Exhibit 99.1
Filed by Dynegy Acquisition, Inc.
Pursuant to Rule 425 of the Securities Act of 1933, as amended, and
deemed filed pursuant to Rule 14a-12 of the Securities Exchange Act of 1934, as amended
Subject Company: Dynegy Inc.
Commission File No: 001-15659
DYNEGY ANNOUNCES 2006 RESULTS
| • | Net loss of $342 million includes $343 million in after-tax charges largely arising from liability management activities that position Dynegy for growth |
| • | Year marked by successful completion of strategic, financial and operational achievements |
| o | Announced pending combination with LS Power |
| o | Reduced debt and other obligations by $2.5 billion |
| o | Higher power prices realized through near-term commercial strategy, resulting in higher generation EBITDA year-over-year |
| • | Cash flow and earnings estimates for 2007 updated |
HOUSTON (February 27, 2007)– Dynegy Inc. (NYSE: DYN) today reported a net loss applicable to common stockholders of $342 million or $0.75 per diluted share for 2006, which included a net loss of $58 million for the fourth quarter 2006. This compares to net income applicable to common stockholders of $68 million or $0.18 per diluted share for 2005, which included net income of $293 million for the fourth quarter 2005.
2006 financial results were impacted by the following significant after-tax items:
| • | $205 million in charges related to liability management activities; |
| • | $99 million in charges related to peaking asset impairments; |
| • | $34 million in legal and settlement charges; and |
| • | $29 million charge related to audits of prior year Canadian tax returns; offset by |
| • | $24 million of income primarily related to a previously written off receivable that is now expected to be collected. |
2005 financial results included the following significant after-tax items:
| • | $778 million in income from the sale of the company’s Midstream business; and |
| • | $89 million in tax benefits primarily due to the reversal of a deferred tax valuation allowance related to gains on the sale of Midstream; offset by |
| • | $338 million in charges related to toll settlements; |
| • | $197 million in legal and settlement charges; and |
| • | $35 million in charges related to investment and equipment impairments. |
In addition to these items, 2006 generation results improved year-over-year due to the company’s near-term commercial sales strategy through which the company realized
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better prices than reflected in the market, despite a 16 percent reduction in net volumes. Additionally, the company benefited from its continued focus on in-market availability.
“2006 was a year in which Dynegy realized the benefits of its strategic, financial and operational achievements and announced a growth opportunity that we believe will position the company to deliver significant value to our investors,” said Bruce A. Williamson, Chairman and Chief Executive Officer of Dynegy Inc. “Our proposed combination with LS Power, which remains on track for completion at the end of the first quarter 2007, is expected to be accretive to free cash flow, as affirmed by our 2007 cash flow and earnings estimates, and provide more predictable cash flows.
“In addition, the company delivered stronger year-over-year results from our Midwest and Northeast regions due to higher prices realized, despite lower volumes,” Williamson added. “These results can be attributed to our near-term commercial sales strategy and our focus on operational reliability. This proven operational approach, combined with the portfolio and financial benefits associated with our proposed combination with LS Power, are expected to position Dynegy to pursue further growth and consolidation opportunities for the benefit of our investors.”
Year-Over-Year Comparison
A comparison of the company’s 2006 and 2005 results is set forth in the table below (in millions of dollars, except per share amounts):
| 2006 | 2005 | |||||||
Loss from continuing operations before income taxes | $ | (526 | ) | $ | (1,199 | ) | ||
Income tax benefit from continuing operations | 168 | 395 | ||||||
Income from discontinued operations, net of tax | 24 | 899 | ||||||
Cumulative effect of change in accounting principles, net of tax | 1 | (5 | ) | |||||
Net income (loss) | $ | (333 | ) | $ | 90 | |||
Less: Preferred stock dividends | 9 | 22 | ||||||
Net income (loss) applicable to common stockholders | $ | (342 | ) | $ | 68 | |||
Basic earnings (loss) per share | $ | (0.75 | ) | $ | 0.18 | |||
Diluted earnings (loss) per share | $ | (0.75 | ) | $ | 0.18 | |||
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Annual Business Results
Following are year-end 2006 business results compared to year-end 2005. Since the company’s Midstream natural gas business was sold to Targa Resources, Inc. in the fourth quarter 2005, Midstream’s results are not included in the company’s 2006 business segment discussions. However, 2005 financial results include the Midstream business as a discontinued operation.
Power Generation Business
Earnings before interest, taxes and depreciation and amortization (EBITDA) from the power generation business was $432 million for 2006, compared to $404 million for 2005. 2006 results included pre-tax impairment charges of $155 million related to the Bluegrass, Calcasieu and Rockingham peaking facilities. 2005 results included pre-tax impairment charges of $56 million related to various investments and equipment. In addition, 2005 results included $66 million of general and administrative expenses, which were reported in the company’s Other results beginning in 2006 and are no longer allocated to the company’s business segments.
Cash flow from operations was $698 million for the 12 months ended December 31, 2006. Net proceeds from asset sales and acquisitions totaled $376 million, which were partially offset by capital expenditures of $147 million and increases in restricted cash and other of $3 million. Free cash flow from the power generation business was an inflow of $924 million.
Following are power generation results for the Midwest, Northeast and South segments.
Midwest segment
Midwest segment EBITDA was $378 million in 2006, and includes $110 million in pre-tax impairment charges related to the Bluegrass generation facility. This compares to EBITDA of $355 million in 2005, which included a $29 million pre-tax impairment charge for a surplus gas turbine sold in 2006, as well as $33 million of general and administrative expenses, which were reported in the company’s Other results beginning in 2006. In addition to these items, the increase in EBITDA during 2006 primarily related to higher prices realized.
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2005 results in the Midwest were impacted by Ameren taking higher volumes than expected under a prior power purchase agreement, resulting in a need to purchase power at market prices in order to satisfy the company’s obligations for forward sales previously made to other customers.
Average actual on-peak market power prices in NI Hub/Com Ed and Cin Hub/Cinergy were lower by 16 percent and 19 percent, respectively, as compared to 2005.
Volumes generated by Midwest facilities decreased slightly to 21.5 million megawatt hours in 2006 compared to 21.9 million megawatt hours in 2005. This decrease was attributed to the reduced operation of the Havana coal-fired facility as a result of Consent Decree compliance and a plant outage, as well as lower peaker volumes related to greater efficiencies associated with Midwest Independent Transmission System Operator (MISO) dispatch practices in 2006.
Northeast segment
EBITDA for Dynegy’s Northeast segment was $88 million in 2006, compared to EBITDA of $53 million in 2005. 2005 results included $22 million of general and administrative expenses, which were reported in the company’s Other results beginning in 2006. Apart from the increase resulting from the treatment of general and administrative expenses, the increase in 2006 EBITDA primarily resulted from higher prices realized and improved capacity sales at the Independence facility, partially offset by lower volumes and a fuel oil inventory write-down at the Roseton facility.
Average actual on-peak market power prices in New York Zone G (Roseton and Danskammer) and New York Zone A (Independence) were lower by 17 percent and 22 percent, respectively, as compared to 2005.
Volumes generated by Northeast facilities decreased to 4.4 million megawatt hours during 2006 compared to 8.3 million megawatt hours during 2005. The most significant factor behind lower Northeast volumes was the reduced operation of the Roseton facility, which resulted from higher fuel oil costs leading to compressed spark spreads. Volumes from the Independence facility also declined due to compressed spark spreads.
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South segment
The loss before interest, taxes and depreciation and amortization for the South segment was $34 million during 2006 compared to a loss of $4 million in 2005. 2006 results were impacted by $45 million in pre-tax impairment charges related to the Calcasieu and Rockingham peaking facilities. 2005 results included $27 million in pre-tax impairment charges related to certain equity investments and $11 million of general and administrative expenses, which were reported in the company’s Other results beginning in 2006. In addition to these items, the increased loss in 2006 resulted primarily from lower earnings from equity investments as a result of asset sales completed in early 2006.
Average actual on-peak market power prices in the Electric Reliability Council of Texas (ERCOT) were 21 percent lower than during 2005.
Net volumes generated by South segment facilities decreased from 5.3 million megawatt hours during 2005 to 3.9 million megawatt hours during 2006, with lower volumes primarily attributed to asset sales completed in early 2006.
Customer Risk Management Business
EBITDA for the Customer Risk Management (CRM) business totaled $34 million during 2006, compared to a $640 million loss before interest, taxes and depreciation and amortization in 2005. 2006 results primarily benefited from mark-to-market gains on legacy trading positions and earnings related to the release of a bad debt reserve against a receivable that was previously assessed as uncollectible. This income was partially offset by $53 million of pre-tax legal and settlement charges, which are reflected in consolidated general and administrative expenses for 2006.
The 2005 loss included pre-tax charges of $364 million and $169 million, respectively, related to agreements to terminate the Sterlington power tolling obligation and the Independence toll restructuring associated with the Sithe Energies acquisition. 2005 results also included legal and settlement charges of $38 million, which are reflected in consolidated general and administrative expenses for 2005. Additionally, the
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2005 loss includes payments in excess of realized margins under the Sterlington and Gregory tolling arrangements, which are no longer operative, and mark-to-market losses.
Other
The loss before interest, taxes and depreciation and amortization for the company’s Other results was $100 million during 2006, compared to EBITDA of $986 million in 2005.
Other results in 2006 included approximately $143 million of general and administrative expenses, including costs related to the company’s business segments. 2005 results included pre-tax income from discontinued operations of approximately $1.3 billion, which primarily related to the Midstream business that was sold in the fourth quarter 2005. This income was partially offset by $249 million in pre-tax legal and settlement charges included in general and administrative expenses. In addition, 2005 results included $115 million of general and administrative expenses related to the company’s Other results, which excludes $66 million in expenses associated with the generation business segments. Other results benefited year-over-year from higher interest income resulting from higher cash balances and higher interest rates earned on cash deposits. Additionally, compensation and benefits costs and professional and legal fees were lower in 2006 compared to 2005.
Consolidated Interest and Taxes
Interest expense and debt conversion costs totaled $631 million during 2006, compared to $389 million during 2005. The increase is primarily due to $249 million in pre-tax debt conversion costs resulting from the company’s 2006 liability management activities, a $36 million pre-tax charge related to the Sithe Subordinated Debt exchange and a $36 million pre-tax charge for acceleration of financing costs. These charges were partially offset by the effects of lower interest rates and principal balances resulting from Dynegy’s liability management activities.
The 2006 income tax benefit from continuing operations was $168 million, compared to an income tax benefit from continuing operations of $395 million for 2005.
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Liquidity
As of December 31, 2006, Dynegy’s liquidity was approximately $878 million. This consisted of $371 million in cash on hand and $507 million in unused availability under the company’s revolving bank credit facility and term letter of credit facility.
Cash Flow
Cash flow from operations, including working capital changes, totaled an outflow of $194 million for the 12 months ended December 31, 2006. There was a cash inflow of $698 million from the power generation business. In the company’s CRM business, there were cash outflows of $461 million, which were primarily related to the payment to exit the Sterlington power tolling arrangement and the payment of legal and settlement charges. In the company’s Other results, there were cash outflows of $431 million, which resulted primarily from interest payments and general and administrative expenses, partially offset by interest income.
Cash flow from investing activities for the 12 months ended December 31, 2006 totaled $358 million. This consisted of net proceeds from asset sales and acquisitions of $384 million and net decreases in restricted cash and other of $129 million, partially offset by capital expenditures of $155 million.
For the 12 months ended December 31, 2006, Dynegy’s free cash flow (cash outflow from operations plus cash flow from investing activities) was an inflow of $164 million.
2007 Cash Flow and Earnings Estimates
On December 13, 2006, Dynegy provided cash flow and earnings estimates for 2007. Those estimates were based on quoted forward commodity price curves as of November 1, 2006. In connection with today’s announcement, Dynegy is updating its 2007 estimates to reflect quoted forward commodity price curves as of January 30, 2007. The new estimates also reflect assumptions regarding, among other things, sales volumes, fuel costs and other operational activities.
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The 2007 estimates also continue to reflect the assumption that the proposed combination with LS Power will be completed at the end of the first quarter 2007. As such, the estimates reflect 12 months of financial contributions from Dynegy and nine months of financial contributions from LS Power.
The current 2007 estimates include an anticipated range of operating cash flow between $500 million and $600 million and a range of free cash flow between $315 million and $415 million. Previously, the range of 2007 operating cash flow was between $600 million and $700 million, with a range of free cash flow between $415 million and $515 million. The reduction in 2007 operating cash flow estimates resulted from a change in the timing of approximately $100 million of 2007 forward sales receipts, which were recognized in 2006, and a 2006 interest payment that occurred in 2007. The company’s estimate for 2007 EBITDA has not changed from the range of $1.02 billion to $1.13 billion.
Investor Conference Call/Web Cast
Dynegy will discuss its 2006 results during an investor conference call and web cast today at 9 a.m. ET/8 a.m. CT. Participants may access the web cast and the related presentation materials on the “News & Financials” 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 current power generation portfolio consists of approximately 12,000 megawatts of baseload, intermediate and peaking power plants fueled by a mix of coal, fuel oil and natural gas.
On September 15, 2006, Dynegy announced a proposed combination with LS Power that is expected to result in a combined entity with approximately 20,000 megawatts of generation capacity and a strong presence in the Midwest, the Northeast and the West Coast. The transaction, which remains subject to shareholder approval, is targeted for completion in early 2007.
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,
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particularly the statements concerning Dynegy’s proposed combination with LS Power, including the anticipated benefits of the proposed combination, expected synergies and anticipated future financial operating performance and results; and statements concerning Dynegy’s commercial sales strategy, future growth opportunities, and estimated financial results for 2007. 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.
Some of the key factors that could cause actual results to vary materially from those estimated, expected or implied include: changes in commodity prices, particularly for power and natural gas; the effects of competition and weather on the demand for Dynegy’s products and services; the impact of Dynegy’s commercial strategy; the availability, ability to consummate, and effects of growth opportunities for Dynegy’s power generation business; obtaining shareholder approval required for the LS Power combination; the ability to integrate the operations of Dynegy and LS Power; the condition of the capital markets generally and Dynegy’s ability to access the capital markets as and when needed; operational factors affecting Dynegy’s assets, including safety efforts, scheduled maintenance and blackouts or other unscheduled outages; Dynegy’s ability to transport and maintain fuel inventories, including coal and fuel oil; Dynegy’s ability to fund the projects mandated by the Baldwin consent decree; uncertainties regarding environmental regulations, litigation and other legal or regulatory developments affecting Dynegy’s businesses; and Dynegy’s ability to successfully complete its exit from the Customer Risk Management business and fund the costs associated with this exit. 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 Dec. 31, 2005, as amended, its Quarterly Reports on Form 10-Q for the quarters ended March 31, 2006, June 30, 2006 and September 30, 2006, and its Current Reports, which are available free of charge on the SEC’s web site at 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.
WHERE YOU CAN FIND MORE INFORMATION
Dynegy and Dynegy Acquisition, Inc. have filed a proxy statement/prospectus with the SEC in connection with the previously announced proposed merger with LS Power. Investors and security holders are urged to carefully read the important information contained in the materials regarding the proposed transaction. Investors and security holders may obtain a copy of the proxy statement/prospectus and other relevant documents, free of charge, at the SEC’s web site atwww.sec.gov, and on Dynegy’s web site atwww.dynegy.com. The materials may also be obtained by writing Dynegy Inc. Investor Relations, 1000 Louisiana Street, Suite 5800, Houston, Texas 77002 or by calling 713-507-6466.
Dynegy, LS Power and their respective directors, executive officers, partners and other members of management and employees may be deemed to be participants in the solicitation of proxies from Dynegy’s shareholders with respect to the proposed transaction. Information regarding Dynegy’s directors and executive officers is available in the company’s proxy statement for its 2006 Annual Meeting of Shareholders, dated April 3, 2006. Additional information regarding the interests of such potential participants is included in the proxy statement/prospectus and other relevant documents filed with the SEC as they become available. DYNC
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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, | |||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
Revenues | $ | 397 | $ | 622 | $ | 2,017 | $ | 2,313 | ||||||||
Cost of sales, exclusive of depreciation and amortization shown separately below | (284 | ) | (934 | ) | (1,387 | ) | (2,416 | ) | ||||||||
Depreciation and amortization expense | (56 | ) | (55 | ) | (230 | ) | (220 | ) | ||||||||
Impairment and other charges | (48 | ) | (40 | ) | (155 | ) | (46 | ) | ||||||||
Gain (loss) on sale of assets, net | — | — | 3 | (1 | ) | |||||||||||
General and administrative expenses | (36 | ) | (47 | ) | (196 | ) | (468 | ) | ||||||||
Operating income (loss) | (27 | ) | (454 | ) | 52 | (838 | ) | |||||||||
Earnings (losses) from unconsolidated investments | (7 | ) | (12 | ) | (1 | ) | 2 | |||||||||
Interest expense | (72 | ) | (105 | ) | (382 | ) | (389 | ) | ||||||||
Debt conversion costs | — | — | (249 | ) | — | |||||||||||
Other income and expense, net | 13 | 17 | 54 | 26 | ||||||||||||
Loss from continuing operations before income taxes | (93 | ) | (554 | ) | (526 | ) | (1,199 | ) | ||||||||
Income tax benefit | 14 | 167 | 168 | 395 | ||||||||||||
Loss from continuing operations | (79 | ) | (387 | ) | (358 | ) | (804 | ) | ||||||||
Income from discontinued operations, net of tax | 21 | 690 | 24 | 899 | ||||||||||||
Cumulative effect of change in accounting principles, net of tax | — | (5 | ) | 1 | (5 | ) | ||||||||||
Net income (loss) | $ | (58 | ) | $ | 298 | $ | (333 | ) | $ | 90 | ||||||
Less: Preferred stock dividends | — | 5 | 9 | 22 | ||||||||||||
Net income (loss) applicable to common stockholders | $ | (58 | ) | $ | 293 | $ | (342 | ) | $ | 68 | ||||||
Earnings before interest, taxes, and depreciation and amortization (EBITDA) (1) | $ | 57 | $ | 714 | $ | 366 | $ | 750 | ||||||||
Basic earnings (loss) per share: | ||||||||||||||||
Loss from continuing operations (2) | $ | (0.16 | ) | $ | (0.98 | ) | $ | (0.80 | ) | $ | (2.13 | ) | ||||
Income from discontinued operations | 0.04 | 1.73 | 0.05 | 2.32 | ||||||||||||
Cumulative effect of change in accounting principles | — | (0.01 | ) | — | (0.01 | ) | ||||||||||
Basic earnings (loss) per share | $ | (0.12 | ) | $ | 0.74 | $ | (0.75 | ) | $ | 0.18 | ||||||
Diluted earnings (loss) per share: | ||||||||||||||||
Loss from continuing operations (2) | $ | (0.16 | ) | $ | (0.98 | ) | $ | (0.80 | ) | $ | (2.13 | ) | ||||
Income from discontinued operations | 0.04 | 1.73 | 0.05 | 2.32 | ||||||||||||
Cumulative effect of change in accounting principles | — | (0.01 | ) | — | (0.01 | ) | ||||||||||
Diluted earnings (loss) per share | $ | (0.12 | ) | $ | 0.74 | $ | (0.75 | ) | $ | 0.18 | ||||||
Basic shares outstanding | 495 | 398 | 459 | 387 | ||||||||||||
Diluted shares outstanding | 497 | 524 | 509 | 513 | ||||||||||||
| (1) | EBITDA is a non-GAAP financial measure. Consolidated EBITDA can be reconciled to Net income (loss) using the following calculation: Net income (loss) less Income tax benefit, plus Interest expense and Depreciation and amortization expense. 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 (loss) and Net income (loss) for the periods presented is included below. |
| (2) | See “Reported Unaudited Basic and Diluted Loss Per Share From Continuing Operations” for a reconciliation of basic loss per share from continuing operations to diluted loss per share from continuing operations. |
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
Operating income (loss) | $ | (27 | ) | $ | (454 | ) | $ | 52 | $ | (838 | ) | |||||
Add: Depreciation and amortization expense, a component of operating income (loss) | 56 | 55 | 230 | 220 | ||||||||||||
Earnings (losses) from unconsolidated investments | (7 | ) | (12 | ) | (1 | ) | 2 | |||||||||
Other income and expense, net | 13 | 17 | 54 | 26 | ||||||||||||
EBITDA from discontinued operations (3) | 22 | 1,115 | 30 | 1,347 | ||||||||||||
Cumulative effect of change in accounting principles, pre-tax | — | (7 | ) | 1 | (7 | ) | ||||||||||
Earnings before interest, taxes, and depreciation and amortization (EBITDA) | 57 | 714 | 366 | 750 | ||||||||||||
Depreciation and amortization expense, a component of operating income (loss) | (56 | ) | (55 | ) | (230 | ) | (220 | ) | ||||||||
Depreciation and amortization expense from discontinued operations | — | (1 | ) | — | (38 | ) | ||||||||||
Interest expense and debt conversion costs from continuing operations | (72 | ) | (105 | ) | (631 | ) | (389 | ) | ||||||||
Interest expense from discontinued operations | — | (13 | ) | — | (53 | ) | ||||||||||
Income tax benefit from continuing operations | 14 | 167 | 168 | 395 | ||||||||||||
Income tax expense from discontinued operations | (1 | ) | (411 | ) | (6 | ) | (357 | ) | ||||||||
Income tax benefit on cumulative effect of change in accounting principles | — | 2 | — | 2 | ||||||||||||
Net income (loss) | $ | (58 | ) | $ | 298 | $ | (333 | ) | $ | 90 | ||||||
| (3) | A reconciliation of EBITDA from discontinued operations to Income from discontinued operations, net of tax for the periods presented, is included below. |
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
EBITDA from discontinued operations | $ | 22 | $ | 1,115 | $ | 30 | $ | 1,347 | ||||||||
Depreciation and amortization expense from discontinued operations | — | (1 | ) | — | (38 | ) | ||||||||||
Interest expense from discontinued operations | — | (13 | ) | — | (53 | ) | ||||||||||
Income tax expense from discontinued operations | (1 | ) | (411 | ) | (6 | ) | (357 | ) | ||||||||
Income from discontinued operations, net of tax | $ | 21 | $ | 690 | $ | 24 | $ | 899 | ||||||||
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DYNEGY INC.
REPORTED UNAUDITED BASIC AND DILUTED LOSS PER SHARE FROM CONTINUING OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE DATA)
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
Loss from continuing operations | $ | (79 | ) | $ | (387 | ) | $ | (358 | ) | $ | (804 | ) | ||||
Less: convertible preferred stock dividends | — | 5 | 9 | 22 | ||||||||||||
Loss from continuing operations for basic loss per share | (79 | ) | (392 | ) | (367 | ) | (826 | ) | ||||||||
Effect of dilutive securities: | ||||||||||||||||
Interest on convertible subordinated debentures | — | 2 | 3 | 7 | ||||||||||||
Dividends on Series C convertible preferred stock | — | 5 | 9 | 22 | ||||||||||||
Loss from continuing operations for diluted loss per share | $ | (79 | ) | $ | (385 | ) | $ | (355 | ) | $ | (797 | ) | ||||
Basic weighted-average shares | 495 | 398 | 459 | 387 | ||||||||||||
Effect of dilutive securities: | ||||||||||||||||
Stock options and restricted stock | 2 | 2 | 2 | 2 | ||||||||||||
Convertible subordinated debentures | — | 55 | 20 | 55 | ||||||||||||
Series C convertible preferred stock | — | 69 | 28 | 69 | ||||||||||||
Diluted weighted-average shares | 497 | 524 | 509 | 513 | ||||||||||||
Loss per share from continuing operations: | ||||||||||||||||
Basic | $ | (0.16 | ) | $ | (0.98 | ) | $ | (0.80 | ) | $ | (2.13 | ) | ||||
Diluted (1) | $ | (0.16 | ) | $ | (0.98 | ) | $ | (0.80 | ) | $ | (2.13 | ) | ||||
| (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 and twelve months ended December 31, 2006 and 2005. |
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DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
(UNAUDITED) (IN MILLIONS)
| Three Months Ended December 31, 2006 | ||||||||||||||||||||||||
| Power Generation | ||||||||||||||||||||||||
| GEN-MW | GEN-NE | GEN-SO | CRM | OTHER | Total | |||||||||||||||||||
Generation | $ | 49 | $ | (4 | ) | $ | (40 | ) | $ | — | $ | — | $ | 5 | ||||||||||
Customer Risk Management | — | — | — | 10 | — | 10 | ||||||||||||||||||
Other | — | — | — | — | (42 | ) | (42 | ) | ||||||||||||||||
Operating income (loss) | 49 | (4 | ) | (40 | ) | 10 | (42 | ) | (27 | ) | ||||||||||||||
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 | 6 | 5 | — | 3 | 56 | ||||||||||||||||||
EBITDA from continuing operations (1) | 92 | 5 | (42 | ) | 13 | (33 | ) | 35 | ||||||||||||||||
EBITDA from discontinued operations, pre-tax (2) | — | — | — | 18 | 4 | 22 | ||||||||||||||||||
EBITDA (1) | $ | 92 | $ | 5 | $ | (42 | ) | $ | 31 | $ | (29 | ) | $ | 57 | ||||||||||
Depreciation and amortization expense | (56 | ) | ||||||||||||||||||||||
Interest expense and debt conversion costs | (72 | ) | ||||||||||||||||||||||
Pre-tax loss | (71 | ) | ||||||||||||||||||||||
Income tax benefit | 13 | |||||||||||||||||||||||
Net loss | $ | (58 | ) | |||||||||||||||||||||
| Three Months Ended December 31, 2005 | ||||||||||||||||||||||||
| Power Generation | ||||||||||||||||||||||||
| GEN-MW | GEN-NE | GEN-SO | CRM | OTHER | Total | |||||||||||||||||||
Generation | $ | 40 | $ | (16 | ) | $ | (16 | ) | $ | — | $ | — | $ | 8 | ||||||||||
Customer Risk Management | — | — | — | (422 | ) | — | (422 | ) | ||||||||||||||||
Other | — | — | — | — | (40 | ) | (40 | ) | ||||||||||||||||
Operating income (loss) | 40 | (16 | ) | (16 | ) | (422 | ) | (40 | ) | (454 | ) | |||||||||||||
Losses from unconsolidated investments | — | — | (12 | ) | — | — | (12 | ) | ||||||||||||||||
Other items, net | — | 2 | — | 5 | 10 | 17 | ||||||||||||||||||
Cumulative effect of change in accounting principle, pre-tax | (5 | ) | (2 | ) | — | — | — | (7 | ) | |||||||||||||||
Add: Depreciation and amortization expense, a component of operating income (loss) | 40 | 5 | 6 | — | 4 | 55 | ||||||||||||||||||
EBITDA from continuing operations (1) | 75 | (11 | ) | (22 | ) | (417 | ) | (26 | ) | (401 | ) | |||||||||||||
EBITDA from discontinued operations, pre-tax (2) | — | — | — | 3 | 1,112 | 1,115 | ||||||||||||||||||
EBITDA (1) | $ | 75 | $ | (11 | ) | $ | (22 | ) | $ | (414 | ) | $ | 1,086 | $ | 714 | |||||||||
Depreciation and amortization expense | (56 | ) | ||||||||||||||||||||||
Interest expense | (118 | ) | ||||||||||||||||||||||
Pre-tax income | 540 | |||||||||||||||||||||||
Income tax expense | (242 | ) | ||||||||||||||||||||||
Net income | $ | 298 | ||||||||||||||||||||||
| (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) less Income tax benefit, plus Interest expense and Depreciation and amortization expense. 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. |
| (2) | See Note (3) to “Reported Unaudited Condensed Consolidated Statements of Operations.” |
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DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
(UNAUDITED) (IN MILLIONS)
| Twelve Months Ended December 31, 2006 | ||||||||||||||||||||||||
| Power Generation | ||||||||||||||||||||||||
| GEN-MW | GEN-NE | GEN-SO | CRM | OTHER | Total | |||||||||||||||||||
Generation | $ | 208 | $ | 55 | $ | (55 | ) | $ | — | $ | — | $ | 208 | |||||||||||
Customer Risk Management | — | — | — | 7 | — | 7 | ||||||||||||||||||
Other | — | — | — | — | (163 | ) | (163 | ) | ||||||||||||||||
Operating income (loss) | 208 | 55 | (55 | ) | 7 | (163 | ) | 52 | ||||||||||||||||
Losses from unconsolidated investments | — | — | (1 | ) | — | — | (1 | ) | ||||||||||||||||
Other items, net | 2 | 9 | 1 | 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 | 24 | 21 | — | 17 | 230 | ||||||||||||||||||
EBITDA from continuing operations (1) | 378 | 88 | (34 | ) | 11 | (107 | ) | 336 | ||||||||||||||||
EBITDA from discontinued operations, pre-tax (2) | — | — | — | 23 | 7 | 30 | ||||||||||||||||||
EBITDA (1) | $ | 378 | $ | 88 | $ | (34 | ) | $ | 34 | $ | (100 | ) | $ | 366 | ||||||||||
Depreciation and amortization expense | (230 | ) | ||||||||||||||||||||||
Interest expense and debt conversion costs | (631 | ) | ||||||||||||||||||||||
Pre-tax loss | (495 | ) | ||||||||||||||||||||||
Income tax benefit | 162 | |||||||||||||||||||||||
Net loss | $ | (333 | ) | |||||||||||||||||||||
| Twelve Months Ended December 31, 2005 | ||||||||||||||||||||||||
| Power Generation | ||||||||||||||||||||||||
| GEN-MW | GEN-NE | GEN-SO | CRM | OTHER | Total | |||||||||||||||||||
Generation | $ | 194 | $ | 29 | $ | (21 | ) | $ | — | $ | — | $ | 202 | |||||||||||
Customer Risk Management | — | — | — | (647 | ) | — | (647 | ) | ||||||||||||||||
Other | — | — | — | — | (393 | ) | (393 | ) | ||||||||||||||||
Operating income (loss) | 194 | 29 | (21 | ) | (647 | ) | (393 | ) | (838 | ) | ||||||||||||||
Earnings (losses) from unconsolidated investments | 7 | — | (5 | ) | — | — | 2 | |||||||||||||||||
Other items, net | 2 | 5 | (1 | ) | — | 20 | 26 | |||||||||||||||||
Cumulative effect of change in accounting principle, pre-tax | (5 | ) | (2 | ) | — | — | — | (7 | ) | |||||||||||||||
Add: Depreciation and amortization expense, a component of operating income (loss) | 157 | 21 | 23 | 1 | 18 | 220 | ||||||||||||||||||
EBITDA from continuing operations (1) | 355 | 53 | (4 | ) | (646 | ) | (355 | ) | (597 | ) | ||||||||||||||
EBITDA from discontinued operations, pre-tax (2) | — | — | — | 6 | 1,341 | 1,347 | ||||||||||||||||||
EBITDA (1) | $ | 355 | $ | 53 | $ | (4 | ) | $ | (640 | ) | $ | 986 | $ | 750 | ||||||||||
Depreciation and amortization expense | (258 | ) | ||||||||||||||||||||||
Interest expense | (442 | ) | ||||||||||||||||||||||
Pre-tax income | 50 | |||||||||||||||||||||||
Income tax benefit | 40 | |||||||||||||||||||||||
Net income | $ | 90 | ||||||||||||||||||||||
| (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) less Income tax benefit, plus Interest expense and Depreciation and amortization expense. 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. |
| (2) | See Note (3) to “Reported Unaudited Condensed Consolidated Statements of Operations.” |
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DYNEGY INC.
SIGNIFICANT ITEMS
(UNAUDITED) (IN MILLIONS)
| Three Months Ended December 31, 2006 | |||||||||||||||||||||||
| Power Generation | |||||||||||||||||||||||
| GEN-MW | GEN-NE | GEN-SO | CRM | OTHER | Total | ||||||||||||||||||
Asset impairments (1) | $ | (14 | ) | $ | — | $ | (36 | ) | $ | — | $ | — | $ | (50 | ) | ||||||||
Taxes (2) | — | — | — | — | (29 | ) | (29 | ) | |||||||||||||||
Discontinued operations (3) | — | — | — | 18 | 4 | 22 | |||||||||||||||||
Total | $ | (14 | ) | $ | — | $ | (36 | ) | $ | 18 | $ | (25 | ) | $ | (57 | ) | |||||||
| Three Months Ended December 31, 2005 | |||||||||||||||||||||||
| Power Generation | |||||||||||||||||||||||
| GEN-MW | GEN-NE | GEN-SO | CRM | OTHER | Total | ||||||||||||||||||
Sterlington toll settlement charge (4) | $ | — | $ | — | $ | — | $ | (364 | ) | $ | — | $ | (364 | ) | |||||||||
Asset impairment (5) | (29 | ) | — | — | — | — | (29 | ) | |||||||||||||||
Impairment of generation investments (6) | — | — | (19 | ) | — | — | (19 | ) | |||||||||||||||
Restructuring charges (7) | — | — | — | — | (11 | ) | (11 | ) | |||||||||||||||
Legal and settlement charges (8) | — | — | — | (9 | ) | — | (9 | ) | |||||||||||||||
Taxes (9) | — | — | — | — | (23 | ) | (23 | ) | |||||||||||||||
Discontinued operations (10) | — | — | — | 3 | 1,098 | 1,101 | |||||||||||||||||
Total | $ | (29 | ) | $ | — | $ | (19 | ) | $ | (370 | ) | $ | 1,064 | $ | 646 | ||||||||
| (1) | We recognized a cumulative pre-tax charge of approximately $50 million ($32 million after-tax) related to the impairments of our Bluegrass and Calcasieu gas-fired peaking facilities. The Bluegrass impairment of $14 million ($9 million after-tax) and the Calcasieu impairment of $36 million ($23 million after-tax) were due to management’s conclusion that it was more likely than not that these assets would be sold prior to the end of their previously estimated useful lives. These charges are included in Impairment and other charges on our Reported Unaudited Condensed Consolidated Statements of Operations. |
| (2) | We recognized an income tax expense of approximately $29 million resulting from Canadian authorities’ audit of prior year income tax returns. This tax expense is included in the $14 million Income tax benefit on our Reported Unaudited Condensed Consolidated Statements of Operations. |
| (3) | We recognized pre-tax income of approximately $22 million ($21 million after-tax) related to discontinued operations. The income is primarily associated with a receivable previously reserved that is now expected to be collected. |
| (4) | We recognized a pre-tax charge of approximately $364 million ($229 million after-tax) related to the Sterlington toll settlement. This charge is included in Cost of sales on our Reported Unaudited Condensed Consolidated Statements of Operations. |
| (5) | We recognized a pre-tax charge of approximately $29 million ($18 million after-tax) related to the impairment of a gas turbine, which was sold in 2006. This charge is included in Impairment and other charges on our Reported Unaudited Condensed Consolidated Statements of Operations. |
| (6) | We recognized a pre-tax charge of approximately $19 million ($12 million after-tax) related to the impairment of our investments in Black Mountain, West Coast Power and Chorrera, a joint venture located in Panama. This charge is included in Earnings (losses) from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations. |
| (7) | We recognized a pre-tax charge of approximately $11 million ($7 million after-tax) related to restructuring charges in connection with a reduction in workforce. This charge is included in Impairment and other charges on our Reported Unaudited Condensed Consolidated Statements of Operations. |
| (8) | We recognized a pre-tax charge of approximately $9 million ($6 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. |
| (9) | We recognized a net income tax expense of approximately $23 million related to an increase in the deferred tax valuation allowance. An expense of $32 million is included in Income tax benefit, partially offset by a $9 million benefit included in the $690 million after-tax Income from discontinued operations. |
| (10) | We recognized pre-tax income of approximately $1,101 million ($690 million after-tax) related to discontinued operations. The income consists primarily of $1,098 million associated with our NGL segment, which was reclassified to discontinued operations due to the sale of DMSLP. Included in the $1,098 million is a pre-tax gain of approximately $1,087 million ($675 million after-tax) on the sale of DMSLP. |
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DYNEGY INC.
SIGNIFICANT ITEMS
(UNAUDITED) (IN MILLIONS)
| Twelve Months Ended December 31, 2006 | ||||||||||||||||||||||||
| Power Generation | ||||||||||||||||||||||||
| GEN-MW | GEN-NE | GEN-SO | CRM | OTHER | Total | |||||||||||||||||||
Debt conversion costs (1) | $ | — | $ | — | $ | — | $ | — | $ | (249 | ) | $ | (249 | ) | ||||||||||
Asset impairments (2) | (110 | ) | — | (45 | ) | — | — | (155 | ) | |||||||||||||||
Legal and settlement charges (3) | — | — | — | (53 | ) | — | (53 | ) | ||||||||||||||||
Sithe Subordinated Debt exchange charge (4) | — | (36 | ) | — | — | — | (36 | ) | ||||||||||||||||
Acceleration of financing costs (5) | — | — | — | — | (36 | ) | (36 | ) | ||||||||||||||||
Taxes (6) | — | — | — | — | (29 | ) | (29 | ) | ||||||||||||||||
Discontinued operations (7) | — | — | — | 23 | 7 | 30 | ||||||||||||||||||
Total | $ | (110 | ) | $ | (36 | ) | $ | (45 | ) | $ | (30 | ) | $ | (307 | ) | $ | (528 | ) | ||||||
| Twelve Months Ended December 31, 2005 | ||||||||||||||||||||||||
| Power Generation | ||||||||||||||||||||||||
| GEN-MW | GEN-NE | GEN-SO | CRM | OTHER | Total | |||||||||||||||||||
Sterlington toll settlement charge (8) | $ | — | $ | — | $ | — | $ | (364 | ) | $ | — | $ | (364 | ) | ||||||||||
Legal and settlement charges (9) | — | — | — | (38 | ) | (249 | ) | (287 | ) | |||||||||||||||
Independence toll settlement charge (10) | — | — | — | (169 | ) | — | (169 | ) | ||||||||||||||||
Asset impairment (11) | (29 | ) | — | — | — | — | (29 | ) | ||||||||||||||||
Impairment of generation investments (12) | — | — | (27 | ) | — | — | (27 | ) | ||||||||||||||||
Restructuring charges (13) | — | — | — | — | (11 | ) | (11 | ) | ||||||||||||||||
Taxes (14) | — | — | — | — | 89 | 89 | ||||||||||||||||||
Discontinued operations (15) | — | — | — | 6 | 1,250 | 1,256 | ||||||||||||||||||
Total | $ | (29 | ) | $ | — | $ | (27 | ) | $ | (565 | ) | $ | 1,079 | $ | 458 | |||||||||
| (1) | 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 billion 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. |
| (2) | We recognized a cumulative pre-tax charge of approximately $155 million ($99 million after-tax) related to the impairments of our Bluegrass, Calcasieu and Rockingham 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) and the Calcasieu impairment of $36 million ($23 million after-tax) recorded in the fourth quarter 2006 were due to management's conclusion that it was more likely than not that these assets would be sold prior to the end of their previously estimated useful lives. 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. |
| (3) | 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. |
| (4) | 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. |
| (5) | We recognized pre-tax charges totaling 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), payment of the $150 million term loan required as a result of the sale of the Rockingham facility, 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. |
| (6) | We recognized an income tax expense of approximately $29 million resulting from Canadian authorities' audit of prior year income tax returns. This tax expense is included in the $168 million Income tax benefit on our Reported Unaudited Condensed Consolidated Statements of Operations. |
| (7) | We recognized pre-tax income of approximately $30 million ($24 million after-tax) related to discontinued operations. The income is primarily associated with a receivable previously reserved that is now expected to be collected. |
| (8) | We recognized a pre-tax charge of approximately $364 million ($229 million after-tax) related to the Sterlington toll settlement. This charge is included in Cost of sales on our Reported Unaudited Condensed Consolidated Statements of Operations. |
| (9) | We recognized a pre-tax charge of approximately $287 million ($197 million after-tax) primarily related to the settlement of our class action shareholder lawsuit and other legal and settlement charges. This charge is included in General and administrative expense on our Reported Unaudited Condensed Consolidated Statements of Operations. |
| (10) | We recognized a pre-tax charge of approximately $169 million ($109 million after-tax) related to the Independence toll restructuring charge following our acquisition of ExRes SHC, Inc., the parent company of Sithe Energies, Inc. and Sithe / Independence Power Partners, L.P. This charge is included in Cost of sales on our Reported Unaudited Condensed Consolidated Statements of Operations. |
| (11) | We recognized a pre-tax charge of approximately $29 million ($18 million after-tax) related to the impairment of a gas turbine, which was sold in 2006. This charge is included in Impairment and other charges on our Reported Unaudited Condensed Consolidated Statements of Operations. |
| (12) | We recognized a pre-tax charge of approximately $27 million ($17 million after-tax) related to the impairment of our investments in Black Mountain, West Coast Power and Chorrera, a joint venture located in Panama. This charge is included in Earnings (losses) from unconsolidated investments on our Reported Unaudited Condensed Consolidated Statements of Operations. |
| (13) | We recognized a pre-tax charge of approximately $11 million ($7 million after-tax) related to restructuring charges in connection with a reduction in workforce. This charge is included in Impairment and other charges on our Reported Unaudited Condensed Consolidated Statements of Operations. |
| (14) | We recognized a net income tax benefit of approximately $89 million primarily for the reversal of a deferred tax capital loss valuation allowance related to gains on the anticipated sale of DMSLP. A benefit of $121 million is included in the $899 million after-tax Income from discontinued operations, partially offset by a $32 million charge in Income tax benefit. |
| (15) | We recognized pre-tax income of approximately $1,256 million ($899 million after-tax) related to discontinued operations. The income consists primarily of $1,250 million associated with our NGL segment, which was reclassified to discontinued operations due to the sale of DMSLP, and $6 million pre-tax income on our UK CRM business. Included in the $1,250 million of income from our NGL segment are a pre-tax gains of approximately $1,087 million ($675 million after-tax) on the sale of DMSLP and $10 million ($7 million after-tax) on the sale of the Port Everglades property. |
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DYNEGY INC.
SUMMARY CASH FLOW INFORMATION
(UNAUDITED) (IN MILLIONS)
| Twelve Months Ended December 31, 2006 | ||||||||||||||||
| GEN (1) | CRM | OTHER | Total | |||||||||||||
Cash Flow from Operations | $ | 698 | $ | (461 | ) | $ | (431 | ) | $ | (194 | ) | |||||
Capital Expenditures | (147 | ) | — | (8 | ) | (155 | ) | |||||||||
Business Acquisition Costs | (40 | ) | — | (8 | ) | (48 | ) | |||||||||
Proceeds from Asset Sales (2) | 416 | — | 16 | 432 | ||||||||||||
Restricted Cash and Other (3) | (3 | ) | — | 132 | 129 | |||||||||||
Free Cash Flow (4) | $ | 924 | $ | (461 | ) | $ | (299 | ) | $ | 164 | ||||||
| Twelve Months Ended December 31, 2005 | ||||||||||||||||
| GEN (1) | CRM | OTHER | Total | |||||||||||||
Cash Flow from Operations | $ | 472 | $ | (21 | ) | $ | (481 | ) | $ | (30 | ) | |||||
Capital Expenditures | (143 | ) | — | (52 | ) | (195 | ) | |||||||||
Business Acquisition Costs | (120 | ) | — | — | (120 | ) | ||||||||||
Proceeds from Asset Sales (5) | 1 | — | 2,487 | 2,488 | ||||||||||||
Restricted Cash and Other (6) | (14 | ) | — | (335 | ) | (349 | ) | |||||||||
Free Cash Flow (4) | $ | 196 | $ | (21 | ) | $ | 1,619 | $ | 1,794 | |||||||
| (1) | Beginning in the fourth quarter 2005, we report the results of our power generation business as three separate segments in our unaudited condensed consolidated financial statements: (1) the Midwest segment (GEN-MW); (2) the Northeast segment (GEN-NE); and (3) the South segment (GEN-SO). For the purpose of this schedule, GEN includes the three combined segments. |
| (2) | Primarily represents proceeds of $205 million from the sale of West Coast Power, $194 million from the sale of the Rockingham facility, $15 million related to the sale of DMSLP and $14 million for the sale of a gas turbine no longer in use. |
| (3) | Restricted cash and other primarily relates to the $335 million return of cash collateral posted for the October 2005 letter of credit facility, offset by $200 million posted for a new letter of credit facility in second quarter 2006. |
| (4) | 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 plus investing cash flow (consisting of asset sale proceeds less business acquisition costs, capital expenditures and changes in restricted cash) 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 by segment for the periods presented is included above. |
| (5) | During the fourth quarter 2005, we received proceeds of approximately $2,382 million from the sale of DMSLP and approximately $10 million in the third quarter for sale of the Port Everglades property. Also, during the first quarter 2005, we paid approximately $5 million to Ameren related to the working capital adjustment for our sale of Illinois Power. |
| (6) | Restricted cash and other primarily relates to an increase in restricted cash associated with the $335 million cash collateral posted for the Amended and Restated Credit Facility. |
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16
DYNEGY INC.
OPERATING DATA
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||
GEN-MW | ||||||||||||
Million Megawatt Hours Generated—Gross and Net | 5.4 | 5.1 | 21.5 | 21.9 | ||||||||
Average Actual On-Peak Market Power Prices ($/MWh)(1): | ||||||||||||
Cinergy (Cin Hub) | $ | 47 | $ | 71 | $ | 52 | $ | 64 | ||||
Commonwealth Edison (NI Hub) | $ | 48 | $ | 71 | $ | 52 | $ | 62 | ||||
GEN-NE | ||||||||||||
Million Megawatt Hours Generated—Gross and Net | 0.8 | 1.5 | 4.4 | 8.3 | ||||||||
Average Actual On-Peak Market Power Prices ($/MWh)(1): | ||||||||||||
New York—Zone G | $ | 70 | $ | 111 | $ | 76 | $ | 92 | ||||
New York—Zone A | $ | 54 | $ | 93 | $ | 59 | $ | 76 | ||||
GEN-SO | ||||||||||||
Million Megawatt Hours Generated—Gross | 0.9 | 1.7 | 4.6 | 7.3 | ||||||||
Million Megawatt Hours Generated—Net | 0.8 | 1.2 | 3.9 | 5.3 | ||||||||
Average Actual On-Peak Market Power Prices ($/MWh)(1): | ||||||||||||
Southern | $ | 49 | $ | 87 | $ | 55 | $ | 71 | ||||
ERCOT | $ | 54 | $ | 93 | $ | 63 | $ | 80 | ||||
Average Natural Gas Price—Henry Hub ($/MMBtu) (2) | $ | 6.60 | $ | 12.21 | $ | 6.74 | $ | 8.80 | ||||
| (1) | Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices realized by the Company. |
| (2) | 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.
2007 EARNINGS ESTIMATES (1)
(IN MILLIONS)
| GEN-MW | GEN-West | GEN-NE | Total GEN | OTHER | Total | |||||||||||||||||||
EBITDA (2) | $ | 745-795 | $ | 215-235 | $ | 175-205 | $ | 1,135-1,235 | $ | (115-105 | ) | $ | 1,020-1,130 | |||||||||||
Depreciation and Amortization | (180 | ) | (45 | ) | (40 | ) | (265 | ) | (15 | ) | (280 | ) | ||||||||||||
Interest Expense | (435 | ) | ||||||||||||||||||||||
Income Tax Expense | (115-160 | ) | ||||||||||||||||||||||
Net Income | $ | 190-255 | ||||||||||||||||||||||
| 2007 CASH FLOW ESTIMATES (1) | ||||||||||||||||||||||||
| (IN MILLIONS) | ||||||||||||||||||||||||
| GEN | OTHER | Total | Less: Non-Core (4) | Total Core Business | ||||||||||||||||||||
Cash Flow from Operations | $ | 1,090-1,180 | $ | (590-580 | ) | $ | 500-600 | $ | — | $ | 500-600 | |||||||||||||
Capital Expenditures | (400 | ) | (25 | ) | (425 | ) | — | (425 | ) | |||||||||||||||
Proceeds from Asset Sales and Acquisition Costs, Net | 200 | (145 | ) | 55 | 55 | — | ||||||||||||||||||
Changes in Restricted Cash | 155 | 30 | 185 | — | 185 | |||||||||||||||||||
Free Cash Flow (3) | $ | 1,045-1,135 | $ | (730-720 | ) | $ | 315-415 | $ | 55 | $ | 260-360 | |||||||||||||
| (1) | 2007 estimates are presented on a GAAP basis, are based on quoted forward commodity price curves as of January 30, 2007 and assume closing of the LS Power transaction at the end of the first quarter 2007, excluding purchase accounting adjustments. 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 2007 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. |
| (2) | EBITDA is a non-GAAP financial measure. Consolidated EBITDA can be reconciled to Net income using the following calculation: Net income plus Income tax expense, Interest expense and Depreciation and amortization expense. 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. |
| (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 plus investing cash flow (consisting of asset sale proceeds less business acquisition costs, capital expenditures and changes in restricted cash) 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 by segment for the periods presented is included above. |
| (4) | The following summarizes the items included in Non-core business in our cash flow estimate. |
| Cash Flow from Operations | Capital Expenditures | Proceeds from Asset Sales and Acquisition Costs, Net | Changes in Restricted Cash | Free Cash Flow | |||||||||||||
Acquisition Costs (OTHER) | $ | — | $ | — | $ | (145 | ) | $ | — | $ | (145 | ) | |||||
Proceeds from Asset Sales (GEN) | — | — | 200 | — | 200 | ||||||||||||
Total | $ | — | $ | — | $ | 55 | $ | — | $ | 55 | |||||||
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