | 13 | | | | | (33 | ) | | | | 72 | | |
EBITDA from discontinued operations, pre-tax (2) | | | | — | | | | | (37 | ) | | | | — | | | | | 18 | | | | | 4 | | | | | (15 | ) | |
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EBITDA (1) | | | $ | 92 | | | | $ | (42 | ) | | | $ | 5 | | | | $ | 31 | | | | $ | (29 | ) | | | $ | 57 | | |
Depreciation and amortization expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (56 | ) | |
Interest expense and debt conversion costs | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (72 | ) | |
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Pre-tax loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (71 | ) | |
Income tax benefit | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 13 | | |
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Net loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | (58 | ) | |
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(1) | See Note (1) to “Reported Unaudited Condensed Consolidated Statements of Operations.” EBITDA is a non-GAAP financial measure. Consolidated EBITDA can be reconciled to Net income (loss) using the following calculation: Net income (loss) plus Income tax expense (benefit), Interest expense and Depreciation and amortization expense equals EBITDA. Management and some members of the investment community utilize EBITDA to measure financial performance on an ongoing basis. However, EBITDA should not be used in lieu of GAAP measures such as net income and cash flow from operations. |
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(2) | See Note (3) to “Reported Unaudited Condensed Consolidated Statements of Operations.” |
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(3) | Includes an expense resulting from adjusting Dynegy’s temporary differences to a higher overall effective state tax rate. The higher rate was driven by changes in levels of business activity in states in which we do business and the higher state tax rates in which the LS assets are located. |
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DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Twelve Months Ended December 31, 2007 | |
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| | Power Generation | | | | | | | |
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| | GEN - MW | | GEN - WE | | GEN - NE | | CRM | | OTHER | | Total | |
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Operating income (loss) | | | $ | 495 | | | | $ | 130 | | | | $ | 164 | | | | $ | 19 | | | | $ | (203 | ) | | | $ | 605 | | |
Earnings (losses) from unconsolidated investments | | | | — | | | | | 6 | | | | | — | | | | | — | | | | | (9 | ) | | | | (3 | ) | |
Other items, net | | | | (7 | ) | | | | — | | | | | — | | | | | (5 | ) | | | | 61 | | | | | 49 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Add: Depreciation and amortization expense, a component of operating income (loss) | | | | 194 | | | | | 73 | | | | | 45 | | | | | — | | | | | 13 | | | | | 325 | | |
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EBITDA from continuing operations (1) | | | | 682 | | | | | 209 | | | | | 209 | | | | | 14 | | | | | (138 | ) | | | | 976 | | |
EBITDA from discontinued operations, pre-tax (2) | | | | — | | | | | 230 | | | | | — | | | | | 15 | | | | | (1 | ) | | | | 244 | | |
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EBITDA (1) | | | $ | 682 | | | | $ | 439 | | | | $ | 209 | | | | $ | 29 | | | | $ | (139 | ) | | | $ | 1,220 | | |
Depreciation and amortization expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (330 | ) | |
Interest expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (384 | ) | |
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Pre-tax income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 506 | | |
Income tax expense (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (242 | ) | |
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Net income | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 264 | | |
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| | Twelve Months Ended December 31, 2006 | |
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| | Power Generation | | | | | | | |
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| | GEN - MW | | GEN - WE | | GEN - NE | | CRM | | OTHER | | Total | |
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Operating income (loss) | | | $ | 208 | | | | $ | (2 | ) | | | $ | 55 | | | | $ | 7 | | | | $ | (163 | ) | | | $ | 105 | | |
Losses from unconsolidated investments | | | | — | | | | | (1 | ) | | | | — | | | | | — | | | | | — | | | | | (1 | ) | |
Other items, net | | | | 2 | | | | | 1 | | | | | 9 | | | | | 4 | | | | | 38 | | | | | 54 | | |
Cumulative effect of change in accounting principle, pre-tax | | | | — | | | | | — | | | | | — | | | | | — | | | | | 1 | | | | | 1 | | |
Add: Depreciation and amortization expense, a component of operating income (loss) | | | | 168 | | | | | 8 | | | | | 24 | | | | | — | | | | | 17 | | | | | 217 | | |
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EBITDA from continuing operations (1) | | | | 378 | | | | | 6 | | | | | 88 | | | | | 11 | | | | | (107 | ) | | | | 376 | | |
EBITDA from discontinued operations, pre-tax (2) | | | | — | | | | | (40 | ) | | | | — | | | | | 23 | | | | | 7 | | | | | (10 | ) | |
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EBITDA (1) | | | $ | 378 | | | | $ | (34 | ) | | | $ | 88 | | | | $ | 34 | | | | $ | (100 | ) | | | $ | 366 | | |
Depreciation and amortization expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (230 | ) | |
Interest expense and debt conversion costs | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (631 | ) | |
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Pre-tax loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (495 | ) | |
Income tax benefit | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 162 | | |
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Net loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | (333 | ) | |
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(1) | See Note (1) to “Reported Unaudited Condensed Consolidated Statements of Operations.” EBITDA is a non-GAAP financial measure. Consolidated EBITDA can be reconciled to Net income (loss) using the following calculation: Net income (loss) plus Income tax expense (benefit), Interest expense and Depreciation and amortization expense equals EBITDA. Management and some members of the investment community utilize EBITDA to measure financial performance on an ongoing basis. However, EBITDA should not be used in lieu of GAAP measures such as net income and cash flow from operations. |
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(2) | See Note (3) to “Reported Unaudited Condensed Consolidated Statements of Operations.” |
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(3) | Includes an expense resulting from adjusting Dynegy’s temporary differences to a higher overall effective state tax rate. The higher rate was driven by changes in levels of business activity in states in which we do business and the higher state tax rates in which the LS assets are located. |
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DYNEGY INC.
SIGNIFICANT ITEMS
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended December 31, 2007 |
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| | Power Generation | | | | | | | | | | |
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| | GEN - MW | | GEN - WE | | GEN - NE | | CRM | | OTHER | | Total | |
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Discontinued operations (1) | | | $ | — | | | | $ | 12 | | | | $ | — | | | | $ | — | | | | $ | (1 | ) | | | $ | 11 | | |
Gain on partial sale of Plum Point ownership
interest (2) | | | | 39 | | | | | — | | | | | — | | | | | — | | | | | — | | | | | 39 | | |
Taxes (3) | | | | — | | | | | — | | | | | — | | | | | — | | | | | 10 | | | | | 10 | | |
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Total | | | $ | 39 | | | | $ | 12 | | | | $ | — | | | | $ | — | | | | $ | 9 | | | | $ | 60 | | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended December 31, 2006 |
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| | Power Generation | | | | | | | | | | |
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| | GEN - MW | | GEN - WE | | GEN - NE | | CRM | | OTHER | | Total | |
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Asset impairment (4) | | | $ | (14 | ) | | | $ | — | | | | $ | — | | | | $ | — | | | | $ | — | | | | $ | (14 | ) | |
Taxes (5) | | | | — | | | | | — | | | | | — | | | | | — | | | | | (29 | ) | | | | (29 | ) | |
Discontinued operations (6) | | | | — | | | | | (40 | ) | | | | — | | | | | 18 | | | | | 4 | | | | | (18 | ) | |
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Total | | | $ | (14 | ) | | | $ | (40 | ) | | | $ | — | | | | $ | 18 | | | | $ | (25 | ) | | | $ | (61 | ) | |
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(1) | We recognized pre-tax income of approximately $11 million ($17 million after-tax) related to discontinued operations. The income consists primarily of a $14 million pre-tax ($11 million after-tax) gain associated with the sale of our CoGen Lyondell power generation facility to EnergyCo LLC (“EnergyCo”), a joint venture between PNM Resources and a subsidiary of Cascade Investment, LLC. |
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(2) | We recognized a pre-tax gain of approximately $39 million ($24 million after-tax) related to the sale of a portion of our ownership interest in the Plum Point power generation facility. The gain is included in Gain on sale of assets, net on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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(3) | We recognized a tax benefit of $4 million as a result of a change in New York State tax law and a net benefit of $6 million as a result of a net decrease in our tax reserves. This net benefit of $6 million includes a benefit of $9 million to discontinued operations, partly offset by continuing operations expense. |
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(4) | We recognized a pre-tax charge of approximately $14 million ($9 million after-tax) related to the impairment of our Bluegrass Generation Facility due to management’s conclusion that it was more likely than not that this asset would be sold prior to the end of its previously estimated useful life. This charge is included in Impairment and other charges on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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(5) | We recognized an income tax expense of approximately $29 million resulting from the Canadian authorities’ audit of prior year income tax returns. This tax expense is included in Income tax benefit on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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(6) | We recognized pre-tax losses of approximately $18 million ($7 million after-tax) related to discontinued operations. These losses consist of $40 million associated with our Calcasieu and CoGen Lyondell power generation facilities and $18 million pre-tax income on our UK CRM business primarily associated with a receivable previously reserved that was collected in 2007. Included in the $40 million of losses from our GEN-WE segment is a pre-tax charge of approximately $36 million ($23 million after-tax) related to the impairment of our Calcasieu gas-fired peaking facility due to management’s conclusion that it was more likely than not that this asset would be sold prior to the end of its previously estimated useful life. |
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DYNEGY INC.
SIGNIFICANT ITEMS
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Twelve Months Ended December 31, 2007 | |
| |
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| | Power Generation | | | |
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| | GEN - MW | | GEN - WE | | GEN - NE | | CRM | | OTHER | | Total | |
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Discontinued operations (1) | | | $ | — | | | | $ | 225 | | | | $ | — | | | | $ | 15 | | | | $ | (1 | ) | | | $ | 239 | | |
Gain on partial sale of Plum Point ownership interest (2) | | | | 39 | | | | | — | | | | | — | | | | | — | | | | | — | | | | | 39 | | |
Settlement of Kendall toll (3) | | | | — | | | | | — | | | | | — | | | | | 31 | | | | | — | | | | | 31 | | |
Change in fair value of interest rate swaps, net of minority interest (4) | | | | (9 | ) | | | | — | | | | | — | | | | | — | | | | | 39 | | | | | 30 | | |
Gain on sale of Sandy Creek ownership interest (5) | | | | — | | | | | 10 | | | | | — | | | | | — | | | | | — | | | | | 10 | | |
Illinois rate relief charge (6) | | | | (25 | ) | | | | — | | | | | — | | | | | — | | | | | — | | | | | (25 | ) | |
Legal and settlement
charges (7) | | | | — | | | | | — | | | | | — | | | | | (15 | ) | | | | (21 | ) | | | | (36 | ) | |
Taxes (8) | | | | — | | | | | — | | | | | — | | | | | — | | | | | 10 | | | | | 10 | | |
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Total | | | $ | 5 | | | | $ | 235 | | | | $ | — | | | | $ | 31 | | | | $ | 27 | | | | $ | 298 | | |
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|
| | Twelve Months Ended December 31, 2006 | |
| |
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| | Power Generation | | | |
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| | GEN - MW | | GEN - WE | | GEN - NE | | CRM | | OTHER | | Total | |
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Debt conversion costs (9) | | | $ | — | | | | $ | — | | | | $ | — | | | | $ | — | | | | $ | (249 | ) | | | $ | (249 | ) | |
Asset impairments (10) | | | | (110 | ) | | | | (9 | ) | | | | — | | | | | — | | | | | — | | | | | (119 | ) | |
Legal and settlement
charges (11) | | | | — | | | | | — | | | | | — | | | | | (53 | ) | | | | — | | | | | (53 | ) | |
Sithe subordinated debt exchange charge (12) | | | | — | | | | | — | | | | | (36 | ) | | | | — | | | | | — | | | | | (36 | ) | |
Acceleration of financing costs (13) | | | | — | | | | | — | | | | | — | | | | | — | | | | | (36 | ) | | | | (36 | ) | |
Taxes (14) | | | | — | | | | | — | | | | | — | | | | | — | | | | | (29 | ) | | | | (29 | ) | |
Discontinued operations (15) | | | | — | | | | | (53 | ) | | | | — | | | | | 23 | | | | | 7 | | | | | (23 | ) | |
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Total | | | $ | (110 | ) | | | $ | (62 | ) | | | $ | (36 | ) | | | $ | (30 | ) | | | $ | (307 | ) | | | $ | (545 | ) | |
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(1) | We recognized pre-tax income of approximately $239 million ($148 million after-tax) related to discontinued operations. The income consists primarily of a $224 million pre-tax ($121 million after-tax) gain associated with the sale of our CoGen Lyondell power generation facility to EnergyCo LLC (“EnergyCo”), a joint venture between PNM Resources and a subsidiary of Cascade Investment, LLC. |
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(2) | We recognized a pre-tax gain of approximately $39 million ($24 million after-tax) related to the sale of a portion of our ownership interest in the Plum Point power generation facility. The gain is included in Gain on sale of assets, net on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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(3) | We recognized a pre-tax gain of approximately $31 million ($20 million after-tax) related to the Kendall toll settlement. This gain is included in Cost of sales on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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(4) | We recognized a pre-tax gain of approximately $30 million ($19 million after-tax) primarily related to the change in fair value of Plum Point and LS Power IR swaps. This gain is primarily included in Interest expense and Other income and expense, net on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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(5) | We recognized a pre-tax gain of approximately $10 million ($6 million after-tax) on the sale of a 12.5% interest in the Sandy Creek project. This gain is included in Losses from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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(6) | We recognized a pre-tax charge of approximately $25 million ($16 million after-tax) related to the Illinois rate relief settlement. This charge is included in Cost of sales on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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(7) | We recognized pre-tax charges of approximately $36 million ($23 million after-tax) related to legal and settlement charges. These charges are included in General and administrative expenses on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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(8) | We recognized a tax benefit of $4 million as a result of a change in New York State tax law and a net benefit of $6 million as a result of a net decrease in our tax reserves. This net benefit of $6 million includes a benefit of $9 million to discontinued operations, partly offset by continuing operations expense. |
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(9) | We recognized a pre-tax charge of approximately $249 million ($159 million after-tax) related to the premiums and transaction costs associated with our purchase of substantially all of our $1.7 billon Second Priority Senior Secured Notes (SPN Tender Offer), conversion of our $225 million 4.75% Convertible Subordinated Debentures (Convertible Debenture Exchange), and redemption of our $400 million Series C Convertible Preferred Stock (Series C Preferred). This charge is included in Debt conversion costs on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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(10) | We recognized a cumulative pre-tax charge of approximately $119 million ($76 million after-tax) related to the impairments of our Bluegrass and Rockingham natural gas-fired peaking facilities. The Bluegrass Generation facility impairment of $96 million ($61 million after-tax) recorded during the third quarter 2006 was due to recent changes in the market that placed economic constraints on the facility. The Bluegrass impairment of $14 million ($9 million after-tax) recorded in the fourth quarter 2006 was due to management’s conclusion that it was more likely than not that this asset would be sold prior to the end of its previously estimated useful life. The Rockingham impairment of $9 million ($6 million after-tax) recorded during the second quarter 2006 was due to the pending sale of the facility. These charges are included in Impairment and other charges on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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(11) | We recognized a pre-tax charge of approximately $53 million ($34 million after-tax) related to legal and settlement charges. This charge is included in General and administrative expenses on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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(12) | We recognized a pre-tax charge of approximately $36 million ($23 million after-tax) related to the Sithe subordinated debt exchange transaction. This charge is included in Interest expense on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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(13) | We recognized a pre-tax charge of approximately $36 million ($23 million after-tax) related to the acceleration of debt issuance costs associated with our purchase of substantially all our $1.7 billion Second Priority Senior Secured Notes (SPN Tender Offer), redemption of our $400 million Series C Convertible Preferred Stock (Series C Preferred), and our former $1 billion facility comprised of (i) $400 million letter of credit facility and (ii) $600 million revolving credit facility that was replaced in March 2006 and amended in April 2006 with a $470 million revolving credit facility and $200 million term facility. This charge is included in Interest expense on our Reported Unaudited Condensed Consolidated Statements of Operations. |
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(14) | We recognized an income tax expense of approximately $29 million resulting from the Canadian authorities’ audit of prior year income tax returns. This tax expense is included in Income tax benefit on our Reported Unaudited Condensed consolidated Statements of Operations. |
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(15) | We recognized pre-tax losses of approximately $23 million ($13 million after-tax) related to discontinued operations. These losses consist of $53 million associated with our Calcasieu and CoGen Lyondell power generation facilities and $23 million pre-tax income on our UK CRM business primarily associated with a receivable previously reserved that was collected in 2007. Included in the $53 million of losses from our GEN-WE segment is a pre-tax charge of approximately $36 million ($23 million after-tax) related to the impairment of our Calcasieu gas-fired peaking facility. The Calcasieu impairment of $36 million ($23 million after-tax) recorded in the fourth quarter 2006 was due to management’s conclusion that it was more likely than not that this asset would be sold prior to the end of its previously estimated useful life. |
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DYNEGY INC.
SUMMARY CASH FLOW INFORMATION
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | |
| | Twelve Months Ended December 31, 2007 |
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| | GEN | | CRM | | OTHER | | Total | |
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Cash Flow from Operations | | | $ | 934 | | | | $ | (30 | ) | | | $ | (563 | ) | | | $ | 341 | | |
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Capital Expenditures (Maintenance and Environmental) | | | | (203 | ) | | | | — | | | | | (15 | ) | | | | (218 | ) | |
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Free Cash Flow (1) | | | $ | 731 | | | | $ | (30 | ) | | | $ | (578 | ) | | | $ | 123 | | |
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| | Twelve Months Ended December 31, 2006 | |
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| | GEN | | CRM | | OTHER | | Total | | |
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Cash Flow from Operations | | | $ | 698 | | | | $ | (461 | ) | | | $ | (431 | ) | | | $ | (194 | ) | |
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Capital Expenditures (Maintenance and Environmental) | | | | (147 | ) | | | | — | | | | | (8 | ) | | | | (155 | ) | |
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Free Cash Flow (1) | | | $ | 551 | | | | $ | (461 | ) | | | $ | (439 | ) | | | $ | (349 | ) | |
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(1) | Free cash flow is a non-GAAP financial measure. Free cash flow can be reconciled to operating cash flow using the following calculation: Operating cash flow minus maintenance & environmental capital expenditures equals free cash flow. We use free cash flow to measure the cash generating ability of our operating asset-based energy business relative to our capital expenditure obligations. Free cash flow should not be used in lieu of GAAP measures with respect to cash flows and should not be interpreted as available for discretionary expenditures, as mandatory expenditures such as debt obligations are not deducted from the measure. A reconciliation of free cash flow to cash flow from operations for the periods presented is included above. |
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DYNEGY INC.
OPERATING DATA
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| | | Three Months Ended
December 31, | | Twelve Months Ended
December 31, | |
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| | | 2007 | | 2006 | | 2007 | | 2006 | |
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GEN - MW | | | | | | | | | | | | | | | | | | | | | | |
Million Megawatt Hours Generated (1) | | | | | 5.8 | | | | | 5.4 | | | | | 25.0 | | | | | 21.5 | | |
Average Actual On-Peak Market Power Prices ($/MWh) (3): | | | | | | | | | | | | | | | | | | | | | | |
Cinergy (Cin Hub) | | | | $ | 58 | | | | $ | 47 | | | | $ | 61 | | | | $ | 52 | | |
Commonwealth Edison (NI Hub) | | | | $ | 58 | | | | $ | 48 | | | | $ | 59 | | | | $ | 52 | | |
PJM West | | | | $ | 69 | | | | $ | 50 | | | | $ | 71 | | | | $ | 62 | | |
Average Market Spark Spreads ($/MWh): | | | | | | | | | | | | | | | | | | | | | | |
PJM West | | | | $ | 15 | | | | $ | 1 | | | | $ | 17 | | | | $ | 10 | | |
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GEN - WE | | | | | | | | | | | | | | | | | | | | | | |
Million Megawatt Hours Generated (1) (2) | | | | | 3.1 | | | | | 0.1 | | | | | 11.1 | | | | | 0.9 | | |
Average Actual On-Peak Market Power Prices ($/MWh) (3): | | | | | | | | | | | | | | | | | | | | | | |
North Path 15 (NP 15) | | | | $ | 68 | | | | $ | 62 | | | | $ | 67 | | | | $ | 61 | | |
Palo Verde | | | | $ | 58 | | | | $ | 54 | | | | $ | 62 | | | | $ | 58 | | |
Average Market Spark Spreads ($/MWh): | | | | | | | | | | | | | | | | | | | | | | |
North Path 15 (NP 15) | | | | $ | 17 | | | | $ | 14 | | | | $ | 16 | | | | $ | 14 | | |
Palo Verde | | | | $ | 10 | | | | $ | 7 | | | | $ | 13 | | | | $ | 12 | | |
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GEN - NE | | | | | | | | | | | | | | | | | | | | | | |
Million Megawatt Hours Generated | | | | | 2.5 | | | | | 0.8 | | | | | 9.4 | | | | | 4.4 | | |
Average Actual On-Peak Market Power Prices ($/MWh) (3): | | | | | | | | | | | | | | | | | | | | | | |
New York - Zone G | | | | $ | 86 | | | | $ | 70 | | | | $ | 84 | | | | $ | 76 | | |
New York - Zone A | | | | $ | 69 | | | | $ | 54 | | | | $ | 64 | | | | $ | 59 | | |
Mass Hub | | | | $ | 82 | | | | $ | 66 | | | | $ | 78 | | | | $ | 70 | | |
Average Market Spark Spreads ($/MWh): | | | | | | | | | | | | | | | | | | | | | | |
New York - Zone A | | | | $ | 17 | | | | $ | 4 | | | | $ | 12 | | | | $ | 9 | | |
Mass Hub | | | | $ | 28 | | | | $ | 16 | | | | $ | 23 | | | | $ | 19 | | |
Fuel Oil | | | | $ | (40 | ) | | | $ | (6 | ) | | | $ | (16 | ) | | | $ | (10 | ) | |
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Average Natural Gas Price - Henry Hub ($/MMBtu) (4) | | | | $ | 6.92 | | | | $ | 6.60 | | | | $ | 6.95 | | | | $ | 6.74 | | |
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(1) | Includes our ownership percentage in the MWh generated by our GEN-WE investment in Black Mountain for the three and twelve months ended December 31, 2007 and 2006 and includes the MWh generated by our GEN-WE investments in West Coast Power and our GEN-MW investment in Rocky Road for the twelve months ended December 31, 2006. |
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(2) | Excludes approximately 0.7 million MWh for the three months ended December 31, 2006 and 1.7 million MWh and 2.9 million MWh generated for the twelve months ended December 31, 2006 and 2007, respectively, for our CoGen Lyondell facility, which we sold in August 2007, and less than 0.1 million MWh and less than 0.1 million MWh generated by our Calcasieu facility, which is classified as held for sale, for the three and twelve months ended December 31, 2007 and 2006, respectively. |
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(3) | Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices realized by the Company. |
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(4) | Reflects the average of daily quoted prices for the periods presented and does not necessarily reflect prices realized by the Company. |
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DYNEGY INC.
2008 EARNINGS ESTIMATES (1)
(IN MILLIONS)
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| | GEN - MW | | GEN - WE | | GEN - NE | | Total GEN | | OTHER | | Total | |
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EBITDA (2) | | $ | 800 - 850 | | $ | 165 - 185 | | $ | 180 - 200 | | $ | 1,145 - 1,235 | | $ | (155 - 145 | ) | $ | 990 - 1,090 | |
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Depreciation and Amortization | | | (210 | ) | | (105 | ) | | (55 | ) | | (370 | ) | | (10 | ) | | (380 | ) |
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Interest Expense | | | | | | | | | | | | | | | | | | (430 | ) |
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Income Tax Expense | | | | | | | | | | | | | | | | | | (70 - 110 | ) |
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Net Income | | | | | | | | | | | | | | | | | $ | 110 - 170 | |
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2008 CASH FLOW ESTIMATES (1)
(IN MILLIONS)
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| | GEN | | OTHER | | Total | | Less:
Non-Core (4) | | Total Core
Operating
Business | |
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Cash Flow from Operations | | $ | 1,095 - 1,185 | | $ | (585 - 575 | ) | $ | 510 - 610 | | | $ | (35 | ) | $ | 545 - 645 | |
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Capital Expenditures | | | (390 | ) | | (20 | ) | | (410 | ) | | | — | | | (410 | ) |
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Free Cash Flow (3) | | $ | 705 - 795 | | $ | (605 - 595 | ) | $ | 100 -200 | | | $ | (35 | ) | $ | 135 - 235 | |
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(1) | 2008 estimates are presented on a GAAP basis and are based on quoted forward commodity price curves as of 1/29/08. 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 2008 and forward 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. |
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(2) | EBITDA is a non-GAAP financial measure. Consolidated EBITDA can be reconciled to Net income (loss) using the following calculation: Net income (loss) plus Income tax expense (benefit), Interest expense and Depreciation and amortization expense equals EBITDA. Management and some members of the investment community utilize EBITDA to measure financial performance on an ongoing basis. However, EBITDA should not be used in lieu of GAAP measures such as net income and cash flow from operations. |
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(3) | Free cash flow is a non-GAAP financial measure. Free cash flow can be reconciled to operating cash flow using the following calculation: Operating cash flow minus maintenance & environmental capital expenditures equals free cash flow. We use free cash flow to measure the cash generating ability of our operating asset-based energy business relative to our capital expenditure obligations. Free cash flow should not be used in lieu of GAAP measures with respect to cash flows and should not be interpreted as available for discretionary expenditures, as mandatory expenditures such as debt obligations are not deducted from the measure. A reconciliation of free cash flow to cash flow from operations for the periods presented is included above. |
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(4) | The following summarizes the items included in Non-Core operating business in our cash flow estimate. |
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| | Non-core items
in Cash Flow
from Operations | |
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Illinois rate relief (GEN) | | | $ | (10 | ) | |
2007 Deferred payments (CORP) | | | | (25 | ) | |
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Total | | | $ | (35 | ) | |
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