Exhibit 99.1
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| FOR IMMEDIATE RELEASE | | NR06-06 |
DYNEGY ANNOUNCES 2005 RESULTS
| | • | | 2005 results benefited from higher prices realized in Midwest, Northeast and South regions |
| | • | | Year marked by the successful completion of key self-restructuring initiatives: |
| | • | | Settled significant legacy litigation, including shareholder class action and Midwest environmental litigation |
| | • | | Sold Midstream business for $2.4 billion in cash |
| | • | | Reached agreement to terminate Sterlington power tolling obligation |
| | • | | Year-end liquidity was $1.6 billion |
| | • | | Updated estimates for 2006 provided |
HOUSTON (March 8, 2006)– Dynegy Inc. (NYSE: DYN) today reported net income applicable to common stockholders of $88 million or $0.23 per diluted share for 2005, which included net income of $300 million for the fourth quarter 2005. This compares to a net loss applicable to common stockholders of $37 million or $(0.10) per diluted share for 2004, which included a net loss of $176 million for the fourth quarter 2004.
Financial results for 2005 included a $1.1 billion pre-tax gain on the sale of the Midstream business and $102 million in tax benefits associated with the net reduction of a deferred tax valuation allowance primarily related to capital loss carryforwards realized on the sale of Midstream. The gain and benefit were partially offset by previously announced pre-tax charges of $364 million related to the termination of the Sterlington power tolling obligation and $169 million related to the purchase of the Independence facility, which resulted in the Independence power tolling obligations becoming intercompany agreements. Other 2005 pre-tax charges included legal and settlement charges of $287 million, which largely related to the settlement of shareholder class action litigation, asset impairments and other charges totaling $67 million.
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| DYNEGY ANNOUNCES 2005 RESULTS | | NR06-06 |
| 2-2-2-2-2 | | |
“2005 was a pivotal year for Dynegy in terms of completing key self-restructuring initiatives and shifting our approach from the resolution of legacy issues to the future where running and growing our business is the primary focus,” said Bruce A. Williamson, Chairman and Chief Executive Officer of Dynegy Inc. “It was also a year that saw us operate our business in a safe, efficient and reliable manner, capitalize on near-term market opportunities, maintain our emphasis on financial discipline, and manage costs and capital expenditures to maximize liquidity and financial flexibility.
“Going forward, we will continue to market our production through a commercial strategy that emphasizes producing and selling energy in a timely and efficient manner to meet market requirements, while maintaining a strong balance sheet,” Williamson added. “We believe this is a proven business model that has withstood the test of time in other commodity-cyclical energy sectors, and, when coupled with our strong operational performance, will produce long-term value for our company’s investors as the economy strengthens and power markets continue to recover.”
Year-Over-Year Comparison
A comparison of the company’s 2005 and 2004 results is set forth in the table below (in millions of dollars, except per share amounts):
| | | | | | | | |
| | | 2005 | | | 2004 | |
Loss from continuing operations before income taxes | | $ | (1,199 | ) | | $ | (352 | ) |
Income tax benefit from continuing operations | | | 396 | | | | 172 | |
Income from discontinued operations, net of tax | | | 918 | | | | 165 | |
Cumulative effect of change in accounting principle, net of tax | | | (5 | ) | | | — | |
| | | | | | | | |
Net income (loss) | | | 110 | | | | (15 | ) |
Less: Preferred stock dividends | | | 22 | | | | 22 | |
| | | | | | | | |
Net income (loss) applicable to common stockholders | | $ | 88 | | | $ | (37 | ) |
Basic earnings (loss) per share | | $ | 0.23 | | | $ | (0.10 | ) |
Diluted earnings (loss) per share | | | 0.23 | | | | (0.10 | ) |
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| DYNEGY ANNOUNCES 2005 RESULTS | | NR06-06 |
| 3-3-3-3-3 | | |
Annual Business Results
Following are year-end 2005 business results compared to year-end 2004. Because Illinois Power was sold to Ameren Corporation in the third quarter 2004, Regulated Energy Delivery results are not included in the company’s 2005 business segment discussions. However, 2004 financials include results from the Regulated Energy Delivery business.
Power Generation Business
Earnings before interest, taxes and depreciation and amortization (EBITDA) from the power generation business was $404 million for 2005, compared to $547 million for 2004. Results for 2004 benefited from $90 million in pre-tax gains related to the sale of the company’s interests in the Joppa and Oyster Creek generation facilities, as well as earnings from West Coast Power of $165 million, which were offset by an $85 million impairment of the company’s West Coast Power investment.
For the 12 months ended Dec. 31, 2005, cash flow from operations was $472 million, while capital expenditures were $143 million, business acquisition costs related to Sithe Energies were $120 million and changes in restricted cash and other were $14 million. Free cash flow for the power generation business was an inflow of approximately $196 million.
Power generation results are now being reported on a regional basis, with segments including the Midwest, Northeast and South.
Midwest segment
EBITDA attributed to the Midwest segment was $355 million in 2005, compared to EBITDA of $430 million in 2004, which included the gain on the sale of the Joppa facility. This segment comprises 13 facilities located in Illinois (9 facilities), Michigan (1 facility), Ohio (1 facility) and Kentucky (2 facilities), with a total capacity of 7,369 megawatts.
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| DYNEGY ANNOUNCES 2005 RESULTS | | NR06-06 |
| 4-4-4-4-4 | | |
Average on-peak market prices in NI Hub/Com Ed and Cinergy were 48 percent and 49 percent higher, respectively, than during 2004.
Sales volumes generated by Midwest facilities rose to 21.9 million megawatt hours in 2005 compared to 20.8 million megawatt hours in 2004, excluding volumes from assets sold in 2004. Volumes supplied to AmerenIP under Dynegy’s two-year power purchase agreement were 25 percent higher in 2005 than volumes provided to Dynegy’s former Regulated Energy Delivery business in 2004. While profitable, energy sold to AmerenIP under the power purchase agreement is priced significantly below current market prices. The power purchase agreement expires at the end of 2006.
Midwest milestones during 2005 included the conversion of the company’s Havana facility to lower-emission Powder River Basin (PRB) coal. In addition, the Vermilion facility was substantially converted to PRB during 2005. Today, all of the company’s Illinois coal-fired facilities use PRB coal as a fuel source. In another milestone, the company settled environmental litigation related to its Illinois coal-fired fleet. In addition, during the fourth quarter, the company announced that it has agreed to acquire NRG Energy’s 50 percent ownership interest in the Rocky Road natural gas-fired peaking facility near Chicago. This transaction, which is expected to close in early 2006, will provide Dynegy with full ownership interest in the 364-megawatt Rocky Road facility and a related long-term capacity contract. The Rocky Road facility, as well as the company’s other fully owned peaking facilities in the Midwest segment, all operated at various times in 2005 as a result of the implementation of the Midwest Independent System Operator dispatch structure and favorable weather conditions. Midwest peaking facilities provided $16 million more in earnings than in 2004 before a $5 million charge in 2005 for an inventory adjustment.
Northeast segment
EBITDA attributed to Dynegy’s Northeast segment was $53 million in 2005, compared to EBITDA of $31 million in 2004. This segment includes the Roseton, Danskammer and Independence facilities in New York, which have a combined generating capacity of 2,803 megawatts.
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| DYNEGY ANNOUNCES 2005 RESULTS | | NR06-06 |
| 5-5-5-5-5 | | |
Average on-peak market prices in New York Zone G (Roseton and Danskammer) and New York Zone A (Independence) were 48 percent and 43 percent higher, respectively, than in 2004. In addition, natural gas and fuel oil prices averaged 50 percent and 43 percent higher, respectively, than in 2004.
Sales volumes generated by Northeast facilities rose to 8.3 million megawatt hours in 2005 compared to 6 million megawatt hours in 2004, largely as a result of the acquisition of the Independence combined-cycle facility during the first quarter 2005. Sales volumes were slightly higher year-over-year for the Danskammer facility, but compressed spark spreads resulted in lower volumes generated by the Roseton facility. Volumes produced by the two plants were essentially flat for the year.
Northeast segment milestones during 2005 included the acquisition of the natural gas-fired Independence facility, which diversifies the Northeast segment’s fuel types among natural gas, fuel oil and coal.
South segment
The loss before interest, taxes and depreciation and amortization attributed to the South segment was $4 million in 2005, compared to EBITDA of $86 million in 2004. Results for 2004 included earnings from West Coast Power related to a California Department of Water Resources (CDWR) contract that ended in December 2004. This segment primarily includes the 610-megawatt CoGen Lyondell combined-cycle facility in Texas, peaking facilities in three other states and Dynegy’s interest in West Coast Power, which the company has agreed to sell to NRG Energy.
Average on-peak market prices in the Electric Reliability Council of Texas (ERCOT) were 57 percent higher than during 2004. Results benefited from higher power prices, improved spark spreads and stronger sales of ancillary services from CoGen Lyondell.
Sales volumes generated by South segment facilities decreased from 5.8 million megawatt hours in 2004 to 5.3 million megawatt hours in 2005, excluding volumes from assets sold in 2004, primarily as a result of decreased volumes related to the expiration of the CDWR contract.
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| DYNEGY ANNOUNCES 2005 RESULTS | | NR06-06 |
| 6-6-6-6-6 | | |
South segment milestones during 2005 included a new, 15-year commercial arrangement where the company’s CoGen Lyondell facility will provide electricity and steam to Lyondell Chemical Company under a contract providing for fuel cost recovery and a market-based margin. The new contract begins on Jan. 1, 2007.
Customer Risk Management Business
The loss before interest, taxes and depreciation and amortization from the Customer Risk Management segment totaled $640 million during 2005, compared to a $101 million loss before interest, taxes and depreciation and amortization in 2004. The 2005 loss included the previously announced $364 million and $169 million charges, respectively, related to the agreement to terminate the Sterlington power tolling obligation and the purchase of the Independence facility. This segment’s results reflect the impact of fixed payments on the company’s remaining power tolling arrangements in the segment in excess of realized margins on power generated and sold.
Midstream Business
The sale of the Midstream business to Targa Resources was completed on Oct. 31, 2005. EBITDA from the Midstream segment was $1.3 billion for the 10 months of 2005 that Dynegy owned the business, compared to EBITDA of $369 million for 2004. 2005 results included a gain on sale of approximately $1.1 billion.
For the 10 months of 2005, cash flow from operations was $288 million and proceeds from asset sales were $2.4 billion, while capital expenditures were $45 million. Free cash flow for the Midstream segment was an inflow of $2.6 billion.
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| DYNEGY ANNOUNCES 2005 RESULTS | | NR06-06 |
| 7-7-7-7-7 | | |
Other
In the Other segment, which consists primarily of general and administrative expenses and legal and settlement charges, the company recorded a $355 million loss before interest, taxes and depreciation and amortization for 2005, compared to a $240 million loss for 2004. The loss in 2005 related primarily to a $249 million charge for the settlement of the company’s shareholder class action litigation and associated legal expenses, compared to $92 million in legal and settlement expenses in 2004. The 2005 loss was partially offset by lower general and administrative costs and lower insurance costs.
Consolidated Interest and Taxes
Interest expense totaled $389 million in 2005, compared to $453 million in 2004. The decrease is primarily attributable to lower average debt balances in 2005, resulting from the sale of Illinois Power in September 2004 and other debt repayments in 2004, partially offset by the acquisition of the Independence facility, increased interest rates and decreased amortization of debt issuance costs in 2005.
The 2005 tax benefit from continuing operations of $396 million includes a $32 million charge associated with a deferred tax valuation allowance. The 2004 tax benefit from continuing operations of $172 million includes a $36 million benefit primarily related to the release of a deferred tax valuation allowance. After adjusting for these items, the effective tax rates for 2005 and 2004 were 36 percent and 39 percent, respectively.
Liquidity
As of Dec. 31, 2005, Dynegy’s liquidity was approximately $1.6 billion. This consisted of approximately $1.5 billion in cash on hand and $71 million in unused availability under the company’s cash collateralized letter of credit facility.
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| DYNEGY ANNOUNCES 2005 RESULTS | | NR06-06 |
| 8-8-8-8-8 | | |
On March 6, 2006 the company announced the completion of a three-year, $400 million revolving credit facility. The new facility amends and restates the credit facility last amended on Oct. 31, 2005, and eliminates the requirement to cash collateralize the facility. The new credit facility, which is undrawn, is available for letters of credit and general corporate purposes. As of March 7, 2006, after also reflecting the announced completion of the Sterlington power tolling settlement, liquidity was approximately $1.7 billion.
Cash Flow
Cash flow from operations, including working capital changes, totaled an outflow of $30 million for the 12 months ended Dec. 31, 2005. This consisted of cash inflows of $472 million from the power generation business and $288 million from the former Midstream business. These cash inflows were more than offset by outflows of $769 million in the Other segment resulting from payments to settle the shareholder class action litigation, interest payments and general and administrative expenses. In addition, the legacy Customer Risk Management business had cash outflows of $21 million primarily from payments related to the company’s remaining tolling arrangements, partially offset by the return of cash collateral.
Cash flow from investing activities for the 12 months ended Dec. 31, 2005, totaled $1.8 billion. This consisted of $2.5 billion in proceeds from asset sales, primarily relating to the sale of the Midstream business, partially offset by $664 million in capital expenditures, business acquisition costs and changes in restricted cash.
For the 12 months ended Dec. 31, 2005, Dynegy’s free cash flow (cash from operations plus cash flow from investing activities) was $1.8 billion.
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| DYNEGY ANNOUNCES 2005 RESULTS | | NR06-06 |
| 9-9-9-9-9 | | |
2006 Cash Flow and Earnings Estimates
On Nov. 8, 2005, Dynegy provided earnings and cash flow estimates for 2006. Those estimates were based on quoted forward commodity price curves as of Oct. 4, 2005. In connection with today’s announcement, Dynegy is updating its 2006 estimates to reflect quoted forward commodity price curves as of Feb. 7, 2006. These commodity price curves were derived from standard market quotes and are not necessarily indicative of management’s expectations for commodity price movements during the rest of 2006; rather, they represent commodity price estimates as of Feb. 7, 2006 and are intended to provide a basis on which the effects of future commodity price movements can be measured. Dynegy’s updated estimates also reflect current estimates and assumptions regarding, among other things, sales volumes, fuel costs and other operational activities, as well as the financial results of the termination of the Sterlington power tolling obligation and the pending sale of the company’s interest in West Coast Power.
Taking these factors into consideration, the company’s estimated free cash flow for 2006 is an inflow of $85 million to $195 million, compared to the previous estimate of an inflow of $20 million to $130 million. The current 2006 estimated net loss applicable to common stockholders is $65 million to $130 million, compared to the previously estimated net loss of $5 million to $75 million. Estimated EBITDA for the company’s power generation business is $565 million to $660 million, compared to the previous estimate of $725 million to $825 million.
Investor Conference Call/Web Cast
Dynegy will discuss its 2005 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.
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| DYNEGY ANNOUNCES 2005 RESULTS | | NR06-06 |
| 10-10-10-10-10 | | |
About Dynegy Inc.
Dynegy Inc. produces and sells electric energy, capacity and ancillary services in key U.S. markets. The company’s power generation portfolio consists of more than 12,600 megawatts of baseload, intermediate and peaking power plants fueled by a mix of coal, fuel oil and natural gas.
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 company’s strategy of running and growing its power generation business and the anticipated results of its business model, indications of a recovering power market environment, the agreed upon purchase and sale transactions involving interests in the West Coast Power and Rocky Road facilities, the contract for our CoGen Lyondell facility, and Dynegy’s estimated financial results for 2006. Historically, Dynegy’s performance has deviated, in some cases materially, from its earnings and cash flow estimates, and Dynegy cautions that actual future results may vary materially from those expressed or implied in any forward-looking statements, particularly as a result of changes in commodity prices. 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 impacts of hedging and the strategy of reduced hedging; Dynegy’s ability to successfully complete its exit from the Customer Risk Management business and fund the costs associated with this exit; the availability, ability to consummate, and effects of commercial and strategic growth opportunities for Dynegy’s power generation business; Dynegy’s ability to address its substantial leverage on favorable terms; 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 blackouts or other unscheduled outages; Dynegy’s ability to fund the projects mandated by the Baldwin consent decree; and uncertainties regarding environmental regulations, litigation and other legal or regulatory developments affecting Dynegy’s businesses, including litigation relating to the western power and natural gas markets and master netting agreement matters. More information about the risks and uncertainties relating to these forward-looking statements is found in Dynegy’s SEC filings, including its Annual Report on Form 10-K for the year ended Dec. 31, 2004, its Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 and its Current Reports, which are available free of charge on the SEC’s web site at http://www.sec.gov. Dynegy expressly disclaims any obligation to update any forward-looking statements contained in this news release to reflect events or circumstances that may arise after the date of this release, except as otherwise required by applicable law.
Dynegy’s 2005 independent audit is not complete, and Dynegy expects to file its 2005 Form 10-K with the SEC upon completion of this audit on or before the applicable SEC filing deadline. The 2005 Form 10-K will contain audited financial statements and other required disclosures, including any changes that may be identified relative to the results reported herein. DYNC
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DYNEGY INC.
REPORTED UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE DATA)
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| | | Three Months Ended
December 31, | | | Twelve Months Ended
December 31, | |
| | | 2005 | | | 2004 | | | 2005 | | | 2004 | |
Revenues | | $ | 622 | | | $ | 327 | | | $ | 2,313 | | | $ | 2,451 | |
Cost of sales, exclusive of depreciation and amortization shown separately below | | | (934 | ) | | | (418 | ) | | | (2,416 | ) | | | (1,850 | ) |
Depreciation and amortization expense | | | (55 | ) | | | (52 | ) | | | (220 | ) | | | (235 | ) |
Impairment and other charges | | | (40 | ) | | | — | | | | (46 | ) | | | (78 | ) |
Loss on sale of assets, net | | | — | | | | (19 | ) | | | (1 | ) | | | (58 | ) |
General and administrative expenses | | | (47 | ) | | | (99 | ) | | | (468 | ) | | | (330 | ) |
| | | | | | | | | | | | | | | | |
Operating loss | | | (454 | ) | | | (261 | ) | | | (838 | ) | | | (100 | ) |
Earnings (losses) from unconsolidated investments | | | (12 | ) | | | 5 | | | | 2 | | | | 192 | |
Interest expense | | | (105 | ) | | | (67 | ) | | | (389 | ) | | | (453 | ) |
Other income and expense, net | | | 17 | | | | 3 | | | | 26 | | | | 9 | |
| | | | | | | | | | | | | | | | |
Loss from continuing operations before income taxes | | | (554 | ) | | | (320 | ) | | | (1,199 | ) | | | (352 | ) |
Income tax benefit | | | 168 | | | | 97 | | | | 396 | | | | 172 | |
| | | | | | | | | | | | | | | | |
Loss from continuing operations | | | (386 | ) | | | (223 | ) | | | (803 | ) | | | (180 | ) |
Income from discontinued operations, net of tax | | | 696 | | | | 52 | | | | 918 | | | | 165 | |
Cumulative effect of change in accounting principle, net of tax | | | (5 | ) | | | — | | | | (5 | ) | | | — | |
| | | | | | | | | | | | | | | | |
Net income (loss) | | $ | 305 | | | $ | (171 | ) | | $ | 110 | | | $ | (15 | ) |
| | | | | | | | | | | | | | | | |
Less: Preferred stock dividends | | | 5 | | | | 5 | | | | 22 | | | | 22 | |
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Net income (loss) applicable to common stockholders | | $ | 300 | | | $ | (176 | ) | | $ | 88 | | | $ | (37 | ) |
| | | | | | | | | | | | | | | | |
Earnings (loss) before interest, taxes, and depreciation and amortization (EBITDA) (1) | | $ | 714 | | | $ | (107 | ) | | $ | 750 | | | $ | 727 | |
Basic earnings (loss) per share: | | | | | | | | | | | | | | | | |
Loss from continuing operations (2) | | $ | (0.98 | ) | | $ | (0.59 | ) | | $ | (2.13 | ) | | $ | (0.52 | ) |
Income from discontinued operations | | | 1.74 | | | | 0.14 | | | | 2.37 | | | | 0.43 | |
Cumulative effect of change in accounting principle | | | (0.01 | ) | | | — | | | | (0.01 | ) | | | — | |
| | | | | | | | | | | | | | | | |
Basic earnings (loss) per share | | $ | 0.75 | | | $ | (0.46 | ) | | $ | 0.23 | | | $ | (0.10 | ) |
| | | | | | | | | | | | | | | | |
Diluted earnings (loss) per share: | | | | | | | | | | | | | | | | |
Loss from continuing operations (2) | | $ | (0.98 | ) | | $ | (0.60 | ) | | $ | (2.13 | ) | | $ | (0.53 | ) |
Income from discontinued operations | | | 1.74 | | | | 0.14 | | | | 2.37 | | | | 0.43 | |
Cumulative effect of change in accounting principle | | | (0.01 | ) | | | — | | | | (0.01 | ) | | | — | |
| | | | | | | | | | | | | | | | |
Diluted earnings (loss) per share | | $ | 0.75 | | | $ | (0.46 | ) | | $ | 0.23 | | | $ | (0.10 | ) |
| | | | | | | | | | | | | | | | |
Basic shares outstanding | | | 398 | | | | 379 | | | | 387 | | | | 378 | |
Diluted shares outstanding | | | 524 | | | | 505 | | | | 513 | | | | 504 | |
| (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. |
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| | | Three Months Ended
December 31, | | | Twelve Months Ended
December 31, | |
| | | 2005 | | | 2004 | | | 2005 | | | 2004 | |
Operating loss | | $ | (454 | ) | | $ | (261 | ) | | $ | (838 | ) | | $ | (100 | ) |
Add: Depreciation and amortization expense, a component of operating loss | | | 55 | | | | 52 | | | | 220 | | | | 235 | |
Earnings (losses) from unconsolidated investments | | | (12 | ) | | | 5 | | | | 2 | | | | 192 | |
Other income and expense, net | | | 17 | | | | 3 | | | | 26 | | | | 9 | |
EBITDA from discontinued operations (3) | | | 1,115 | | | | 94 | | | | 1,347 | | | | 391 | |
Cumulative effect of change in accounting principle, pre-tax | | | (7 | ) | | | — | | | | (7 | ) | | | — | |
| | | | | | | | | | | | | | | | |
Earnings before interest, taxes, and depreciation and amortization (EBITDA) | | | 714 | | | | (107 | ) | | | 750 | | | | 727 | |
| | | | |
Depreciation and amortization expense, a component of operating loss | | | (55 | ) | | | (52 | ) | | | (220 | ) | | | (235 | ) |
Depreciation and amortization expense from discontinued operations | | | (1 | ) | | | (22 | ) | | | (38 | ) | | | (88 | ) |
Interest expense from continuing operations | | | (105 | ) | | | (67 | ) | | | (389 | ) | | | (453 | ) |
Interest expense from discontinued operations | | | (13 | ) | | | (11 | ) | | | (53 | ) | | | (27 | ) |
Income tax benefit from continuing operations | | | 168 | | | | 97 | | | | 396 | | | | 172 | |
Income tax expense from discontinued operations | | | (405 | ) | | | (9 | ) | | | (338 | ) | | | (111 | ) |
Income tax benefit on cumulative effect of change in accounting principle | | | 2 | | | | — | | | | 2 | | | | — | |
| | | | | | | | | | | | | | | | |
Net income (loss) | | $ | 305 | | | $ | (171 | ) | | $ | 110 | | | $ | (15 | ) |
| | | | | | | | | | | | | | | | |
| (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. |
| (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, | |
| | | 2005 | | | 2004 | | | 2005 | | | 2004 | |
EBITDA from discontinued operations | | $ | 1,115 | | | $ | 94 | | | $ | 1,347 | | | $ | 391 | |
Depreciation and amortization expense from discontinued operations | | | (1 | ) | | | (22 | ) | | | (38 | ) | | | (88 | ) |
Interest expense from discontinued operations | | | (13 | ) | | | (11 | ) | | | (53 | ) | | | (27 | ) |
Income tax expense from discontinued operations | | | (405 | ) | | | (9 | ) | | | (338 | ) | | | (111 | ) |
| | | | | | | | | | | | | | | | |
Income from discontinued operations, net of tax | | $ | 696 | | | $ | 52 | | | $ | 918 | | | $ | 165 | |
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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, | |
| | | 2005 | | | 2004 | | | 2005 | | | 2004 | |
Loss from continuing operations | | $ | (386 | ) | | $ | (223 | ) | | $ | (803 | ) | | $ | (180 | ) |
Less: convertible preferred stock dividends | | | 5 | | | | 5 | | | | 22 | | | | 22 | |
| | | | | | | | | | | | | | | | |
Loss from continuing operations for basic loss per share | | | (391 | ) | | | (228 | ) | | | (825 | ) | | | (202 | ) |
Effect of dilutive securities: | | | | | | | | | | | | | | | | |
Interest on convertible subordinated debentures | | | 2 | | | | 2 | | | | 7 | | | | 7 | |
Dividends on Series C convertible preferred stock | | | 5 | | | | 5 | | | | 22 | | | | 22 | |
| | | | | | | | | | | | | | | | |
Loss from continuing operations for diluted loss per share | | $ | (384 | ) | | $ | (221 | ) | | $ | (796 | ) | | $ | (173 | ) |
| | | | | | | | | | | | | | | | |
Basic weighted-average shares | | | 398 | | | | 379 | | | | 387 | | | | 378 | |
Effect of dilutive securities: | | | | | | | | | | | | | | | | |
Stock options and restricted stock | | | 2 | | | | 2 | | | | 2 | | | | 2 | |
Convertible subordinated debentures | | | 55 | | | | 55 | | | | 55 | | | | 55 | |
Series C convertible preferred stock | | | 69 | | | | 69 | | | | 69 | | | | 69 | |
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Diluted weighted-average shares | | | 524 | | | | 505 | | | | 513 | | | | 504 | |
| | | | | | | | | | | | | | | | |
Loss per share from continuing operations: | | | | | | | | | | | | | | | | |
Basic | | $ | (0.98 | ) | | $ | (0.60 | ) | | $ | (2.13 | ) | | $ | (0.53 | ) |
| | | | | | | | | | | | | | | | |
Diluted (1) | | $ | (0.98 | ) | | $ | (0.60 | ) | | $ | (2.13 | ) | | $ | (0.53 | ) |
| | | | | | | | | | | | | | | | |
| (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, 2005 and December 31, 2004. |
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DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended December 31, 2005 | |
| | | Power Generation | | | | | | | | | | | | | | | |
| | | GEN - MW | | | GEN - NE | | | GEN - SO | | | CRM | | | NGL | | REG | | | 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 | ) | | $ | 1,112 | | $ | — | | | $ | (26 | ) | | $ | 714 | |
Depreciation and amortization expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (56 | ) |
Interest expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (118 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Pre-tax income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 540 | |
Income tax expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (235 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 305 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| | | Three Months Ended December 31, 2004 | |
| | | Power Generation | | | | | | | | | | | | | | | |
| | | GEN - MW | | | GEN - NE | | | GEN - SO | | | CRM | | | NGL | | REG | | | OTHER | | | Total | |
Generation | | $ | 36 | | | $ | (13 | ) | | $ | (19 | ) | | | | | | | | | | | | | | | | | $ | 4 | |
Regulated Energy Delivery | | | | | | | | | | | | | | | | | | | | | $ | (19 | ) | | | | | | | (19 | ) |
Customer Risk Management | | | | | | | | | | | | | | $ | (163 | ) | | | | | | | | | | | | | | (163 | ) |
Other | | | | | | | | | | | | | | | | | | | | | | | | | $ | (83 | ) | | | (83 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating income (loss) | | | 36 | | | | (13 | ) | | | (19 | ) | | | (163 | ) | | $ | — | | | (19 | ) | | | (83 | ) | | $ | (261 | ) |
Earnings from unconsolidated investments | | | — | | | | — | | | | 5 | | | | — | | | | — | | | — | | | | — | | | | 5 | |
Other items, net | | | — | | | | — | | | | 1 | | | | (2 | ) | | | — | | | — | | | | 4 | | | | 3 | |
Add: Depreciation and amortization expense, a component of operating income (loss) | | | 39 | | | | 3 | | | | 4 | | | | — | | | | — | | | — | | | | 6 | | | | 52 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EBITDA from continuing operations (1) | | | 75 | | | | (10 | ) | | | (9 | ) | | | (165 | ) | | | — | | | (19 | ) | | | (73 | ) | | | (201 | ) |
EBITDA from discontinued operations, pre-tax (2) | | | — | | | | | | | | — | | | | 2 | | | | 92 | | | — | | | | — | | | | 94 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EBITDA (1) | | $ | 75 | | | $ | (10 | ) | | $ | (9 | ) | | $ | (163 | ) | | $ | 92 | | $ | (19 | ) | | $ | (73 | ) | | $ | (107 | ) |
Depreciation and amortization expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (74 | ) |
Interest expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (78 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Pre-tax loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (259 | ) |
Income tax benefit | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 88 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | (171 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (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, 2005 | |
| | | Power Generation | | | | | | | | | | | | | | |
| | | GEN - MW | | | GEN - NE | | | GEN - SO | | | CRM | | | NGL | | REG | | 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 | ) | | $ | 1,341 | | $ | — | | $ | (355 | ) | | $ | 750 | |
Depreciation and amortization expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (258 | ) |
Interest expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (442 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Pre-tax income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 50 | |
Income tax benefit | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 60 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net income | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 110 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| | | Twelve Months Ended December 31, 2004 | |
| | | Power Generation | | | | | | | | | | | | | | |
| | | GEN - MW | | | GEN - NE | | | GEN - SO | | | CRM | | | NGL | | REG | | OTHER | | | Total | |
Generation | | $ | 194 | | | $ | 21 | | | $ | (52 | ) | | | | | | | | | | | | | | | | $ | 163 | |
Regulated Energy Delivery | | | | | | | | | | | | | | | | | | | | | $ | 139 | | | | | | | 139 | |
Customer Risk Management | | | | | | | | | | | | | | $ | (118 | ) | | | | | | | | | | | | | (118 | ) |
Other | | | | | | | | | | | | | | | | | | | | | | | | $ | (284 | ) | | | (284 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating income (loss) | | | 194 | | | | 21 | | | | (52 | ) | | | (118 | ) | | $ | — | | | 139 | | | (284 | ) | | $ | (100 | ) |
Earnings from unconsolidated investments | | | 80 | | | | — | | | | 112 | | | | — | | | | — | | | — | | | — | | | | 192 | |
Other items, net | | | — | | | | — | | | | 1 | | | | (3 | ) | | | — | | | 3 | | | 8 | | | | 9 | |
Add: Depreciation and amortization expense, a component of operating income (loss) | | | 156 | | | | 10 | | | | 25 | | | | 1 | | | | — | | | 10 | | | 33 | | | | 235 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EBITDA from continuing operations (1) | | | 430 | | | | 31 | | | | 86 | | | | (120 | ) | | | — | | | 152 | | | (243 | ) | | | 336 | |
EBITDA from discontinued operations, pre-tax (2) | | | — | | | | — | | | | — | | | | 19 | | | | 369 | | | — | | | 3 | | | | 391 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EBITDA (1) | | $ | 430 | | | $ | 31 | | | $ | 86 | | | $ | (101 | ) | | $ | 369 | | $ | 152 | | $ | (240 | ) | | $ | 727 | |
Depreciation and amortization expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (323 | ) |
Interest expense | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (480 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Pre-tax loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (76 | ) |
Income tax benefit | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 61 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | (15 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (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, 2005 | |
| | | Power Generation | | | | | | | | | | | | | | | |
| | | GEN - MW | | | GEN - NE | | GEN - SO | | | CRM | | | NGL | | REG | | | OTHER | | | Total | |
Sterlington toll settlement charge (1) | | $ | — | | | $ | — | | $ | — | | | $ | (364 | ) | | $ | — | | $ | — | | | $ | — | | | $ | (364 | ) |
Asset impairment (2) | | | (29 | ) | | | — | | | — | | | | — | | | | — | | | — | | | | — | | | | (29 | ) |
Impairment of generation investments (3) | | | — | | | | — | | | (19 | ) | | | — | | | | — | | | — | | | | — | | | | (19 | ) |
Restructuring charges (4) | | | — | | | | — | | | — | | | | — | | | | — | | | — | | | | (11 | ) | | | (11 | ) |
Legal and settlement charges (5) | | | — | | | | — | | | — | | | | (9 | ) | | | — | | | — | | | | — | | | | (9 | ) |
Taxes (6) | | | — | | | | — | | | — | | | | — | | | | — | | | — | | | | (23 | ) | | | (23 | ) |
Discontinued operations (7) | | | — | | | | — | | | — | | | | 3 | | | | 1,098 | | | — | | | | — | | | | 1,101 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total | | $ | (29 | ) | | $ | — | | $ | (19 | ) | | $ | (370 | ) | | $ | 1,098 | | $ | — | | | $ | (34 | ) | | $ | 646 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| | | Three Months Ended December 31, 2004 | |
| | | Power Generation | | | | | | | | | | | | | | | |
| | | GEN - MW | | | GEN - NE | | GEN - SO | | | CRM | | | NGL | | REG | | | OTHER | | | Total | |
Kendall toll restructuring (8) | | $ | — | | | $ | — | | $ | — | | | $ | (115 | ) | | $ | — | | $ | — | | | $ | — | | | $ | (115 | ) |
Legal and settlement charges (9) | | | (9 | ) | | | — | | | — | | | | (13 | ) | | | — | | | — | | | | (35 | ) | | | (57 | ) |
Impairment of West Coast Power (10) | | | — | | | | — | | | (40 | ) | | | — | | | | — | | | — | | | | — | | | | (40 | ) |
Loss on sale of Illinois Power (11) | | | — | | | | — | | | — | | | | — | | | | — | | | (19 | ) | | | — | | | | (19 | ) |
Taxes (12) | | | — | | | | — | | | — | | | | — | | | | — | | | — | | | | (19 | ) | | | (19 | ) |
Discontinued operations (13) | | | — | | | | — | | | — | | | | 2 | | | | 59 | | | — | | | | — | | | | 61 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total | | $ | (9 | ) | | $ | — | | $ | (40 | ) | | $ | (126 | ) | | $ | 59 | | $ | (19 | ) | | $ | (54 | ) | | $ | (189 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (1) | 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. |
| (2) | We recognized a pre-tax charge of approximately $29 million ($18 million after-tax) related to the impairment of a gas turbine not currently in use. This charge is included in Impairment and other charges. |
| (3) | 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, a joint venture with NRG, and Chorrera, a joint venture located in Panama. This charge is included in Earnings (losses) from unconsolidated investments. |
| (4) | We recognized a pre-tax loss of approximately $11 million ($7 million after-tax) related to restructuring charges in connection with a reduction in workforce. This loss is included in Impairment and other charges. |
| (5) | We recognized a pre-tax loss of approximately $9 million ($6 million after-tax) related to legal and settlement charges. This loss is included in General and administrative expenses and Impairment and other charges. |
| (6) | We recognized a net income tax expense of approximately $23 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 $696 million after-tax Income from discontinued operations. |
| (7) | We recognized pre-tax income of approximately $1,101 million ($696 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 is a pre-tax gain of approximately $1,087 ($681 million after-tax) on the sale of DMSLP. |
| (8) | 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. |
| (9) | 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. |
| (10) | 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 and an impairment of our investment in West Coast Power. This charge is included in Earnings (losses) from unconsolidated investments. |
| (11) | 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 Loss on sale of assets, net. |
| (12) | We recognized a net income tax expense of approximately $19 million primarily related to deferred tax capital loss valuation allowances. An expense of $28 million is included in Income tax benefit and a benefit of $9 million is included in Income from discontinued operations. |
| (13) | We recognized pre-tax income of approximately $61 million ($52 million after-tax) related to discontinued operations. The income consists primarily of $59 million income associated with our NGL segment, which was reclassified to discontinued operations due to the anticipated sale of DMSLP. Included in the $59 million of income from our NGL segment is a pre-tax gain of approximately $16 million ($10 million after-tax) on the sale of our Sherman natural gas processing facility. |
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DYNEGY INC.
SIGNIFICANT ITEMS
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Twelve Months Ended December 31, 2005 | |
| | | Power Generation | | | | | | | | | | | | |
| | | GEN - MW | | | GEN - NE | | GEN -SO | | | CRM | | | NGL | | REG | | | OTHER | | | Total | |
Sterlington toll settlement charge (1) | | $ | — | | | $ | — | | $ | — | | | $ | (364 | ) | | $ | — | | $ | — | | | $ | — | | | $ | (364 | ) |
Legal and settlement charges (2) | | | — | | | | — | | | — | | | | (38 | ) | | | — | | | — | | | | (249 | ) | | | (287 | ) |
Independence toll settlement charge (3) | | | — | | | | — | | | — | | | | (169 | ) | | | — | | | — | | | | — | | | | (169 | ) |
Asset impairment (4) | | | (29 | ) | | | — | | | — | | | | — | | | | — | | | — | | | | — | | | | (29 | ) |
Impairment of generation investments (5) | | | — | | | | — | | | (27 | ) | | | — | | | | — | | | — | | | | — | | | | (27 | ) |
Restructuring charges (6) | | | — | | | | — | | | — | | | | — | | | | — | | | — | | | | (11 | ) | | | (11 | ) |
Taxes (7) | | | — | | | | — | | | — | | | | — | | | | — | | | — | | | | 102 | | | | 102 | |
Discontinued operations (8) | | | — | | | | — | | | — | | | | 6 | | | | 1,250 | | | — | | | | — | | | | 1,256 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total | | $ | (29 | ) | | $ | — | | $ | (27 | ) | | $ | (565 | ) | | $ | 1,250 | | $ | — | | | $ | (158 | ) | | $ | 471 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| | | Twelve Months Ended December 31, 2004 | |
| | | Power Generation | | | | | | | | | | | | | | | |
| | | GEN - MW | | | GEN - NE | | GEN -SO | | | CRM | | | NGL | | REG | | | OTHER | | | Total | |
Kendall toll restructuring (9) | | $ | — | | | $ | — | | $ | — | | | $ | (115 | ) | | $ | — | | $ | — | | | $ | — | | | $ | (115 | ) |
Legal and settlement charges (10) | | | (9 | ) | | | — | | | 2 | | | | (13 | ) | | | — | | | (1 | ) | | | (92 | ) | | | (113 | ) |
Impairment of West Coast Power (11) | | | — | | | | — | | | (85 | ) | | | — | | | | — | | | — | | | | — | | | | (85 | ) |
Loss on sale of Illinois Power (12) | | | — | | | | — | | | — | | | | — | | | | — | | | (58 | ) | | | — | | | | (58 | ) |
Impairment of Illinois Power (13) | | | — | | | | — | | | — | | | | — | | | | — | | | (54 | ) | | | — | | | | (54 | ) |
Acceleration of financing costs (14) | | | — | | | | — | | | — | | | | — | | | | — | | | — | | | | (14 | ) | | | (14 | ) |
Gain on sale of Oyster Creek (15) | | | — | | | | — | | | 15 | | | | — | | | | — | | | — | | | | — | | | | 15 | |
Taxes (16) | | | — | | | | — | | | — | | | | — | | | | — | | | — | | | | 24 | | | | 24 | |
Gain on sale of Joppa (17) | �� | | 75 | | | | — | | | | | | | — | | | | — | | | — | | | | — | | | | 75 | |
Gas transportation contracts (18) | | | — | | | | — | | | — | | | | 88 | | | | — | | | — | | | | — | | | | 88 | |
Discontinued operations (19) | | | — | | | | — | | | — | | | | 19 | | | | 254 | | | — | | | | 3 | | | | 276 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total | | $ | 66 | | | $ | — | | $ | (68 | ) | | $ | (21 | ) | | $ | 254 | | $ | (113 | ) | | $ | (79 | ) | | $ | 39 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (1) | 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. |
| (2) | We recognized a pre-tax loss 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 loss is included in General and administrative expenses. |
| (3) | We recognized a pre-tax loss 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 loss is included in Cost of sales. |
| (4) | We recognized a pre-tax charge of approximately $29 million ($18 million after-tax) related to the impairment of a gas turbine not currently in use. This charge is included in Impairment and other charges. |
| (5) | 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, a joint venture with NRG, and Chorrera, a joint venture located in Panama. This charge is included in Earnings (losses) from unconsolidated investments. |
| (6) | We recognized a pre-tax loss of approximately $11 million ($7 million after-tax) related to restructuring charges in connection with a reduction in workforce. This loss is included in Impairment and other charges. |
| (7) | We recognized a net income tax benefit of approximately $102 primarily for the reversal of a deferred tax capital loss valuation allowance related to gains on the anticipated sale of DMSLP. A benefit of $134 million is included in the $918 million after-tax Income from discontinued operations, partially offset by a $32 million charge in Income tax benefit. |
| (8) | We recognized pre-tax income of approximately $1,256 million ($918 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 ($681 million after-tax) on the sale of DMSLP and $10 million ($7 million after-tax) on the sale of the Port Everglades property. |
| (9) | 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. |
| (10) | We recognized a pre-tax loss of approximately $113 million ($71 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. |
| (11) | 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 and an impairment of our investment in West Coast Power. This charge is included in Earnings (losses) from unconsolidated investments. |
| (12) | 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 Loss on sale of assets, net. |
| (13) | 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. |
| (14) | 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. |
| (15) | 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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| (16) | 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 $36 million is included in Income tax benefit, partially offset by a $12 million charge in Income from discontinued operations. |
| (17) | 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. |
| (18) | 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. |
| (19) | We recognized pre-tax income of approximately $276 million ($165 million after-tax) related to discontinued operations. The income consists primarily of $254 million associated with our NGL segment which was reclassified to discontinued operations due to sale of DMSLP, $19 million pre-tax income on our UK CRM business and $3 million pre-tax income associated with our global communications business. Included in the $254 million of income from our NGL segment is 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, 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 and a pre-tax gain of approximately $16 million ($10 million after-tax) on the sale of our Sherman natural gas processing facility. |
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DYNEGY INC.
SUMMARY CASH FLOW INFORMATION
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Twelve Months Ended December 31, 2005 | |
| | | GEN (1) | | | CRM | | | NGL | | | REG | | | OTHER | | | Total | |
Cash Flow from Operations | | $ | 472 | | | $ | (21 | ) | | $ | 288 | | | $ | — | | | $ | (769 | ) | | $ | (30 | ) |
Capital Expenditures | | | (143 | ) | | | — | | | | (45 | ) | | | — | | | | (7 | ) | | | (195 | ) |
Business Acquisition Costs | | | (120 | ) | | | — | | | | — | | | | — | | | | — | | | | (120 | ) |
Proceeds from Asset Sales (2) | | | 1 | | | | — | | | | 2,392 | | | | (5 | ) | | | 100 | | | | 2,488 | |
Restricted Cash and Other (3) | | | (14 | ) | | | — | | | | — | | | | — | | | | (335 | ) | | | (349 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Free Cash Flow (4) | | $ | 196 | | | $ | (21 | ) | | $ | 2,635 | | | $ | (5 | ) | | $ | (1,011 | ) | | $ | 1,794 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| |
| | | Twelve Months Ended December 31, 2004 | |
| | | GEN (1) | | | CRM | | | NGL | | | REG | | | OTHER | | | Total | |
Cash Flow from Operations | | $ | 421 | | | $ | (371 | ) | | $ | 278 | | | $ | 213 | | | $ | (536 | ) | | $ | 5 | |
Capital Expenditures | | | (148 | ) | | | — | | | | (61 | ) | | | (92 | ) | | | (13 | ) | | | (314 | ) |
Proceeds from Asset Sales | | | 260 | | | | — | | | | 99 | | | | 217 | | | | — | | | | 576 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Free Cash Flow (4) | | $ | 533 | | | $ | (371 | ) | | $ | 316 | | | $ | 338 | | | $ | (549 | ) | | $ | 267 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| (1) | Beginning in the fourth quarter 2005, we report the results of our power generation business as three separate segments in our 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) | 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. |
| (3) | Restricted cash and other primarily relates to an increase in restricted cash associated with the $335 million cash collateral posted for the Amended and Restated Credit Facility. |
| (4) | Free cash flow is a non-GAAP financial measure. Free cash flow can be reconciled to operating cash flow using the following calculation: Operating cash flow plus investing cash flow (consisting of asset sale proceeds less business acquisition costs, capital expenditures and changes in restricted cash) equals free cash flow. We use free cash flow to measure the cash generating ability of our operating asset-based energy businesses relative to their capital expenditure obligations. Free cash flow should not be used in lieu of GAAP measures with respect to cash flows and should not be interpreted as available for discretionary expenditures, as mandatory expenditures such as debt obligations are not deducted from the measure. A reconciliation of free cash flow to cash flow from operations by segment for the periods presented is included above. |
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DYNEGY INC.
OPERATING DATA
| | | | | | | | | | | | |
| | | Three Months Ended December 31, | | Twelve Months Ended December 31, |
| | | 2005 | | 2004 | | 2005 | | 2004 |
GEN - MW | | | | | | | | | | | | |
Million Megawatt Hours Generated - Gross and Net | | | 5.1 | | | 5.1 | | | 21.9 | | | 22.6 |
Average On-Peak Market Power Prices ($/MWh): | | | | | | | | | | | | |
Cinergy | | $ | 71 | | $ | 43 | | $ | 64 | | $ | 43 |
Commonwealth Edison (NI Hub) | | $ | 71 | | $ | 42 | | $ | 62 | | $ | 42 |
GEN - NE | | | | | | | | | | | | |
Million Megawatt Hours Generated - Gross and Net | | | 1.5 | | | 1.0 | | | 8.3 | | | 6.0 |
Average On-Peak Market Power Prices ($/MWh): | | | | | | | | | | | | |
New York - Zone G | | $ | 111 | | $ | 62 | | $ | 92 | | $ | 62 |
New York - Zone A | | $ | 93 | | $ | 53 | | $ | 76 | | $ | 53 |
GEN - SO | | | | | | | | | | | | |
Million Megawatt Hours Generated - Gross | | | 1.5 | | | 1.8 | | | 6.6 | | | 8.5 |
Million Megawatt Hours Generated - Net | | | 1.2 | | | 1.4 | | | 5.3 | | | 6.7 |
Average On-Peak Market Power Prices ($/MWh): | | | | | | | | | | | | |
Southern | | $ | 87 | | $ | 49 | | $ | 71 | | $ | 49 |
ERCOT | | $ | 93 | | $ | 53 | | $ | 80 | | $ | 51 |
SP-15 | | $ | 98 | | $ | 61 | | $ | 73 | | $ | 55 |
Average Natural Gas Price - Henry Hub ($/MMBtu) (1) | | $ | 12.21 | | $ | 6.26 | | $ | 8.80 | | $ | 5.85 |
NGL(2) | | | | | | | | | | | | |
Field Plant Gross NGL Production (MBbls/d) | | | 60.4 | | | 57.0 | | | 56.6 | | | 57.3 |
Straddle Plant Gross NGL Production (MBbls/d) | | | 4.3 | | | 29.3 | | | 23.7 | | | 26.6 |
| | | | | | | | | | | | |
Total Gross NGL Production | | | 64.7 | | | 86.3 | | | 80.3 | | | 83.9 |
| | | | | | | | | | | | |
Natural Gas (Residue) Sales (BBtu/d) | | | 190.2 | | | 179.7 | | | 185.0 | | | 182.8 |
Natural Gas Field Plant Inlet Volumes (MMCFD) | | | 544.5 | | | 506.9 | | | 518.5 | | | 535.6 |
Natural Gas Straddle Plant Inlet Volumes (MMCFD) | | | 296.8 | | | 1,063.3 | | | 1,030.2 | | | 990.0 |
| | | | | | | | | | | | |
Total Natural Gas Inlet Volumes | | | 841.3 | | | 1,570.2 | | | 1,548.7 | | | 1,525.6 |
| | | | | | | | | | | | |
Fractionation Volumes (MBbls/d) | | | 169.5 | | | 154.7 | | | 173.8 | | | 202.5 |
Natural Gas Liquids Sold (MBbls/d) | | | 181.4 | | | 286.3 | | | 257.7 | | | 282.5 |
Average Commodity Prices: | | | | | | | | | | | | |
Crude Oil - WTI ($/Bbl) | | $ | 66.23 | | $ | 50.10 | | $ | 54.75 | | $ | 41.43 |
Natural Gas - Henry Hub ($/MMBtu) (3) | | $ | 13.93 | | $ | 7.06 | | $ | 7.87 | | $ | 6.13 |
Natural Gas Liquids ($/Gal) | | $ | 1.10 | | $ | 0.83 | | $ | 0.87 | | $ | 0.71 |
Fractionation Spread ($/MMBtu) - daily | | $ | 0.91 | | $ | 3.11 | | $ | 1.91 | | $ | 2.18 |
REG(4) | | | | | | | | | | | | |
Electric Sales in KWH (Millions): | | | | | | | | | | | | |
Residential | | | — | | | — | | | — | | | 4,182 |
Commercial | | | — | | | — | | | — | | | 3,389 |
Industrial | | | — | | | — | | | — | | | 3,859 |
Transportation of Customer-Owned Electricity | | | — | | | — | | | — | | | 2,407 |
Other | | | — | | | — | | | — | | | 287 |
| | | | | | | | | | | | |
Total Electricity Delivered | | | — | | | — | | | — | | | 14,124 |
| | | | | | | | | | | | |
Gas Sales in Therms (Millions): | | | | | | | | | | | | |
Residential | | | — | | | — | | | — | | | 214 |
Commercial | | | — | | | — | | | — | | | 85 |
Industrial | | | — | | | — | | | — | | | 40 |
Transportation of Customer-Owned Gas | | | — | | | — | | | — | | | 171 |
| | | | | | | | | | | | |
Total Gas Delivered | | | — | | | — | | | — | | | 510 |
| | | | | | | | | | | | |
Cooling Degree Days - Actual | | | — | | | — | | | — | | | 932 |
Cooling Degree Days - 10 year rolling average | | | — | | | — | | | — | | | 1,236 |
Heating Degree Days - Actual | | | — | | | — | | | — | | | 3,145 |
Heating Degree Days - 10 year rolling average | | | — | | | — | | | — | | | 3,190 |
| (1) | Calculated as the average of the daily gas prices for the period. |
| (2) | Effective October 31, 2005, we sold DMSLP to Targa Resources. |
| (3) | Calculated as the average of the first of the month prices for the period. |
| (4) | Effective September 30, 2004, we sold Illinois Power, our regulated utility, to Ameren. |
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DYNEGY INC.
2006 EARNINGS ESTIMATES (1)
(IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | GEN - MW | | | GEN - NE | | | GEN - SO | | | Total GEN | | | CRM | | OTHER | | | Total | |
EBITDA (2) | | $ | 490 -540 | | | $ | 80 -115 | | | $ | (5) -5 | | | $ | 565 -660 | | | $ | 15 | | $ | (100 -90) | | | $ | 480 -585 | |
Depreciation and Amortization | | | (155 | ) | | | (50 | ) | | | (30 | ) | | | (235 | ) | | | — | | | (10 | ) | | | (245 | ) |
Interest Expense | | | | | | | | | | | | | | | | | | | | | | | | | | (410 | ) |
Income Tax Benefit | | | | | | | | | | | | | | | | | | | | | | | | | | 67 - 27 | |
Preferred Stock Dividends | | | | | | | | | | | | | | | | | | | | | | | | | | (22 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net Loss | | | | | | | | | | | | | | | | | | | | | | | | | $ | (130 -65) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
2006 CASH FLOW ESTIMATES (1)
(IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | GEN (4) | | | CRM | | | OTHER | | | Total Core
Business | | | Non-Core (5) | | | Total | |
Cash Flow from Operations | | $ | 530 -630 | | | $ | (10 | ) | | $ | (360 -350) | | | $ | 160 -270 | | | | (370 | ) | | $ | (210 -100) | |
Capital Expenditures and Business Acquisitions | | | (190 | ) | | | — | | | | (5 | ) | | | (195 | ) | | | (5 | ) | | | (200 | ) |
Proceeds from Asset Sales | | | — | | | | — | | | | — | | | | — | | | | 160 | | | | 160 | |
Changes in Restricted Cash | | | — | | | | — | | | | — | | | | — | | | | 335 | | | | 335 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Free Cash Flow (3) | | $ | 340 - 440 | | | $ | (10 | ) | | $ | (365 -355) | | | $ | (35) -75 | | | $ | 120 | | | $ | 85 - 195 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| (1) | 2006 estimates are presented on a GAAP basis and are based on forward commodity price curves as of Feb. 7, 2006. 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. Core business represents continuing results, excluding significant items. |
| (2) | 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 (loss) 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 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. |
| (4) | Beginning in the fourth quarter 2005, we report the results of our power generation business as three separate segments in our 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. |
| (5) | The following summarizes the items included in Non-core business in our cash flow estimate. |
| | | | | | | | | | | | | | | | | | |
| | | Cash Flow from
Operations | | | Capital Exp. and
Business Acq. | | | Proceeds
from Asset
Sales | | Changes in
Restricted Cash | | Free Cash
Flows | |
Sterlington toll settlement payment (CRM) | | $ | (370 | ) | | $ | — | | | $ | — | | $ | — | | $ | (370 | ) |
Development Capital Expenditures (GEN) | | | — | | | | (5 | ) | | | — | | | — | | | (5 | ) |
Net proceeds from sale of West Coast Power and acquisition of Rocky Road (GEN) | | | — | | | | — | | | | 160 | | | — | | | 160 | |
Return of Cash Collateral (OTHER) | | | — | | | | — | | | | — | | | 335 | | | 335 | |
| | | | | | | | | | | | | | | | | | |
Total | | $ | (370 | ) | | $ | (5 | ) | | $ | 160 | | $ | 335 | | $ | 120 | |
| | | | | | | | | | | | | | | | | | |
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