EXHIBIT 99.1
Feb. 24, 2005
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| Media: | | John Sousa or David Byford |
| | | (713) 767-5800 |
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| Analysts: | | Peter Wilt, Norelle Lundy or Hillarie Bloxom |
| | | (713) 507-6466 |
DYNEGY ANNOUNCES FOURTH QUARTER AND YEAR-END 2004 RESULTS
| | • | | Natural Gas Liquids benefited from favorable commodity prices and fractionation spreads |
| | • | | Power Generation maintained solid year-over-year production levels |
| | • | | Strong operational results offset by fourth quarter charges related to power tolling restructuring and additional legal and settlement charges |
| | • | | Continued self-restructuring highlights include: |
| | • | | Year-end debt and other obligations target of $5.5 billion achieved |
| | • | | Significant progress in restructuring power tolling arrangements |
| | • | | Sale of regulated business and other non-core assets |
| | • | | Extension of bank credit facilities |
| | • | | Year-end liquidity was $1.2 billion |
HOUSTON (Feb. 24, 2005)– Dynegy Inc. (NYSE: DYN) today reported a net loss applicable to common shareholders of $37 million or $(0.10) per diluted share for 2004, which includes a net loss of $176 million for the fourth quarter 2004.
Net income applicable to common shareholders of $321 million, or $0.78 per diluted share, for 2003 included a $1 billion gain on preferred stock dividends related to the restructuring of the company’s Series B preferred stock.
Results for 2004 would have been in line with guidance estimates had the company not accrued an additional after-tax fourth quarter charge of $36 million related to pending resolution of legacy litigation matters.
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Year-end and fourth quarter 2004 results benefited from a strong operational performance from the company’s Natural Gas Liquids and Power Generation businesses. The in-market availability of Dynegy’s Natural Gas Liquids assets enabled it to capture the benefits of favorable commodity prices, as well as profitable fractionation spreads during the second half of 2004. Dynegy’s Power Generation business also benefited from strong asset availability, producing core volumes consistent with those reported in 2003. Offsetting the company’s operational results were charges related to the sale of Illinois Power, the restructuring of legacy power tolling arrangements, as well as capacity payments related to former and existing tolling and gas transport arrangements, and legal and settlement charges.
“2004 was a significant year in terms of the company’s strong operational performance and our continued progress in our comprehensive self-restructuring initiative, which began more than two years ago and is nearing completion,” said Bruce A. Williamson, Chairman, President and Chief Executive Officer of Dynegy Inc. “Throughout the year, Dynegy employees operated the company’s energy assets safely and efficiently, with a focus on asset availability to capture market opportunities. In addition, we made further progress toward resolving legacy issues and divesting non-strategic assets, while undertaking measured, fiscally responsible growth, including the acquisition of Sithe Energies.”
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DYNEGY ANNOUNCES FOURTH QUARTER AND YEAR-END 2004 RESULTS
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Year-Over-Year Comparison
A comparison of the company’s year-end 2004 and year-end 2003 results is set forth in the table below (in millions of dollars, except per share amounts):
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| | | 2004
| | | 2003
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Loss from continuing operations before income taxes | | $ | (99 | ) | | $ | (959 | ) |
Income tax benefit | | | 89 | | | | 246 | |
Loss from discontinued operations, net of taxes | | | (5 | ) | | | (19 | ) |
Cumulative effect of change in accounting principles, net of tax | | | — | | | | 40 | |
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Net loss | | | (15 | ) | | | (692 | ) |
Less: Preferred stock dividend (gain) | | | 22 | | | | (1,013 | ) |
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Net income (loss) available to common stockholders | | $ | (37 | ) | | $ | 321 | |
Basic earnings (loss) per share | | | (.10 | ) | | | 0.86 | |
Diluted earnings (loss) per share | | $ | (.10 | ) | | $ | 0.78 | |
Included in net loss for 2004 (above) were pre-tax gains (with the exception of the tax item) of $294 million offset by losses of $437 million. Below is a listing of these items (in millions of dollars):
Gains
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Asset sales | | $ | 159 |
| Gas transportation contracts | | | 88 |
| Discontinued operations | | | 23 |
| Taxes | | | 24 |
Losses
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| Asset impairments and loss on sales | | $ | (197 | ) |
| Toll restructuring | | | (115 | ) |
| Legal and settlement charges | | | (111 | ) |
| Acceleration of financing costs | | | (14 | ) |
Annual Business Segment Results
Following are year-end 2004 business segment financial results compared to year-end 2003:
Power Generation
Earnings before interest, taxes and depreciation and amortization (EBITDA) from the Power Generation business was $547 million for 2004, compared to $538 million for the previous year. Results for 2004 included $90 million of gains on the previously announced sales of the company’s interests in the Joppa and Oyster Creek power generation facilities, partially offset by impairment charges totaling $85 million related to Dynegy’s investment in West Coast Power.
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DYNEGY ANNOUNCES FOURTH QUARTER AND YEAR-END 2004 RESULTS
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Overall, core electricity production of 32.7 million megawatts in 2004 was unchanged compared to the prior year. The year was marked by operational milestones by certain assets, including the 1,761-megawatt Baldwin Energy Complex in Illinois, which set an all-time production record by generating 13.2 million megawatt-hours of electricity. Dynegy’s Midwest plants, including Baldwin, benefited from a long-term coal transportation contract that went into effect in January 2004 and supplies these facilities with lower-cost, lower-sulfur Powder River Basin coal. In addition, Dynegy’s 1,210-megawatt Roseton plant in New York generated 20 percent more electricity year-over-year as a result of the cost benefits of fuel oil-fired generation that were realized in the first half of 2004.
Offsetting these operational results were higher coal and fuel oil costs in the Northeast and lower volumes generated by the Havana generation facility in Illinois as a result of the company’s decision to moderate its supply of Colorado-sourced coal inventory during the plant’s conversion to Powder River Basin coal.
For the 12 months ended Dec. 31, 2004, cash flow from operations was $421 million, while capital expenditures and business acquisition costs were $148 million. After including proceeds from asset sales of $260 million, free cash flow for the Power Generation segment was $533 million.
Natural Gas Liquids
EBITDA from the Natural Gas Liquids business was $364 million for 2004, compared to $230 million for 2003. The 58 percent increase in EBITDA year-over-year was the result of significantly higher commodity prices and profitable fractionation spreads in the second half of 2004. Additionally, 2004 earnings included $69 million of gains on asset sales, compared to gains of $25 million on asset sales in 2003. The average natural gas price of $6.13 per million British thermal units represented a 14 percent increase compared to the previous year’s average. The average crude oil price of
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DYNEGY ANNOUNCES FOURTH QUARTER AND YEAR-END 2004 RESULTS
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$41.43 per barrel was 34 percent higher than 2003, while the average natural gas liquids price of $0.71 per gallon was 29 percent higher than the previous year’s average. The favorable fractionation spread in the second half of 2004 that resulted from the widening price gap between natural gas liquids and natural gas prompted the industry to seek full liquids recovery, resulting in stronger utilization of this segment’s marketing assets as compared to 2003.
For the 12 months ended Dec. 31, 2004, cash flow from operations was $278 million, while capital expenditures were $61 million. After including $99 million in proceeds from asset sales, free cash flow for the Natural Gas Liquids segment was $316 million.
Regulated Energy Delivery
As previously announced, the sale of Dynegy’s Regulated Energy Delivery business to Ameren was completed during the third quarter 2004. The sale eliminated $1.8 billion of Illinois Power debt and preferred stock obligations, while delivering additional cash proceeds to the company.
EBITDA from the Regulated Energy Delivery business totaled $152 million, primarily related to operations through Sept. 30, 2004, compared to a loss of $212 million for the full year 2003. 2004 EBITDA included a $58 million charge related to a loss on the sale of Illinois Power and a $54 million impairment of Illinois Power. Previous year results included a $311 million goodwill impairment and a $218 million asset impairment.
For the nine months ended Sept. 30, 2004, cash flow from operations was $213 million, excluding intercompany payments to and from Dynegy, with capital expenditures of $92 million and proceeds from asset sales of $217 million. The result was free cash flow for the Regulated Energy Delivery segment of $338 million.
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Customer Risk Management
The loss before interest, taxes and depreciation and amortization from the Customer Risk Management business totaled $101 million during 2004, compared to a $343 million loss before interest, taxes and depreciation and amortization in 2003. The 2004 loss included a previously announced $88 million gain related to the company’s exit from gas transportation contracts, offset by a $115 million charge related to the financial mitigation of the Kendall power tolling arrangement.
The company’s Customer Risk Management business will continue to have a negative effect on its consolidated results of operations and cash flows until the remaining obligations have been satisfied or restructured. The company continues to pursue opportunities to terminate or restructure its remaining obligations related to this business.
Other
In Other, which consists primarily of general and administrative expenses and legal and settlement charges, the company recorded a $235 million loss before interest, taxes and depreciation and amortization for 2004, compared to a $173 million loss before interest, taxes and depreciation and amortization for 2003. The higher loss in 2004 related primarily to increased legal and settlement charges, costs related to compliance with Section 404 of the Sarbanes-Oxley Act, and higher professional fees.
The company’s interest expense decreased to $480 million for 2004 from $509 million for the previous year primarily as a result of the sale of Illinois Power in the third quarter 2004. In addition, a total of $24 million in deferred financing costs were expensed in 2003 as a result of the company’s August 2003 refinancing, compared to $14 million in 2004.
The 2004 tax benefit from continuing operations of $89 million includes a $52 million benefit primarily related to the release of a deferred tax valuation allowance related to gains on asset sales. After adjusting for this item, the effective tax rate for
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2004 was 37 percent. The 2003 tax benefit from continuing operations of $246 million includes a $34 million benefit related to the release of a deferred tax valuation allowance. Additionally, no tax benefit was recognized in 2003 in connection with the $311 million goodwill impairment. After adjusting for these items, the effective tax rate for 2003 was 33 percent.
The $22 million preferred stock dividend recognized in 2004 is related to the company’s Series C preferred stock, which accumulates dividends at an annual rate of 5.5 percent. During the third quarter 2003, the restructuring of the Series B preferred stock previously held by a ChevronTexaco subsidiary resulted in the recognition of a $1.0 billion benefit, net of accreted dividends.
Liquidity
As of Dec. 31, 2004, Dynegy’s liquidity was approximately $1.2 billion. This consisted of $628 million in cash on hand and $606 million in unused availability under the company’s $700 million revolving bank credit facility.
The decrease in cash on hand compared to Sept. 30, 2004 is primarily attributable to payments made to retire debt and to restructure the Kendall power tolling arrangement.
To date, the revolving credit facility has been used exclusively to support the issuance of letters of credit. Accordingly, as of Dec. 31, 2004, there were no borrowings outstanding under this facility. Total collateral posted as of Dec. 31, 2004, including cash and letters of credit, was approximately $470 million, which was slightly lower than the $482 million posted on Dec. 31, 2003.
Cash Flow
Cash flow from operations, including working capital changes, totaled $5 million for the 12 months ended Dec. 31, 2004. This consisted of $912 million from the Power Generation, Natural Gas Liquids and Regulated Energy Delivery businesses, primarily due to positive results for the period, partially offset by increased cash collateral posted in
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lieu of letters of credit. Cash outflows of $371 million from the Customer Risk Management business primarily resulted from payments related to the Kendall toll and gas transport arrangements and capacity payments that exceeded realized margins on the company’s power tolling arrangements. An additional $536 million in cash outflows was related to interest payments and general and administrative expenses.
Cash flow from investing activities for the 12 months ended Dec. 31, 2004, totaled $262 million. This consisted of $576 million in proceeds from asset sales, partially offset by $314 million in capital expenditures in the company’s operating businesses and business acquisition costs. As previously noted, major asset sales during 2004 included Illinois Power and the company’s interest in the Joppa power generation facility, as well as other non-core assets.
For the 12 months ended Dec. 31, 2004, Dynegy’s free cash flow was $267 million, which consisted of cash flows from operations, plus proceeds from asset sales, less capital expenditures.
Restatements
As a result of the completion of the company’s extensive tax initiative and the preparation of its 2004 tax provision, the financial statements herein reflect the effects of further adjustments related to Dynegy’s previously recorded impairment charge associated with the sale of Illinois Power and Dynegy’s deferred income tax accounts.
Although neither of these items were considered material to the periods to which they related, these items, in aggregate, are material to the company’s 2004 results. Dynegy is required to restate prior periods in accordance with APB 20, “Accounting Changes.” These adjustments will not have an impact on our net income for the year ended Dec. 31, 2004 or cash provided by (used in) operating activities, investing activities or financing activities for the years ended Dec. 31, 2003 and Dec. 31, 2004.
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The aggregate effect of the adjustment related to the company’s previously recorded impairment charge on Dynegy’s net income for the 12 months ended Dec. 31, 2003, as shown in the attached schedule, “Quantification of Effects of Restatement Items,” is a reduction in net income of $16 million.
The aggregate effect of the adjustment related to the company’s deferred income tax accounts on Dynegy’s net income for the twelve months ended Dec. 31, 2003, as shown in the attached schedule, “Quantification of Effects of Restatement Items,” is a reduction in net income of $9 million.
Sarbanes-Oxley
In accordance with Section 404 of the Sarbanes-Oxley Act, Dynegy management is required to include in its 2004 Form 10-K an assessment of the effectiveness of the company’s internal control over financial reporting. Management is currently engaged in the assessment process and will reach a conclusion prior to filing the company’s 2004 Form 10-K.
2005 Earnings Guidance Estimate
With today’s announcement of financial results for the quarter and year ended Dec. 31, 2004, management is revising its 2005 GAAP earnings and operating cash flow estimates, which were first issued on Dec. 8, 2004. The company’s new estimate of net loss from its core businesses is a range of $199 million to $183 million, compared to the previously announced estimated loss of $171 million to $155 million. This revised estimate is based on a change in the company’s financing assumptions due to the elimination of capital-raising events and other liability management activities. The company expects to realize a one-time, pre-tax charge of approximately $220 million related to the company’s acquisition of Sithe Energies and the related tax benefit. As a result, the company’s revised guidance on a GAAP basis is a net loss of $335 million to $319 million.
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DYNEGY ANNOUNCES FOURTH QUARTER AND YEAR-END 2004 RESULTS
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The company expects operating cash flow in 2005 to be a range of $200 million to $215 million, compared to the previous range of $225 million to $240 million. This change is primarily a result of an increase in interest costs associated with the elimination of previously mentioned financing assumptions. Other revisions relate to a $16 million decrease in the expected payment to exit certain natural gas transportation agreements. The $26 million payment was reduced from the previously expected amount of $42 million due to a $16 million prepayment in 2004.
Investor Conference Call/Web Cast
Dynegy will discuss its 2004 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. provides electricity, natural gas and natural gas liquids to customers throughout the United States. Through its energy businesses, the company owns and operates a diverse portfolio of assets, including power plants totaling approximately 13,000 megawatts of net generating capacity and gas processing plants that process approximately 1.6 billion cubic feet of natural gas per day.
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 the ongoing effects of Dynegy’s customer risk management business, the ability to terminate or satisfy remaining power tolling agreements, and Dynegy’s estimated financial results for 2004 and 2005. Historically, Dynegy’s performance has deviated, in some cases materially, from its earnings and cash flow targets, 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 targets on a quarterly basis, it does not intend to update these targets 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.
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DYNEGY ANNOUNCES FOURTH QUARTER AND YEAR-END 2004 RESULTS
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Some of the key factors that could cause actual results to vary materially from those targeted, expected or implied include: changes in commodity prices, particularly for power, natural gas and natural gas liquids; the effects of competition on Dynegy’s results of operations; the effects of weather on Dynegy’s asset-based businesses and the demand for Dynegy’s products and services; Dynegy’s ability to successfully complete its exit from the customer risk management business and fund the costs associated with this exit; Dynegy’s ability to integrate the assets acquired in the Sithe Energies acquisition and achieve its related financial and operational goals; Dynegy’s ability to operate its businesses efficiently and within the confines of the company’s reduced capital spending program; Dynegy’s ability to address its substantial leverage; the condition of the capital markets generally and Dynegy’s ability to access the capital markets as and when needed; Dynegy’s liquidity and its effect on the ability to fund increased interest costs associated with Dynegy’s capital structure; the impacts of hedging; operational factors affecting Dynegy’s assets, including blackouts or other unscheduled outages; Dynegy’s ability to achieve the cost savings targets associated with its ongoing initiatives; and uncertainties regarding environmental regulations and litigation and other legal or regulatory developments affecting Dynegy’s businesses, including litigation relating to the western power and natural gas markets, shareholder claims and master netting agreement matters. 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, 2003, as amended, and its Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, as amended, which are available free of charge on the SEC’s web site athttp://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. DYNF
INTRODUCTORY NOTE
The financial statements herein reflect the effects of restatement items related to Dynegy’s previously recorded impairment charge associated with the sale of Illinois Power Company and Dynegy’s deferred income tax accounts. Although neither of these items were considered material to the periods to which they related, these items, in aggregate, are material to the company’s 2004 results. The company is required to restate prior periods in accordance with APB 20, “Accounting Changes.”
The previously disclosed $311 million goodwill impairment and $193 million pre-tax asset impairment, which were recorded by Dynegy to reflect the fair value of Illinois Power, were originally recorded in the fourth quarter 2003. Recently, while preparing its year-end 2004 tax provision, Dynegy identified a deferred tax liability that was erroneously included in its fourth quarter 2003 impairment analysis. Dynegy’s inclusion of this liability understated the net book value of the assets and, as a result, understated the impairment that had been recorded in the fourth quarter 2003. The company concluded that an additional pre-tax impairment charge of approximately $25 million ($16 million after-tax) should have been reflected in the fourth quarter 2003. The
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DYNEGY ANNOUNCES FOURTH QUARTER AND YEAR-END 2004 RESULTS
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aggregate effect of this restatement on Dynegy’s net loss for the three and twelve months ended Dec. 31, 2003, as shown in the attached schedule, “Quantification of Effects of Restatement Items,” is a reduction in net income of $16 million. This restatement will not have an impact on our net income for the year ended Dec. 31, 2004 or cash provided by (used in) operating activities, investing activities or financing activities for the years ended Dec. 31, 2003 and Dec. 31, 2004.
In Amendment No. 1 to the company’s third quarter 2004 Form 10-Q, the company detailed the steps implemented to improve Dynegy’s internal controls around its tax accounting and tax reconciliation controls and processes. Recently, during the preparation of the company’s financial statements for inclusion in its 2004 Form 10-K, and as a result of these additional internal controls, Dynegy determined that adjustments related to its deferred income tax accounts in periods prior to 2004 are required. These adjustments primarily related to errors in our previously completed tax basis balance sheet review, which resulted in a $45 million understatement of our deferred tax liability at Dec. 31, 2003. The aggregate effect of this restatement on Dynegy’s net loss for the three and twelve months ended Dec. 31, 2003, as shown in the attached schedule, “Quantification of Effects of Restatement Items,” is a reduction in net income of $9 million. This restatement will not have an impact on our net income for the year ended Dec. 31, 2004 or cash provided by (used in) operating activities, investing activities or financing activities for the years ended Dec. 31, 2003 and Dec. 31, 2004.
Please read the accompanying financial statement schedules and the notes thereto, including the schedule entitled “Quantification of Effects of Restatement Items” for further discussion of these restatement items and their respective impact on the company’s financial results for the periods presented.
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DYNEGY INC.
REPORTED UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (1)
(IN MILLIONS, EXCEPT PER SHARE DATA)
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| | | Three Months Ended December 31,
| | | Twelve Months Ended
December 31,
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| | | 2004
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Revenues | | $ | 1,406 | | | $ | 1,456 | | | $ | 6,153 | | | $ | 5,787 | |
Cost of sales, exclusive of depreciation shown separately below | | | (1,411 | ) | | | (1,252 | ) | | | (5,214 | ) | | | (5,074 | ) |
Depreciation and amortization expense | | | (74 | ) | | | (114 | ) | | | (323 | ) | | | (454 | ) |
Goodwill impairment | | | — | | | | (311 | ) | | | — | | | | (311 | ) |
Impairment and other charges | | | — | | | | (231 | ) | | | (83 | ) | | | (225 | ) |
Gain (loss) on sale of assets, net | | | (3 | ) | | | 14 | | | | 11 | | | | 29 | |
General and administrative expenses | | | (105 | ) | | | (70 | ) | | | (352 | ) | | | (346 | ) |
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Operating income (loss) | | | (187 | ) | | | (508 | ) | | | 192 | | | | (594 | ) |
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Earnings (losses) from unconsolidated investments | | | 8 | | | | (18 | ) | | | 202 | | | | 124 | |
Interest expense | | | (78 | ) | | | (145 | ) | | | (480 | ) | | | (509 | ) |
Accumulated distributions associated with trust preferred securities | | | — | | | | — | | | | — | | | | (8 | ) |
Other income and expense, net | | | (4 | ) | | | 8 | | | | (13 | ) | | | 28 | |
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Loss from continuing operations before income taxes | | | (261 | ) | | | (663 | ) | | | (99 | ) | | | (959 | ) |
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Income tax benefit | | | 88 | | | | 137 | | | | 89 | | | | 246 | |
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Income (loss) from continuing operations | | | (173 | ) | | | (526 | ) | | | (10 | ) | | | (713 | ) |
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Income (loss) from discontinued operations, net of tax | | | 2 | | | | (13 | ) | | | (5 | ) | | | (19 | ) |
Cumulative effect of change in accounting principles, net of tax | | | — | | | | (15 | ) | | | — | | | | 40 | |
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Net income (loss) | | $ | (171 | ) | | $ | (554 | ) | | $ | (15 | ) | | $ | (692 | ) |
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Less: Preferred stock dividends (gain) | | | 5 | | | | 5 | | | | 22 | | | | (1,013 | ) |
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Net income (loss) applicable to common stockholders | | $ | (176 | ) | | $ | (559 | ) | | $ | (37 | ) | | $ | 321 | |
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Earnings (loss) before interest, taxes, and depreciation and amortization (EBITDA) (2) | | $ | (107 | ) | | $ | (439 | ) | | $ | 727 | | | $ | 40 | |
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Basic earnings (loss) per share: | | | | | | | | | | | | | | | | |
Income (loss) from continuing operations (3) | | $ | (0.47 | ) | | $ | (1.42 | ) | | $ | (0.09 | ) | | $ | 0.80 | |
Income (loss) from discontinued operations | | | 0.00 | | | | (0.03 | ) | | | (0.01 | ) | | | (0.05 | ) |
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Cumulative effect of change in accounting principles | | | — | | | | (0.04 | ) | | | — | | | | 0.11 | |
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Basic earnings (loss) per share | | $ | (0.47 | ) | | $ | (1.49 | ) | | $ | (0.10 | ) | | $ | 0.86 | |
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Diluted earnings (loss) per share: | | | | | | | | | | | | | | | | |
Income (loss) from continuing operations (3) | | $ | (0.47 | ) | | $ | (1.42 | ) | | $ | (0.09 | ) | | $ | 0.73 | |
Income (loss) from discontinued operations | | | 0.00 | | | | (0.03 | ) | | | (0.01 | ) | | | (0.04 | ) |
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Cumulative effect of change in accounting principles | | | — | | | | (0.04 | ) | | | — | | | | 0.09 | |
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Diluted earnings (loss) per share | | $ | (0.47 | ) | | $ | (1.49 | ) | | $ | (0.10 | ) | | $ | 0.78 | |
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Basic shares outstanding | | | 379 | | | | 375 | | | | 378 | | | | 374 | |
Diluted shares outstanding | | | 505 | | | | 501 | | | | 504 | | | | 423 | |
| (1) | Financial results for the periods presented reflect the effects of the restatement items described in the Introductory Note and the other financial statement schedules accompanying this press release, including the notes thereto, for additional discussion regarding these restatements. |
| (2) | EBITDA is a non-GAAP financial measure. EBITDA consists of Operating income (loss) plus Depreciation and amortization expense; Earnings (losses) from unconsolidated investments; Accumulated distributions associated with trust preferred securities; Other income and expense, net; Income (loss) from discontinued operations (pre-tax) and Cumulative effect of change in accounting principles (pre-tax). 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. |
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| | | Three Months Ended December 31,
| | | Twelve Months Ended
December 31,
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| | | 2004
| | | 2003
| | | 2004
| | | 2003
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Operating income (loss) | | $ | (187 | ) | | $ | (508 | ) | | $ | 192 | | | $ | (594 | ) |
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Add: Depreciation and amortization expense, a component of operating income (loss) | | | 74 | | | | 114 | | | | 323 | | | | 454 | |
Earnings (losses) from unconsolidated investments | | | 8 | | | | (18 | ) | | | 202 | | | | 124 | |
Accumulated distributions associated with trust preferred securities | | | — | | | | — | | | | — | | | | (8 | ) |
Other income and expense, net | | | (4 | ) | | | 8 | | | | (13 | ) | | | 28 | |
Income (loss) from discontinued operations, pre-tax | | | 2 | | | | (12 | ) | | | 23 | | | | (28 | ) |
Cumulative effect of change in accounting principles, pre-tax | | | — | | | | (23 | ) | | | — | | | | 64 | |
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|
|
Earnings (losses) before interest, taxes, and depreciation and amortization (EBITDA) | | | (107 | ) | | | (439 | ) | | | 727 | | | | 40 | |
| | | | |
Less: Depreciation and amortization expense, a component of operating income (loss) | | | (74 | ) | | | (114 | ) | | | (323 | ) | | | (454 | ) |
Interest expense | | | (78 | ) | | | (145 | ) | | | (480 | ) | | | (509 | ) |
Income tax benefit from continuing operations | | | 88 | | | | 137 | | | | 89 | | | | 246 | |
Income tax benefit (expense) from discontinued operations | | | — | | | | (1 | ) | | | (28 | ) | | | 9 | |
Income tax benefit (expense) on cumulative effect of change in accounting principles | | | — | | | | 8 | | | | — | | | | (24 | ) |
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|
| |
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|
|
Net income (loss) | | $ | (171 | ) | | $ | (554 | ) | | $ | (15 | ) | | $ | (692 | ) |
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| (3) | 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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DYNEGY INC.
REPORTED UNAUDITED BASIC AND DILUTED EARNINGS (LOSS) PER SHARE FROM CONTINUING OPERATIONS (1)
(IN MILLIONS, EXCEPT PER SHARE DATA)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended December 31,
| | | Twelve Months Ended
December 31,
| |
| | | 2004
| | | 2003
| | | 2004
| | | 2003
| |
Income (loss) from continuing operations | | $ | (173 | ) | | $ | (526 | ) | | $ | (10 | ) | | $ | (713 | ) |
Less: convertible preferred stock dividends (gain) | | | 5 | | | | 5 | | | | 22 | | | | (1,013 | ) |
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| |
|
|
|
Income (loss) from continuing operations for basic earnings (loss) per share | | | (178 | ) | | | (531 | ) | | | (32 | ) | | | 300 | |
Effect of dilutive securities: | | | | | | | | | | | | | | | | |
Interest on convertible debentures | | | 2 | | | | 2 | | | | 7 | | | | 3 | |
Dividends on Series C convertible preferred stock | | | 5 | | | | 5 | | | | 22 | | | | 8 | |
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Income (loss) from continuing operations for diluted earnings (loss) per share | | $ | (171 | ) | | $ | (524 | ) | | $ | (3 | ) | | $ | 311 | |
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Basic weighted-average shares | | | 379 | | | | 375 | | | | 378 | | | | 374 | |
| | | | |
Effect of dilutive securities: | | | | | | | | | | | | | | | | |
Stock options and restricted stock | | | 2 | | | | 2 | | | | 2 | | | | 2 | |
Convertible subordinated debentures | | | 55 | | | | 55 | | | | 55 | | | | 20 | |
Series C convertible preferred stock | | | 69 | | | | 69 | | | | 69 | | | | 27 | |
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Diluted weighted-average shares (2) | | | 505 | | | | 501 | | | | 504 | | | | 423 | |
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Earnings (loss) per share from continuing operations: | | | | | | | | | | | | | | | | |
Basic | | $ | (0.47 | ) | | $ | (1.42 | ) | | $ | (0.09 | ) | | $ | 0.80 | |
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Diluted (3) | | $ | (0.47 | ) | | $ | (1.42 | ) | | $ | (0.09 | ) | | $ | 0.73 | |
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| (1) | Financial results for the periods presented reflect the effects of the restatement items described in the Introductory Note and the other financial statement schedules accompanying this press release, including the notes thereto, for additional discussion regarding these restatements. |
| (2) | The diluted shares for the twelve-months ended December 31, 2003 do not include the effect of the preferential conversion to Class B common stock of the Series B Preferred Stock previously held by a ChevronTexaco subsidiary, as such inclusion would be anti-dilutive. |
| (3) | 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, 2004 and the three months ended December 31, 2003. |
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DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended December 31, 2004
| |
| | | GEN
| | NGL
| | | REG
| | | CRM
| | | OTHER
| | | Total
| |
Generation | | $ | 4 | | | | | | | | | | | | | | | | | | $ | 4 | |
Natural Gas Liquids | | | | | | | | | | | | | | | | | | | | | | | |
Upstream | | | | | $ | 64 | | | | | | | | | | | | | | | | 64 | |
Downstream | | | | | | 9 | | | | | | | | | | | | | | | | 9 | |
Regulated Energy Delivery | | | | | | | | | $ | (19 | ) | | | | | | | | | | | (19 | ) |
Customer Risk Management | | | | | | | | | | | | | $ | (163 | ) | | | | | | | (163 | ) |
Other | | | | | | | | | | | | | | | | | $ | (82 | ) | | | (82 | ) |
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Operating income (loss) | | | 4 | | | 73 | | | | (19 | ) | | | (163 | ) | | | (82 | ) | | $ | (187 | ) |
Earnings from unconsolidated investments | | | 5 | | | 3 | | | | — | | | | — | | | | — | | | | 8 | |
Other items, net | | | 1 | | | (7 | ) | | | — | | | | (2 | ) | | | 4 | | | | (4 | ) |
Income from discontinued operations, pre-tax | | | — | | | — | | | | — | | | | 2 | | | | — | | | | 2 | |
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|
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|
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|
|
| | | | 10 | | | 69 | | | | (19 | ) | | | (163 | ) | | | (78 | ) | | | (181 | ) |
Add: Depreciation and amortization expense, a component of operating income (loss) (2) | | | 46 | | | 22 | | | | — | | | | — | | | | 6 | | | | 74 | |
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|
|
Earnings (loss) before interest, taxes, and depreciation and amortization (EBITDA) (3) | | $ | 56 | | $ | 91 | | | $ | (19 | ) | | $ | (163 | ) | | $ | (72 | ) | | $ | (107 | ) |
| | | | | | |
Less: Depreciation and amortization expense, a component of operating income (loss) | | | | | | | | | | | | | | | | | | | | | | (74 | ) |
Interest expense | | | | | | | | | | | | | | | | | | | | | | (78 | ) |
| | | | | | | | | | | | | | | | | | | | | |
|
|
|
Pre-tax loss | | | | | | | | | | | | | | | | | | | | | | (259 | ) |
Income tax benefit | | | | | | | | | | | | | | | | | | | | | | 88 | |
| | | | | | | | | | | | | | | | | | | | | |
|
|
|
Net loss | | | | | | | | | | | | | | | | | | | | | $ | (171 | ) |
| | | | | | | | | | | | | | | | | | | | | |
|
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended December 31, 2003 (1)
| |
| | | GEN
| | | NGL
| | | REG
| | | CRM
| | | OTHER
| | | Total
| |
Generation | | $ | 18 | | | | | | | | | | | | | | | | | | | $ | 18 | |
Natural Gas Liquids | | | | | | | | | | | | | | | | | | | | | | | | |
Upstream | | | | | | $ | 22 | | | | | | | | | | | | | | | | 22 | |
Downstream | | | | | | | 27 | | | | | | | | | | | | | | | | 27 | |
Regulated Energy Delivery | | | | | | | | | | $ | (485 | ) | | | | | | | | | | | (485 | ) |
Customer Risk Management | | | | | | | | | | | | | | $ | (37 | ) | | | | | | | (37 | ) |
Other | | | | | | | | | | | | | | | | | | $ | (53 | ) | | | (53 | ) |
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Operating income (loss) | | | 18 | | | | 49 | | | | (485 | ) | | | (37 | ) | | | (53 | ) | | $ | (508 | ) |
Losses from unconsolidated investments | | | (7 | ) | | | (9 | ) | | | — | | | | (2 | ) | | | — | | | | (18 | ) |
Other items, net | | | — | | | | (5 | ) | | | — | | | | 4 | | | | 9 | | | | 8 | |
Income (loss) from discontinued operations, pre-tax | | | — | | | | 1 | | | | (3 | ) | | | (13 | ) | | | 3 | | | | (12 | ) |
Cumulative effect of change in accounting principles | | | (23 | ) | | | — | | | | — | | | | — | | | | — | | | | (23 | ) |
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|
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|
| | | | (12 | ) | | | 36 | | | | (488 | ) | | | (48 | ) | | | (41 | ) | | | (553 | ) |
Add: Depreciation and amortization expense, a component of operating income (loss) | | | 50 | | | | 21 | | | | 30 | | | | (1 | ) | | | 14 | | | | 114 | |
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|
|
| |
|
|
|
Earnings (loss) before interest, taxes, and depreciation and amortization (EBITDA) (3) | | $ | 38 | | | $ | 57 | | | $ | (458 | ) | | $ | (49 | ) | | $ | (27 | ) | | $ | (439 | ) |
| | | | | | |
Less: Depreciation and amortization expense, a component of operating income (loss) | | | | | | | | | | | | | | | | | | | | | | | (114 | ) |
Interest expense | | | | | | | | | | | | | | | | | | | | | | | (145 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
|
|
|
Pre-tax loss | | | | | | | | | | | | | | | | | | | | | | | (698 | ) |
Income tax benefit | | | | | | | | | | | | | | | | | | | | | | | 144 | |
| | | | | | | | | | | | | | | | | | | | | | |
|
|
|
Net loss | | | | | | | | | | | | | | | | | | | | | | $ | (554 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
|
|
|
| (1) | Financial results for the periods presented reflect the effects of the restatement items described in the Introductory Note and the other financial statement schedules accompanying this press release, including the notes thereto, for additional discussion regarding these restatements. |
| (2) | Beginning in the first quarter 2004, we ceased depreciation on our Illinois Power assets in our REG reportable segment, as these assets were classified as “held-for-sale.” |
| (3) | See Note (1) to “Reported Unaudited Condensed Consolidated Statements of Operations.” EBITDA is a non-GAAP financial measure. EBITDA consists of Operating income (loss) plus Depreciation and amortization expense; Earnings (losses) from unconsolidated investments; Accumulated distributions associated with trust preferred securities; Other income and expense, net; Income (loss) from discontinued operations (pre-tax) and Cumulative effect of change in accounting principles (pre-tax). 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. |
-more-
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | |
| | | Twelve Months Ended December 31, 2004
| |
| | | GEN
| | NGL
| | | REG
| | CRM
| | | OTHER
| | | Total
| |
Generation | | $ | 163 | | | | | | | | | | | | | | | | | $ | 163 | |
Natural Gas Liquids | | | | | | | | | | | | | | | | | | | | | | |
Upstream | | | | | $ | 206 | | | | | | | | | | | | | | | 206 | |
Downstream | | | | | | 81 | | | | | | | | | | | | | | | 81 | |
Regulated Energy Delivery | | | | | | | | | $ | 139 | | | | | | | | | | | 139 | |
Customer Risk Management | | | | | | | | | | | | $ | (118 | ) | | | | | | | (118 | ) |
Other | | | | | | | | | | | | | | | | $ | (279 | ) | | | (279 | ) |
| | |
|
| |
|
|
| |
|
| |
|
|
| |
|
|
| |
|
|
|
Operating income (loss) | | | 163 | | | 287 | | | | 139 | | | (118 | ) | | | (279 | ) | | $ | 192 | |
Earnings from unconsolidated investments | | | 192 | | | 10 | | | | — | | | — | | | | — | | | | 202 | |
Other items, net | | | 1 | | | (22 | ) | | | 3 | | | (3 | ) | | | 8 | | | | (13 | ) |
Income from discontinued operations, pre-tax | | | — | | | 1 | | | | — | | | 19 | | | | 3 | | | | 23 | |
| | |
|
| |
|
|
| |
|
| |
|
|
| |
|
|
| |
|
|
|
| | | | 356 | | | 276 | | | | 142 | | | (102 | ) | | | (268 | ) | | | 404 | |
Add: Depreciation and amortization expense, a component of operating income (loss) (2) | | | 191 | | | 88 | | | | 10 | | | 1 | | | | 33 | | | | 323 | |
| | |
|
| |
|
|
| |
|
| |
|
|
| |
|
|
| |
|
|
|
Earnings (loss) before interest, taxes, and depreciation and amortization (EBITDA) (3) | | $ | 547 | | $ | 364 | | | $ | 152 | | $ | (101 | ) | | $ | (235 | ) | | $ | 727 | |
| | | | | | |
Less: Depreciation and amortization expense, a component of operating income (loss) | | | | | | | | | | | | | | | | | | | | | (323 | ) |
Interest expense | | | | | | | | | | | | | | | | | | | | | (480 | ) |
| | | | | | | | | | | | | | | | | | | | |
|
|
|
Pre-tax loss | | | | | | | | | | | | | | | | | | | | | (76 | ) |
Income tax benefit | | | | | | | | | | | | | | | | | | | | | 61 | |
| | | | | | | | | | | | | | | | | | | | |
|
|
|
Net loss | | | | | | | | | | | | | | | | | | | | $ | (15 | ) |
| | | | | | | | | | | | | | | | | | | | |
|
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Twelve Months Ended December 31, 2003 (1)
| |
| | | GEN
| | NGL
| | | REG
| | | CRM
| | | OTHER
| | | Total
| |
Generation | | $ | 194 | | | | | | | | | | | | | | | | | | $ | 194 | |
Natural Gas Liquids | | | | | | | | | | | | | | | | | | | | | | | |
Upstream | | | | | $ | 108 | | | | | | | | | | | | | | | | 108 | |
Downstream | | | | | | 62 | | | | | | | | | | | | | | | | 62 | |
Regulated Energy Delivery | | | | | | | | | $ | (327 | ) | | | | | | | | | | | (327 | ) |
Customer Risk Management | | | | | | | | | | | | | $ | (385 | ) | | | | | | | (385 | ) |
Other | | | | | | | | | | | | | | | | | $ | (246 | ) | | | (246 | ) |
| | |
|
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|
|
| |
|
|
| |
|
|
| |
|
|
| |
|
|
|
Operating income (loss) | | | 194 | | | 170 | | | | (327 | ) | | | (385 | ) | | | (246 | ) | | $ | (594 | ) |
Earnings (losses) from unconsolidated investments | | | 128 | | | (2 | ) | | | — | | | | (2 | ) | | | — | | | | 124 | |
Other items, net | | | 4 | | | (17 | ) | | | — | | | | 31 | | | | 2 | | | | 20 | |
Income (loss) from discontinued operations, pre-tax | | | — | | | (2 | ) | | | (3 | ) | | | (30 | ) | | | 7 | | | | (28 | ) |
Cumulative effect of change in accounting principles, pre-tax | | | 24 | | | — | | | | (3 | ) | | | 43 | | | | — | | | | 64 | |
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|
|
| |
|
|
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|
|
|
| | | | 350 | | | 149 | | | | (333 | ) | | | (343 | ) | | | (237 | ) | | | (414 | ) |
Add: Depreciation and amortization expense, a component of operating income (loss) | | | 188 | | | 81 | | | | 121 | | | | — | | | | 64 | | | | 454 | |
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|
| |
|
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|
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|
| |
|
|
| |
|
|
|
Earnings (loss) before interest, taxes, and depreciation and amortization (EBITDA) (3) | | $ | 538 | | $ | 230 | | | $ | (212 | ) | | $ | (343 | ) | | $ | (173 | ) | | $ | 40 | |
| | | | | | |
Less: Depreciation and amortization expense, a component of operating income (loss) | | | | | | | | | | | | | | | | | | | | | | (454 | ) |
Interest expense | | | | | | | | | | | | | | | | | | | | | | (509 | ) |
| | | | | | | | | | | | | | | | | | | | | |
|
|
|
Pre-tax loss | | | | | | | | | | | | | | | | | | | | | | (923 | ) |
Income tax benefit | | | | | | | | | | | | | | | | | | | | | | 231 | |
| | | | | | | | | | | | | | | | | | | | | |
|
|
|
Net loss | | | | | | | | | | | | | | | | | | | | | $ | (692 | ) |
| | | | | | | | | | | | | | | | | | | | | |
|
|
|
| (1) | Financial results for the periods presented reflect the effects of the restatement items described in the Introductory Note and the other financial statement schedules accompanying this press release, including the notes thereto, for additional discussion regarding these restatements. |
| (2) | Beginning in the first quarter 2004, we ceased depreciation on our Illinois Power assets in our REG reportable segment, as these assets were classified as “held-for-sale.” |
| (3) | See Note (1) to “Reported Unaudited Condensed Consolidated Statements of Operations.” EBITDA is a non-GAAP financial measure. EBITDA consists of Operating income (loss) plus Depreciation and amortization expense; Earnings (losses) from unconsolidated investments; Accumulated distributions associated with trust preferred securities; Other income and expense, net; Income (loss) from discontinued operations (pre-tax) and Cumulative effect of change in accounting principles (pre-tax). 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. |
-more-
DYNEGY INC.
SIGNIFICANT ITEMS
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended December 31, 2004
| |
| | | GEN
| | | NGL
| | REG
| | | CRM
| | | OTHER
| | | Total
| |
Kendall toll restructuring (1) | | $ | — | | | $ | — | | $ | — | | | $ | (115 | ) | | $ | — | | | $ | (115 | ) |
Impairment of West Coast Power (2) | | | (40 | ) | | | — | | | — | | | | — | | | | — | | | | (40 | ) |
Loss on sale of Illinois Power (3) | | | — | | | | — | | | (19 | ) | | | — | | | | — | | | | (19 | ) |
Legal and settlement charges (4) | | | (9 | ) | | | — | | | — | | | | (13 | ) | | | (35 | ) | | | (57 | ) |
Taxes (5) | | | — | | | | — | | | — | | | | — | | | | (19 | ) | | | (19 | ) |
Gain on sale of Sherman (6) | | | — | | | | 16 | | | — | | | | — | | | | — | | | | 16 | |
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| |
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| |
|
|
| |
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|
| |
|
|
| |
|
|
|
Total | | $ | (49 | ) | | $ | 16 | | $ | (19 | ) | | $ | (128 | ) | | $ | (54 | ) | | $ | (234 | ) |
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| | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended December 31, 2003
| |
| | | GEN
| | | NGL
| | | REG
| | | CRM
| | | OTHER
| | Total
| |
Illinois Power goodwill impairment (7) | | $ | — | | | $ | — | | | $ | (311 | ) | | $ | — | | | $ | — | | $ | (311 | ) |
Illinois Power asset impairment (8) | | | — | | | | — | | | | (218 | ) | | | — | | | | — | | | (218 | ) |
Batesville tolling settlement (9) | | | — | | | | — | | | | — | | | | (34 | ) | | | — | | | (34 | ) |
Impairment of generation investments (10) | | | (26 | ) | | | — | | | | — | | | | — | | | | — | | | (26 | ) |
West Coast Power goodwill impairment (11) | | | (20 | ) | | | — | | | | — | | | | — | | | | — | | | (20 | ) |
Discontinued operations (12) | | | — | | | | 1 | | | | (3 | ) | | | (13 | ) | | | 3 | | | (12 | ) |
Impairment of equity investment (13) | | | — | | | | (12 | ) | | | — | | | | — | | | | — | | | (12 | ) |
Gain on sale of Hackberry LNG (14) | | | — | | | | 15 | | | | — | | | | — | | | | — | | | 15 | |
Taxes (15) | | | (1 | ) | | | — | | | | — | | | | — | | | | 34 | | | 33 | |
Cumulative effect of change in accounting (16) | | | (23 | ) | | | — | | | | — | | | | — | | | | — | | | (23 | ) |
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Total | | $ | (70 | ) | | $ | 4 | | | $ | (532 | ) | | $ | (47 | ) | | $ | 37 | | $ | (608 | ) |
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| (1) | We recognized a pre-tax charge of approximately $115 million ($72 million after-tax) related to the restructuring of the Kendall toll with Constellation Energy. This charge is included in Cost of sales. |
| (2) | We recognized a pre-tax charge of approximately $40 million ($25 million after-tax) related to our share of an impairment of assets at West Coast Power, a joint venture with NRG Energy, and an impairment of our investment in West Coast Power. This charge is included in Earnings (losses) from unconsolidated investments. |
| (3) | We recognized a pre-tax loss of approximately $19 million ($12 million after-tax) related to the sale of Illinois Power. This loss is included in Gain (loss) on sale of assets, net. |
| (4) | We recognized a pre-tax loss of approximately $57 million ($36 million after-tax) related to legal and settlement charges. The loss is included in Cost of sales and General and administrative expenses. |
| (5) | We recognized a net income tax expense of approximately $19 million primarily related to deferred tax capital loss valuation allowances. An expense of $11 million is included in Income tax benefit and an expense of $8 million is included in Income (loss) from discontinued operations. |
| (6) | We recognized a pre-tax gain of approximately $16 million ($10 million after-tax) on the sale of our Sherman natural gas processing facility. This gain is included in Gain (loss) on sale of assets, net. |
| (7) | We recognized a pre-tax charge of approximately $311 million ($311 million after-tax) for the impairment of goodwill associated with Illinois Power. This charge is included in Goodwill impairment. |
| (8) | We recognized a pre-tax charge of approximately $218 million ($136 million after-tax) for the impairment of Illinois Power assets. This charge is included in Impairment and other charges. |
| (9) | We recognized a pre-tax charge of approximately $34 million ($22 million after-tax) related to the termination of the Batesville tolling arrangement with a subsidiary of Dominion Resources. This charge is included in Cost of sales. |
| (10) | We recognized a pre-tax charge of approximately $26 million ($16 million after-tax) related to the impairments of our investments in certain domestic and foreign generation assets. These charges are included in Earnings (losses) from unconsolidated investments. |
| (11) | We recognized a pre-tax charge of approximately $20 million ($13 million after-tax) related to our share of an impairment of goodwill recorded by West Coast Power. This charge is included in Earnings (losses) from unconsolidated investments. |
| (12) | We recognized a pre-tax loss of approximately $12 million ($13 million after-tax) related to discontinued operations. This loss consists primarily of a $13 million pre-tax loss ($8 million after-tax) from our UK CRM business and a $3 million pre-tax loss ($2 million after-tax) associated with NNG. These losses are offset by a $3 million pre-tax gain ($4 million after-tax expense) from our global communications business and a $1 million pre-tax gain ($1 million after-tax) associated with our global liquids business. |
| (13) | We recognized a pre-tax charge of approximately $12 million ($8 million after-tax) related to the impairment of our investment in a fractionator located in the Texas Gulf Coast region. This charge is included in Earnings (losses) from unconsolidated investments. |
| (14) | We recognized a pre-tax gain of approximately $15 million ($10 million after-tax) related to the sale of our interest in Hackberry LNG Terminal LLC and associated project development milestones. This gain is included in Gain (loss) on sale of assets, net. |
| (15) | We recognized an income tax benefit of approximately $33 million primarily related to the release of a deferred tax capital gains valuation allowance. A benefit of $38 million is included in Income tax benefit and the offsetting $5 million charge is included in Income (loss) from discontinued operations. |
| (16) | We adopted the provisions of FIN 46 and recognized a pre-tax charge of $23 million ($15 million after-tax). |
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DYNEGY INC.
SIGNIFICANT ITEMS
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Twelve Months Ended December 31, 2004
| |
| | | GEN
| | | NGL
| | REG
| | | CRM
| | | OTHER
| | | Total
| |
Kendall toll restructuring (1) | | $ | — | | | $ | — | | $ | — | | | $ | (115 | ) | | $ | — | | | $ | (115 | ) |
Impairment of West Coast Power (2) | | | (85 | ) | | | — | | | — | | | | — | | | | — | | | | (85 | ) |
Legal and settlement charges (3) | | | (7 | ) | | | 2 | | | (1 | ) | | | (13 | ) | | | (92 | ) | | | (111 | ) |
Impairment of Illinois Power (4) | | | — | | | | — | | | (54 | ) | | | — | | | | — | | | | (54 | ) |
Loss on sale of Illinois Power (5) | | | — | | | | — | | | (58 | ) | | | — | | | | — | | | | (58 | ) |
Acceleration of financing costs (6) | | | — | | | | — | | | — | | | | — | | | | (14 | ) | | | (14 | ) |
Gain on sale of Oyster Creek (7) | | | 15 | | | | — | | | — | | | | — | | | | — | | | | 15 | |
Gain on sale of Sherman (8) | | | — | | | | 16 | | | — | | | | — | | | | — | | | | 16 | |
Gain on sale of Hackberry LNG (9) | | | — | | | | 17 | | | — | | | | — | | | | — | | | | 17 | |
Discontinued operations (10) | | | — | | | | 1 | | | — | | | | 19 | | | | 3 | | | | 23 | |
Taxes (11) | | | — | | | | — | | | — | | | | — | | | | 24 | | | | 24 | |
Gain on sale of Indian Basin (12) | | | — | | | | 36 | | | — | | | | — | | | | — | | | | 36 | |
Gain on sale of Joppa (13) | | | 75 | | | | — | | | — | | | | — | | | | — | | | | 75 | |
Gas transportation contracts (14) | | | — | | | | — | | | — | | | | 88 | | | | — | | | | 88 | |
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Total | | $ | (2 | ) | | $ | 72 | | $ | (113 | ) | | $ | (21 | ) | | $ | (79 | ) | | $ | (143 | ) |
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| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Twelve Months Ended December 31, 2003
| |
| | | GEN
| | | NGL
| | | REG
| | | CRM
| | | OTHER
| | | Total
| |
Illinois Power goodwill impairment (15) | | $ | — | | | $ | — | | | $ | (311 | ) | | $ | — | | | $ | — | | | $ | (311 | ) |
Illinois Power asset impairment (16) | | | — | | | | — | | | | (218 | ) | | | — | | | | — | | | | (218 | ) |
Southern Power settlement (17) | | | — | | | | — | | | | — | | | | (133 | ) | | | — | | | | (133 | ) |
Sithe power tolling contract (18) | | | — | | | | — | | | | — | | | | (121 | ) | | | — | | | | (121 | ) |
Legal charges (19) | | | — | | | | — | | | | — | | | | — | | | | (50 | ) | | | (50 | ) |
Batesville tolling settlement (20) | | | — | | | | — | | | | — | | | | (34 | ) | | | — | | | | (34 | ) |
Kroger settlement (21) | | | — | | | | — | | | | — | | | | (30 | ) | | | — | | | | (30 | ) |
Discontinued operations (22) | | | — | | | | (2 | ) | | | (3 | ) | | | (30 | ) | | | 7 | | | | (28 | ) |
Impairment of generation investment (23) | | | (26 | ) | | | — | | | | — | | | | — | | | | — | | | | (26 | ) |
Acceleration of financing costs (24) | | | — | | | | — | | | | — | | | | — | | | | (24 | ) | | | (24 | ) |
West Coast Power goodwill impairment (25) | | | (20 | ) | | | — | | | | — | | | | — | | | | — | | | | (20 | ) |
Impairment of equity investment (26) | | | — | | | | (12 | ) | | | — | | | | — | | | | — | | | | (12 | ) |
Taxes (27) | | | (1 | ) | | | — | | | | — | | | | — | | | | 34 | | | | 33 | |
Gain on sale of Hackberry LNG (28) | | | — | | | | 25 | | | | — | | | | 2 | | | | — | | | | 27 | |
Cumulative effect of change in accounting | | | | | | | | | | | | | | | | | | | | | | | | |
principles (29) | | | 24 | | | | — | | | | (3 | ) | | | 43 | | | | — | | | | 64 | |
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Total | | $ | (23 | ) | | $ | 11 | | | $ | (535 | ) | | $ | (303 | ) | | $ | (33 | ) | | $ | (883 | ) |
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| (1) | We recognized a pre-tax charge of approximately $115 million ($72 million after-tax) related to the restructuring of the Kendall toll with Constellation Energy. This charge is included in Cost of sales. |
| (2) | We recognized a pre-tax charge of approximately $85 million ($54 million after-tax) related to our share of an impairment of assets at West Coast Power, a joint venture with NRG Energy, and an impairment of our investment in West Coast Power. This charge is included in Earnings (losses) from unconsolidated investments. |
| (3) | We recognized a pre-tax loss of approximately $111 million ($70 million after-tax) related to legal and settlement charges. The loss is primarily included in General and administrative expenses, Impairment and other charges and Cost of sales. |
| (4) | We recognized a pre-tax charge of approximately $54 million ($34 million after-tax) relating to the impairment of Illinois Power. This loss is included in Impairment and other charges. |
| (5) | We recognized a pre-tax loss of approximately $58 million ($37 million after-tax) related to the sale of Illinois Power. The loss is primarily included in Gain (loss) on sale of assets, net. |
| (6) | We recognized a pre-tax charge of approximately $14 million ($9 million after-tax) related to the acceleration of debt issuance costs associated with our former $1.1 billion revolving credit facility that was replaced in May 2004 with a $700 million revolving credit facility and $600 million term loan. This charge is included in Interest expense. |
| (7) | We recognized a pre-tax gain of approximately $15 million ($9 million after-tax) on the sale of our interest in the Oyster Creek cogeneration facility. This gain is included in Earnings (losses) from unconsolidated investments. |
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| (8) | We recognized a pre-tax gain of approximately $16 million ($10 million after-tax) on the sale of our Sherman natural gas processing facility. This gain is included in Gain (loss) on sale of assets, net. |
| (9) | We recognized a pre-tax gain of approximately $17 million ($11 million after-tax) on the sale of our remaining financial interest in the Hackberry LNG project. The gain is included in Gain (loss) on sale of assets, net. |
| (10) | We recognized a pre-tax gain of approximately $23 million related to discontinued operations. The gain consists primarily of a $19 million pre-tax gain on our UK CRM business and a $3 million pre-tax gain associated with our communications business. |
| (11) | We recognized a net income tax benefit of approximately $24 million primarily related to a net release of deferred tax capital loss valuation allowances related to gains on asset sales offset by charges resulting from the conclusion of prior year tax audits. A benefit of $52 million is included in Income tax benefit, partially offset by a $28 million charge in Income (loss) from discontinued operations. |
| (12) | We recognized a pre-tax gain of approximately $36 million ($24 million after-tax) on the sale of our interest in the Indian Basin gas processing plant. This gain is included in Gain (loss) on sale of assets, net. |
| (13) | We recognized a pre-tax gain of approximately $75 million ($47 million after-tax) on the sale of our interest in the Joppa power generation facility. This gain is included in Earnings (losses) from unconsolidated investments. |
| (14) | We recognized a pre-tax gain of approximately $88 million ($55 million after-tax) related to our exit from four long-term natural gas transportation contracts. This gain is included in Revenues. |
| (15) | We recognized a pre-tax charge of approximately $311 million ($311 million after-tax) for the impairment of goodwill associated with Illinois Power. This charge is included in Goodwill impairment. |
| (16) | We recognized a pre-tax charge of approximately $218 million ($136 million after-tax) for the impairment of Illinois Power assets. This charge is included in Impairment and other charges. |
| (17) | We recognized a pre-tax charge of approximately $133 million ($84 million after-tax) related to the settlement of three power tolling arrangements with Southern Power for $155 million. This charge is included in Cost of sales. |
| (18) | We recognized a pre-tax charge of approximately $121 million ($76 million after-tax) related to a mark-to-market loss incurred during the twelve months on contracts associated with the Sithe Independence power tolling arrangement. This charge is included in Revenues. |
| (19) | We recognized a pre-tax charge of approximately $50 million ($32 million after-tax) associated with legal charges. This charge is included in General and administrative expenses. |
| (20) | We recognized a pre-tax charge of approximately $34 million ($22 million after-tax) related to the termination of the Batesville tolling arrangement with a subsidiary of Dominion Resources. This charge is included in Cost of sales. |
| (21) | We recognized a pre-tax charge of approximately $30 million ($19 million after-tax) for an agreement reached with the Kroger Company related to four power supply agreements. The charge is included in Revenues. |
| (22) | We recognized a pre-tax loss of approximately $28 million ($19 million after-tax) related to discontinued operations. This loss consists primarily of a $30 million pre-tax loss ($20 million after-tax) from our UK CRM business; a $3 million pre-tax loss ($2 million after-tax) associated with NNG; and a $2 million pre-tax loss ($2 million after-tax) associated with our global liquids business. These losses are offset by a $7 million pre-tax gain ($5 million after-tax) from our global communications business. |
| (23) | We recognized a pre-tax charge of approximately $26 million ($16 million after-tax) related to the impairments of our investments in certain domestic and foreign generation assets. These charges are included in Earnings (losses) from unconsolidated investments. |
| (24) | We recognized a pre-tax charge of approximately $20 million ($13 million after-tax) related to the acceleration of unamortized financing costs and the settlement value of the associated interest rate hedge instruments as part of our August and October 2003 refinancings and a pre-tax charge of approximately $4 million ($3 million after-tax) related to the acceleration of unamortized financing costs as part of our early payment in April 2003 of the Renaissance and Rolling Hills credit facility. These charges are included in Interest expense. |
| (25) | We recognized a pre-tax charge of approximately $20 million ($13 million after-tax) related to our share of a goodwill impairment recorded by West Coast Power, a joint venture with NRG Energy. This charge is included in Earnings (losses) from unconsolidated investments. |
| (26) | We recognized a pre-tax charge of approximately $12 million ($8 million after-tax) related to the impairment of our investment in a fractionator located in the Texas Gulf Coast region. This charge is included in Earnings (losses) from unconsolidated investments. |
| (27) | We recognized an income tax benefit of approximately $33 million primarily related to the release of a deferred tax capital gains valuation allowance. A benefit of $38 million is included in Income tax benefit and the offsetting $5 million charge is included in Income (loss) from discontinued operations. |
| (28) | We recognized a pre-tax gain of approximately $27 million ($18 million after-tax) on the sale of our interest in Hackberry LNG Terminal LLC and associated project development milestones. This gain is included in Gain (loss) on sale of assets, net. |
| (29) | We reflected the rescission of EITF Issue 98-10 effective January 1, 2003 as a cumulative effect of a change in accounting principle. The net impact was a pre-tax benefit of $33 million ($21 million after-tax). We also adopted SFAS No. 143 effective January 1, 2003, and recognized a pre-tax benefit of $54 million ($34 million after-tax) associated with its implementation. Finally, we adopted the provisions of FIN 46 and recognized a pre-tax charge of $23 million ($15 million after-tax) in the fourth quarter of 2003. |
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DYNEGY INC.
SUMMARY CASH FLOW INFORMATION
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Twelve Months Ended December 31, 2004
| |
| | | GEN
| | | NGL
| | | REG
| | | CRM
| | | OTHER
| | | Total
| |
Cash Flow from Operations | | $ | 421 | | | $ | 278 | | | $ | 213 | | | $ | (371 | ) | | $ | (536 | ) | | $ | 5 | |
Capital Expenditures & Business Acquisition Costs | | | (148 | ) | | | (61 | ) | | | (92 | ) | | | — | | | | (13 | ) | | | (314 | ) |
Proceeds from Asset Sales | | | 260 | | | | 99 | | | | 217 | | | | — | | | | — | | | | 576 | |
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|
|
Free Cash Flow (1) (2) | | $ | 533 | | | $ | 316 | | | $ | 338 | | | $ | (371 | ) | | $ | (549 | ) | | $ | 267 | |
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| | | | | | | | | | | | | | | | | | | | | | | |
| | | Twelve Months Ended December 31, 2003
| |
| | | GEN
| | | NGL
| | | REG
| | | CRM
| | OTHER
| | | Total
| |
Cash Flow from Operations | | $ | 428 | | | $ | 186 | | | $ | 67 | | | $ | 496 | | $ | (301 | ) | | $ | 876 | |
Capital Expenditures | | | (151 | ) | | | (51 | ) | | | (126 | ) | | | — | | | (5 | ) | | | (333 | ) |
Proceeds from Asset Sales | | | 47 | | | | 35 | | | | — | | | | — | | | (10 | ) | | | 72 | |
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Free Cash Flow (1) | | $ | 324 | | | $ | 170 | | | $ | (59 | ) | | $ | 496 | | $ | (316 | ) | | $ | 615 | |
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| (1) | Free cash flow is a non-GAAP financial measure. Free cash flow consists of cash flows from operations less capital expenditures and business acquisition costs, net, adjusted for proceeds from asset sales. We use free cash flow to measure the cash generating ability of our operating asset-based energy businesses relative to their 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. |
| (2) | Effective September 30, 2004, we sold Illinois Power, our regulated utility, to Ameren. As such, the REG free cash flow information presented above for the twelve-months ended December 31, 2004 represents activity for the nine-months ended September 30, 2004 due to this sale. |
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DYNEGY INC.
QUANTIFICATION OF EFFECTS OF RESTATEMENT ITEMS
(UNAUDITED) (IN MILLIONS)
The following schedule summarizes the effects of the restatement items described in this press release on the Company’s previously reported net income for the three-month and twelve-month period ended December 31, 2003. This schedule, which has not been audited, reflects the effects of restatements related to (1) the Company’s previously disclosed impairment charge associated with the sale of Illinois Power Company and (2) the Company’s deferred income tax accounts. Please read the Introductory Note to these financial statement schedules for further discussion of these restatement items.
| | | | | | | | |
| | | Three Months Ended
December 31, 2003
| | | Twelve Months Ended
December 31, 2003
| |
Impairment and other charges as originally reported (1) | | $ | (206 | ) | | $ | (200 | ) |
Impairment of Illinois Power | | | (25 | ) | | | (25 | ) |
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Restated impairment and other charges | | $ | (231 | ) | | $ | (225 | ) |
| | |
Income tax benefit (expense) as originally reported (1) | | $ | 137 | | | $ | 246 | |
Impairment of Illinois Power | | | 9 | | | | 9 | |
Deferred income tax accounts | | | (9 | ) | | | (9 | ) |
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Restated income tax benefit (expense) | | $ | 137 | | | $ | 246 | |
| | |
Net income as originally reported (1) | | $ | (529 | ) | | $ | (667 | ) |
Impairment of Illinois Power | | | (16 | ) | | | (16 | ) |
Deferred income tax accounts | | | (9 | ) | | | (9 | ) |
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Restated net income | | $ | (554 | ) | | $ | (692 | ) |
| (1) | As previously reported in Amendment No. 2 on Form 10-K filed January 18, 2005. |
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DYNEGY INC.
OPERATING DATA
| | | | | | | | | | | | |
| | | Three Months Ended December 31,
| | Twelve Months Ended December 31,
|
| | | 2004
| | 2003
| | 2004
| | 2003
|
GEN | | | | | | | | | | | | |
Million Megawatt Hours Generated - Gross | | | 7.9 | | | 9.3 | | | 37.1 | | | 39.1 |
Million Megawatt Hours Generated - Net | | | 7.4 | | | 8.9 | | | 35.3 | | | 37.2 |
| | | | |
Average Natural Gas Price - Henry Hub ($/MMBtu) (1) | | $ | 6.35 | | $ | 5.07 | | $ | 5.89 | | $ | 5.28 |
Average On-Peak Market Power Prices ($/MWh): | | | | | | | | | | | | |
Cinergy | | $ | 43 | | $ | 27 | | $ | 43 | | $ | 37 |
Commonwealth Edison (NI Hub) | | $ | 42 | | $ | 27 | | $ | 42 | | $ | 37 |
Southern | | $ | 49 | | $ | 33 | | $ | 49 | | $ | 41 |
New York - Zone G | | $ | 62 | | $ | 51 | | $ | 62 | | $ | 61 |
ERCOT | | $ | 53 | | $ | 39 | | $ | 51 | | $ | 45 |
SP-15 | | $ | 61 | | $ | 47 | | $ | 55 | | $ | 52 |
| | | | |
NGL | | | | | | | | | | | | |
Field Plant Gross NGL Production (MBbls/d) | | | 57.0 | | | 60.9 | | | 57.3 | | | 59.6 |
Straddle Plant Gross NGL Production (MBbls/d) | | | 29.3 | | | 25.7 | | | 26.6 | | | 25.6 |
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| |
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|
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Total Gross NGL Production | | | 86.3 | | | 86.6 | | | 83.9 | | | 85.2 |
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Natural Gas (Residue) Sales (BBtu/d) | | | 179.7 | | | 195.2 | | | 182.8 | | | 174.4 |
| | | | |
Natural Gas Field Plant Inlet Volumes (MMCFD) | | | 506.9 | | | 597.0 | | | 535.6 | | | 591.0 |
Natural Gas Straddle Plant Inlet Volumes (MMCFD) | | | 1,063.3 | | | 953.7 | | | 990.0 | | | 1,103.1 |
| | |
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| |
|
| |
|
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Total Natural Gas Inlet Volumes | | | 1,570.2 | | | 1,550.7 | | | 1,525.6 | | | 1,694.1 |
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Fractionation Volumes (MBbls/d) | | | 154.7 | | | 190.4 | | | 202.5 | | | 185.3 |
Natural Gas Liquids Sold (MBbls/d) | | | 286.3 | | | 331.5 | | | 282.5 | | | 311.7 |
| | | | |
Average Commodity Prices: | | | | | | | | | | | | |
Crude Oil - WTI ($/Bbl) | | $ | 50.10 | | $ | 29.89 | | $ | 41.43 | | $ | 31.01 |
Natural Gas - Henry Hub ($/MMBtu) (2) | | $ | 7.06 | | $ | 4.58 | | $ | 6.13 | | $ | 5.38 |
Natural Gas Liquids ($/Gal) | | $ | 0.83 | | $ | 0.56 | | $ | 0.71 | | $ | 0.55 |
Fractionation Spread ($/MMBtu) - daily | | $ | 3.11 | | $ | 1.31 | | $ | 2.18 | | $ | 0.79 |
| | | | |
REG (3) | | | | | | | | | | | | |
Electric Sales in KWH (Millions): | | | | | | | | | | | | |
Residential | | | — | | | 1,112 | | | 4,182 | | | 5,309 |
Commercial | | | — | | | 1,095 | | | 3,389 | | | 4,413 |
Industrial | | | — | | | 1,509 | | | 3,859 | | | 6,123 |
Transportation of Customer-Owned Electricity | | | — | | | 590 | | | 2,407 | | | 2,382 |
Other | | | — | | | 82 | | | 287 | | | 374 |
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Total Electricity Delivered | | | — | | | 4,388 | | | 14,124 | | | 18,601 |
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|
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Gas Sales in Therms (Millions): | | | | | | | | | | | | |
Residential | | | — | | | 99 | | | 214 | | | 337 |
Commercial | | | — | | | 47 | | | 85 | | | 145 |
Industrial | | | — | | | 13 | | | 40 | | | 70 |
Transportation of Customer-Owned Gas | | | — | | | 56 | | | 171 | | | 226 |
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| |
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|
| |
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Total Gas Delivered | | | — | | | 215 | | | 510 | | | 778 |
| | |
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| |
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| |
|
| |
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|
Cooling Degree Days - Actual | | | — | | | 9 | | | 932 | | | 980 |
Cooling Degree Days - 10 year rolling average | | | — | | | — | | | 1,236 | | | 1,214 |
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Heating Degree Days - Actual | | | — | | | 1,764 | | | 3,145 | | | 5,256 |
Heating Degree Days - 10 year rolling average | | | — | | | 1,912 | | | 3,190 | | | 4,930 |
| (1) | Calculated as the average of the daily gas prices for the period. |
| (2) | Calculated as the average of the first of the month prices for the period. |
| (3) | Effective September 30, 2004, we sold Illinois Power, our regulated utility, to Ameren. As such, the REG operating statistics for the twelve-months ended December 31, 2004 only include operating statistics for the nine-months ended September 30, 2004. |
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DYNEGY INC.
2005 EARNINGS GUIDANCE ESTIMATES (1)
(IN MILLIONS)
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| | | GEN
| | | NGL
| | | CRM
| | | OTHER
| | | Total
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EBITDA (2) | | $ | 120-130 | | | $ | 285-295 | | | $ | (80 | ) | | $ | (95-90 | ) | | $ | 230-255 | |
Depreciation and Amortization | | | (210 | ) | | | (85 | ) | | | — | | | | (15 | ) | | | (310 | ) |
Interest Expense | | | | | | | | | | | | | | | | | | | (425 | ) |
Income Tax Benefit | | | | | | | | | | | | | | | | | | | 192-183 | |
Preferred stock dividends | | | | | | | | | | | | | | | | | | | (22 | ) |
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Net Loss | | | | | | | | | | | | | | | | | | $ | (335-319 | ) |
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2005 CASH FLOW GUIDANCE ESTIMATES (1)
(IN MILLIONS)
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| | | GEN
| | | NGL
| | | CRM
| | | OTHER
| | | Total
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Cash Flow from Operations | | $ | 315-320 | | | $ | 325-330 | | | $ | (66 | ) | | $ | (400-395 | ) | | $ | 174-189 | |
Capital Expenditures and Business Acquisitions | | | (300 | ) | | | (78 | ) | | | — | | | | (11 | ) | | | (389 | ) |
Proceeds from Asset Sales | | | — | | | | — | | | | — | | | | 110 | | | | 110 | |
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Free Cash Flow (3) | | $ | 15-20 | | | $ | 247-252 | | | $ | (66 | ) | | $ | (301-296 | ) | | $ | (105-90 | ) |
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| (1) | Estimates are provided as a guide for forecasted 2005 consolidated results on an as-reported GAAP basis. Forecasted segment results are intended to reflect management’s estimate of the breakdown of its consolidated results and are subject to change. Estimates do not incorporate assumptions for potential items such as legal settlements, tolling settlements, capital-raising activities or other restructuring events. |
| (2) | EBITDA is a non-GAAP financial measure. EBITDA consists of Operating income (loss) plus Depreciation and amortization expense; Earnings from unconsolidated investments; Accumulated distributions associated with trust preferred securities; Other income and expense, net; Income (loss) from discontinued operations (pre-tax) and Cumulative effect of change in accounting principles (pre-tax). Consolidated EBITDA can be reconciled to Net income (loss) using the following calculation: Net income (loss) less Income (loss) from discontinued operations and Income tax benefit (expense) from continuing operations, 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. |
| (3) | Free cash flow is a non-GAAP financial measure. Free cash flow consists of cash flows from operations less capital expenditures and business acquisition costs, adjusted for proceeds from asset sales. We use free cash flow to measure the cash generating ability of our operating asset-based energy businesses relative to their 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. |
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