Exhibit 99.1
NR05-33
Nov. 8, 2005
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| Media: | | John Sousa or David Byford |
| | | (713) 767-5800 |
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| Analysts: | | Peter Wilt or Hillarie Bloxom |
| | | (713) 507-6466 |
DYNEGY ANNOUNCES THIRD QUARTER 2005 RESULTS
| | • | | Company reports net income applicable to common shareholders of $23 million |
| | • | | Power Generation benefited from continued strong operational performance, increased sales volumes and higher electricity prices realized in key regions |
| | • | | Dynegy raises 2005 earnings guidance estimates for third consecutive quarter driven by $65 million increase in Power Generation EBITDA |
| | • | | Company provides 2006 earnings and cash flow guidance estimates based on continued strong outlook for energy commodity prices and operational performance |
HOUSTON (Nov. 8, 2005) – Dynegy Inc. (NYSE: DYN) today reported net income applicable to common shareholders of $23 million, or $0.06 per diluted share, for the third quarter 2005, compared to net income applicable to common shareholders of $72 million and diluted earnings per share of $0.16 for the third quarter 2004.
Third quarter 2005 financial results were impacted by:
| | • | | $25 million pre-tax legal and settlement charges primarily associated with the company’s Customer Risk Management segment. |
Third quarter 2004 financial results included a number of significant pre-tax items, including:
| | • | | $90 million in gains on the sale of the company’s interest in the Joppa and Oyster Creek power generation facilities; |
| | • | | a $45 million charge related to the impairment of the company’s investment in West Coast Power; and |
| | • | | a $24 million loss related to the sale of Illinois Power. |
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“During the third quarter, Dynegy continued to deliver a strong operational performance and, when coupled with our corporate strategy of reducing long-term forward sales and other forms of hedging, the company was able to realize higher prices,” said Bruce A. Williamson, Chairman and Chief Executive Officer of Dynegy Inc. “This approach to our business also enabled us to be much more efficient by minimizing our collateral requirements, and demonstrates how well Dynegy can perform in a high natural gas price environment where we continue to serve our customers with reliable delivery of electricity from a variety of generating assets and fuel sources.
“Our outlook for the rest of 2005 and all of 2006 is based on our view that energy prices and demand will remain relatively high, which, as demonstrated by our year-to-date performance, positions us favorably as power markets continue to recover and as the market need for energy presents commercial opportunities for our assets,” Williamson added. “We believe this sort of operating leverage and the company’s improving capital structure combined with continued stronger commodity pricing positions our portfolio to build new value for investors for the future.”
Period-Over-Period Comparison
A comparison of the company’s third quarter 2005 and third quarter 2004 results is contained in the table below (in millions of dollars, except per share amounts):
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| | | 3Q 2005
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Income (loss) from continuing operations, before tax | | $ | (27 | ) | | $ | 49 | |
Income tax benefit (expense) from continuing operations Tax | | | 13 | | | | (7 | ) |
Income from discontinued operations, before tax | | | 69 | | | | 60 | |
Income tax expense from discontinued operations | | | (26 | ) | | | (24 | ) |
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Net income | | | 29 | | | | 78 | |
Preferred stock dividends | | | 6 | | | | 6 | |
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Net income applicable to common stockholders | | $ | 23 | | | $ | 72 | |
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Basic earnings per share | | $ | 0.06 | | | $ | 0.19 | |
Diluted earnings per share | | $ | 0.06 | | | $ | 0.16 | |
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Quarterly Business Segment Results
Following are business segment financial results for the third quarter 2005 compared to the third quarter 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
Earnings before interest, taxes and depreciation and amortization (EBITDA) from the Power Generation business was $177 million for the third quarter 2005, compared to $220 million for the third quarter 2004, which included $90 million in pre-tax gains related to the sale of the company’s interests in the Joppa and Oyster Creek generation facilities. Third quarter 2004 results also included earnings from West Coast Power of $42 million, which were offset by a $45 million impairment.
Sales volumes generated by Dynegy’s Northeast facilities rose to 3.3 million megawatt hours in the third quarter 2005 compared to 1.4 million megawatt hours in the third quarter 2004. Volumes generated by the company’s Roseton and Danskammer facilities were 54 percent greater than the third quarter 2004 due to stronger regional demand for electricity and improved spark spreads that benefited the Roseton facility in particular. In addition, Northeast volumes benefited from the acquisition in the first quarter 2005 of the Independence combined-cycle facility, which produced 1.1 million megawatt hours during the third quarter 2005. Average on-peak prices in New York Zone G (Roseton and Danskammer) and New York Zone A (Independence) were 93 percent and 90 percent higher, respectively, than during the third quarter 2004.
Sales volumes generated by Dynegy’s Midwest facilities, excluding volumes related to assets sold in 2004, rose to 6 million megawatt hours in the third quarter 2005 compared to 5.3 million megawatt hours in the third quarter 2004. Energy supplied to AmerenIP under Dynegy’s two-year power purchase agreement was 59 percent higher than the third quarter 2004. However, incremental energy sold to AmerenIP under the power purchase agreement, while profitable, is priced significantly below current market
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prices, resulting in reduced margins for the Midwest region period-over-period. Another factor impacting the results of the company’s Midwest region was an $18 million charge related to mark-to-market losses that resulted from forward sales transactions entered into prior to the company’s change in hedging strategy to emphasize current quarter sales. A majority of these forward sales terminate in the fourth quarter 2005 or shortly thereafter, after which time the AmerenIP sales contract will be the only material long-term forward sales arrangement, and it terminates at the end of 2006. Average on-peak prices in the NI Hub/Com Ed and Cinergy were 83 percent and 86 percent higher, respectively, than during the third quarter 2004.
Higher power prices and improved spark spreads, as well as stronger sales of ancillary services from the company’s CoGen Lyondell combined-cycle plant, led to improved results in the ERCOT region. Power Generation’s performance also benefited from the commercial operation of all of the company’s peaking plants during the third quarter 2005. Sales volumes generated by Dynegy’s peaking facilities rose to 410,000 megawatt hours during the third quarter 2005, compared to 75,000 megawatt hours during the third quarter 2004. This result is indicative of the company’s continuing focus on operational readiness and in-market availability to meet weather-driven demand.
For the nine months ended Sept. 30, 2005, cash flow from operations was $354 million and proceeds from asset sales were $1 million, while capital expenditures were $87 million and business acquisition costs related to Sithe Energies were $120 million. Free cash flow for the Power Generation segment was an inflow of $148 million.
Midstream
The sale of the company’s Midstream business to Targa Resources, Inc. was completed on Oct. 31, 2005. This business was classified as “held-for-sale” beginning on June 1, 2005 in accordance with Generally Accepted Accounting Principles (GAAP), and its results are presented as discontinued operations for all periods. As a result of the held-for-sale status, depreciation of the Midstream assets was suspended.
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EBITDA from the Midstream business was $88 million for the third quarter 2005, compared to $92 million for the third quarter 2004. For the nine months ended Sept. 30, 2005, cash flow from operations was $241 million and proceeds from asset sales were $10 million, while capital expenditures were $39 million. Free cash flow for the Midstream segment was an inflow of $212 million.
Customer Risk Management
Loss before interest, taxes and depreciation and amortization from the Customer Risk Management business totaled $25 million for the third quarter 2005, compared to a loss of $35 million for the third quarter 2004. The third quarter 2005 improvement was partially attributable to the elimination or restructuring of tolling obligations. In addition, the termination of a legacy emission contract in the third quarter 2005 resulted in a $21 million gain, but was offset by $29 million in legal and settlement charges related to legacy litigation associated with the company’s Customer Risk Management business.
The company’s Customer Risk Management business, including obligations associated with its remaining power tolling and gas transportation arrangements, will continue to have a negative effect on its consolidated results of operations and cash flows until the related obligations have been satisfied or restructured. The company remains open to opportunities to assign or renegotiate the terms of these arrangements and is actively pursuing resolution of the remaining pending legacy litigation.
Other
In the Other segment, which consists primarily of general and administrative expenses, the company recorded a $26 million loss before interest, taxes and depreciation and amortization for the third quarter 2005, compared to a $49 million loss before interest, taxes and depreciation and amortization for the third quarter 2004. Other legal and settlement charges, compensation, insurance and external consultant costs were also lower in the third quarter 2005 than the third quarter 2004.
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The company’s interest expense decreased by $16 million to $99 million for the third quarter 2005 primarily as a result of the sale of Illinois Power in the third quarter 2004. Additionally, $15 million and $10 million of interest expense has been reclassified as discontinued operations in the third quarter of 2005 and 2004, respectively, in accordance with GAAP.
The third quarter 2005 tax expense from continuing and discontinued operations totaled $13 million. The third quarter 2004 tax expense from continuing and discontinued operations was $31 million, which included a $13 million benefit primarily related to the reversal of a deferred tax valuation allowance due to gains on asset sales. After adjusting for this item, the effective tax rates for 2005 and 2004 were 31 percent and 40 percent, respectively.
Liquidity
As of Sept. 30, 2005, Dynegy’s liquidity was $580 million. This consisted of $205 million in cash on hand and $375 million in unused availability under the company’s former $700 million revolving bank credit facility. The decrease in liquidity as compared to the $765 million in liquidity on June 30, 2005 primarily related to the final payment for the shareholder class action and derivative litigation settlements and increased working capital requirements.
The company’s former revolving credit facility had been used exclusively to support the issuance of letters of credit. Accordingly, as of Sept. 30, there were no borrowings outstanding under this facility. Total collateral posted as of Sept. 30, 2005, including cash and letters of credit, was approximately $512 million. Dynegy expects collateral at the end of 2005 to be approximately $300 million. This reduction comes primarily from the elimination of the requirement to post collateral in the Midstream business, which was sold effective Oct. 31, 2005.
On Oct. 31, 2005, the company replaced its former $1.3 billion credit facility with an amended and restated $1 billion facility consisting of (1) a $400 million letter of credit component and (2) a $600 million revolving credit component, both of which are
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collateralized with cash and other assets that were pledged under the former $1.3 billion credit facility. Also on Oct. 31, the company borrowed $600 million under the new revolving credit facility to repay the term loan and accrued unpaid interest associated with the former credit facility. The $600 million outstanding principal balance of the new revolving credit facility was paid in full on Nov. 1, 2005.
Following the closing of the sale of the Midstream business and the above financing activities, as of Nov. 1, consolidated liquidity was $1.516 billion. This consisted of $1.503 billion in cash on hand and $13 million in cash-collateralized unused availability under the company’s amended and restated credit facility.
Cash Flow
Cash flow from operations, including working capital changes, totaled an outflow of $178 million for the nine months ended Sept. 30, 2005. This consisted of $595 million in cash inflows from the Power Generation and Midstream businesses and includes the return of cash as letters of credit were substituted for collateral, partially offset by working capital increases due to the impact of higher power prices on accounts receivable. Cash outflows of $64 million from the Customer Risk Management business resulted primarily from capacity payments that exceeded realized margins on the company’s power tolling arrangements, as well as a first quarter 2005 final payment to exit four natural gas transportation contracts, offset by the return of cash as letters of credit were substituted for collateral. An additional $709 million in cash outflows primarily related to interest payments and general and administrative expenses in the company’s Other business segment, as well as payments of $255 million related to settling the shareholder class action and derivative litigation.
Cash flow from investing activities for the nine months ended Sept. 30, 2005 totaled an outflow of $146 million. This consisted of $132 million in capital expenditures and $120 million in business acquisition costs related to Sithe Energies. Proceeds from asset sales totaled $106 million and are primarily related to the release of escrow funds related to the sale of Illinois Power.
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For the nine months ended Sept. 30, 2005, Dynegy’s free cash flow was an outflow of $324 million, which consisted of cash used in operations and investing activities.
2005 Earnings Guidance Update
With today’s announcement of third quarter 2005 earnings and the earlier announcement relating to the completion of the sale of Dynegy’s Midstream business, management is revising its 2005 earnings and cash flow guidance estimates last updated on Aug. 8, 2005. The company’s new estimate of net income applicable to common shareholders of $435 million to $455 million compared to the previous estimate of net income of $400 million to $410 million. Dynegy’s new estimate of net loss from its core businesses, which represent the company’s continuing results excluding significant items, is a range of $195 million to $175 million, compared to the previously announced estimated net loss of $235 million to $225 million. This new estimate takes into consideration an increase in anticipated EBITDA of approximately $65 million from the Power Generation business.
2006 Earnings Guidance Estimates
Based on the expectation of continued strong commodity pricing, the company estimates a net loss applicable to common shareholders of $75 million to $5 million during 2006. This new estimate takes into consideration an anticipated EBITDA range of $725 million to $825 million from power generation based on continued strength in the company’s operational performance, demand and commodity prices.
Investor Conference Call/Web Cast
Dynegy will discuss its third quarter results and 2005 and 2006 earnings and cash flow guidance estimates 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 ofwww.dynegy.com.
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About Dynegy Inc.
Dynegy Inc. provides electricity to markets and customers throughout the United States. The company’s fleet of power generation facilities consists of baseload, intermediate and peaking power plants fueled by a mix of coal, fuel oil and natural gas. Located in 12 states, the portfolio is well-positioned to capitalize on regional differences in power prices and weather-driven demand.
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 impact of the sale of our Midstream business on our financial position and results of operations, the possibility of commercial and strategic growth opportunities for our Power Generation business, indications of a recovering power market environment, 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 2005 and 2006. 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.
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 and natural gas; the effects of competition and weather on 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 achieve tax and capital structure objectives associated with the sale of its Midstream business; the availability, ability to consummate, and effects of commercial and strategic growth opportunities for Dynegy’s Power Generation business; Dynegy’s ability to operate its businesses efficiently; 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; Dynegy’s liquidity and its effect on the ability to fund significant debt maturities and debt service obligations; the impacts of hedging and the strategy of unhedged operations; 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; the financial impact of cash payments and stock issuances required by the shareholder class action litigation settlement agreement; 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 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, 2004, its Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and its Current Reports, 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. 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
September 30,
| | | Nine Months Ended
September 30,
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| | | 2005
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Revenues | | $ | 770 | | | $ | 668 | | | $ | 1,691 | | | $ | 2,124 | |
Cost of sales, exclusive of depreciation and amortization shown separately below | | | (572 | ) | | | (443 | ) | | | (1,482 | ) | | | (1,432 | ) |
Depreciation and amortization expense | | | (56 | ) | | | (58 | ) | | | (165 | ) | | | (183 | ) |
Impairment and other charges | | | — | | | | (3 | ) | | | (6 | ) | | | (78 | ) |
Loss on sale of assets, net | | | (1 | ) | | | (24 | ) | | | (1 | ) | | | (39 | ) |
General and administrative expenses | | | (76 | ) | | | (75 | ) | | | (421 | ) | | | (231 | ) |
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Operating income (loss) | | | 65 | | | | 65 | | | | (384 | ) | | | 161 | |
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Earnings from unconsolidated investments | | | 7 | | | | 99 | | | | 14 | | | | 187 | |
Interest expense | | | (99 | ) | | | (115 | ) | | | (284 | ) | | | (386 | ) |
Other income and expense, net | | | — | | | | — | | | | 9 | | | | 6 | |
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Income (loss) from continuing operations before income taxes | | | (27 | ) | | | 49 | | | | (645 | ) | | | (32 | ) |
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Income tax benefit (expense) | | | 13 | | | | (7 | ) | | | 228 | | | | 75 | |
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Income (loss) from continuing operations | | | (14 | ) | | | 42 | | | | (417 | ) | | | 43 | |
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Income from discontinued operations, net of tax | | | 43 | | | | 36 | | | | 222 | | | | 113 | |
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Net income (loss) | | $ | 29 | | | $ | 78 | | | $ | (195 | ) | | $ | 156 | |
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Less: Preferred stock dividends | | | 6 | | | | 6 | | | | 17 | | | | 17 | |
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Net income (loss) applicable to common stockholders | | $ | 23 | | | $ | 72 | | | $ | (212 | ) | | $ | 139 | |
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Earnings before interest, taxes, and depreciation and amortization (EBITDA) (1) | | $ | 214 | | | $ | 313 | | | $ | 36 | | | $ | 834 | |
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Basic earnings (loss) per share: | | | | | | | | | | | | | | | | |
Income (loss) from continuing operations (2) | | $ | (0.05 | ) | | $ | 0.10 | | | $ | (1.13 | ) | | $ | 0.07 | |
Income from discontinued operations | | | 0.11 | | | | 0.09 | | | | 0.58 | | | | 0.30 | |
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Basic earnings (loss) per share | | $ | 0.06 | | | $ | 0.19 | | | $ | (0.55 | ) | | $ | 0.37 | |
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Diluted earnings (loss) per share: | | | | | | | | | | | | | | | | |
Income (loss) from continuing operations (2) | | $ | (0.05 | ) | | $ | 0.09 | | | $ | (1.13 | ) | | $ | 0.07 | |
Income from discontinued operations | | | 0.11 | | | | 0.07 | | | | 0.58 | | | | 0.30 | |
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Diluted earnings (loss) per share | | $ | 0.06 | | | $ | 0.16 | | | $ | (0.55 | ) | | $ | 0.37 | |
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Basic shares outstanding | | | 390 | | | | 379 | | | | 383 | | | | 378 | |
Diluted shares outstanding | | | 516 | | | | 504 | | | | 509 | | | | 380 | |
| (1) | EBITDA is a non-GAAP financial measure. Consolidated EBITDA can be reconciled to Net income (loss) using the following calculation: Net income (loss) less Income tax benefit, plus Interest expense and Depreciation and amortization expense. Management and some members of the investment community utilize EBITDA to measure financial performance on an ongoing basis. However, EBITDA should not be used in lieu of GAAP measures such as net income and cash flow from operations. A reconciliation of EBITDA to Operating income (loss) and Net income (loss) for the periods presented is included below. |
| (2) | See “Reported Unaudited Basic and Diluted 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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| | | Three Months Ended
September 30,
| | | Nine Months Ended
September 30,
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| | | 2004
| | | 2005
| | | 2004
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Operating income (loss) | | $ | 65 | | | $ | 65 | | | $ | (384 | ) | | $ | 161 | |
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Add: Depreciation and amortization expense, a component of operating income (loss) | | | 56 | | | | 58 | | | | 165 | | | | 183 | |
Earnings from unconsolidated investments | | | 7 | | | | 99 | | | | 14 | | | | 187 | |
Other income and expense, net | | | — | | | | — | | | | 9 | | | | 6 | |
EBITDA from discontinued operations (3) | | | 86 | | | | 91 | | | | 232 | | | | 297 | |
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Earnings before interest, taxes, and depreciation and amortization (EBITDA) | | | 214 | | | | 313 | | | | 36 | | | | 834 | |
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Depreciation and amortization expense, a component of operating income (loss) | | | (56 | ) | | | (58 | ) | | | (165 | ) | | | (183 | ) |
Depreciation and amortization expense from discontinued operations | | | (2 | ) | | | (21 | ) | | | (37 | ) | | | (66 | ) |
Interest expense from continuing operations | | | (99 | ) | | | (115 | ) | | | (284 | ) | | | (386 | ) |
Interest expense from discontinued operations | | | (15 | ) | | | (10 | ) | | | (40 | ) | | | (16 | ) |
Income tax benefit (expense) from continuing operations | | | 13 | | | | (7 | ) | | | 228 | | | | 75 | |
Income tax benefit (expense) from discontinued operations | | | (26 | ) | | | (24 | ) | | | 67 | | | | (102 | ) |
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Net income (loss) | | $ | 29 | | | $ | 78 | | | $ | (195 | ) | | $ | 156 | |
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| (3) | A reconciliation of EBITDA from discontinued operations to Income from discontinued operations, net of tax for the periods presented is included below. |
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| | | Three Months Ended
September 30,
| | | Nine Months Ended
September 30,
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| | | 2005
| | | 2004
| | | 2005
| | | 2004
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EBITDA from discontinued operations | | $ | 86 | | | $ | 91 | | | $ | 232 | | | $ | 297 | |
Depreciation and amortization expense from discontinued operations | | | (2 | ) | | | (21 | ) | | | (37 | ) | | | (66 | ) |
Interest expense from discontinued operations | | | (15 | ) | | | (10 | ) | | | (40 | ) | | | (16 | ) |
Income tax benefit (expense) from discontinued operations | | | (26 | ) | | | (24 | ) | | | 67 | | | | (102 | ) |
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Income from discontinued operations, net of tax | | $ | 43 | | | $ | 36 | | | $ | 222 | | | $ | 113 | |
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DYNEGY INC.
REPORTED UNAUDITED BASIC AND DILUTED EARNINGS (LOSS) PER SHARE FROM CONTINUING OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE DATA)
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| | | Three Months Ended
September 30,
| | Nine Months Ended
September 30,
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| | | 2005
| | | 2004
| | 2005
| | | 2004
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Income (loss) from continuing operations | | $ | (14 | ) | | $ | 42 | | $ | (417 | ) | | $ | 43 |
Less: convertible preferred stock dividends | | | 6 | | | | 6 | | | 17 | | | | 17 |
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Income (loss) from continuing operations for basic loss per share | | | (20 | ) | | | 36 | | | (434 | ) | | | 26 |
Effect of dilutive securities: | | | | | | | | | | | | | | |
Interest on convertible debentures (see Note 6) Interest on convertible subordinated debentures (2) | | | 2 | | | | 2 | | | 5 | | | | — |
Dividends on Series C convertible preferred stock (2) | | | 6 | | | | 6 | | | 17 | | | | — |
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Income (loss) from continuing operations for diluted loss per share | | $ | (12 | ) | | $ | 44 | | $ | (412 | ) | | $ | 26 |
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|
Basic weighted-average shares | | | 390 | | | | 379 | | | 383 | | | | 378 |
| | | | |
Effect of dilutive securities: | | | | | | | | | | | | | | |
Stock options Stock options and restricted stock | | | 2 | | | | 2 | | | 2 | | | | 2 |
Convertible debentures (see Note 6) Convertible subordinated debentures (2) | | | 55 | | | | 54 | | | 55 | | | | — |
Series C convertible preferred stock (2) | | | 69 | | | | 69 | | | 69 | | | | — |
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|
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|
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|
Diluted weighted-average shares | | | 516 | | | | 504 | | | 509 | | | | 380 |
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|
|
Income (loss) per share from continuing operations: | | | | | | | | | | | | | | |
Basic Basic | | $ | (0.05 | ) | | $ | 0.10 | | $ | (1.13 | ) | | $ | 0.07 |
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Diluted (1) | | $ | (0.05 | ) | | $ | 0.09 | | $ | (1.13 | ) | | $ | 0.07 |
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| (1) | When an entity has a net loss from continuing operations, SFAS No. 128, “Earnings per Share,” prohibits the inclusion of potential common shares in the computation of diluted per-share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three and nine months ended September 30, 2005. |
| (2) | The diluted shares for the nine months ended September 30, 2004 do not include the effect of the preferential conversion to Class B common stock of the Series C convertible preferred stock held by a Chevron subsidiary and the interest on the convertible subordinated debentures, as such inclusion would be anti-dilutive. |
- more -
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, 2005
| |
| | | GEN
| | NGL
| | REG
| | CRM
| | | OTHER
| | | Total
| |
Generation | | $ | 115 | | | | | | | | | | | | | | | | $ | 115 | |
Natural Gas Liquids | | | | | | | | | | | | | | | | | | | | | |
Upstream | | | | | $ | — | | | | | | | | | | | | | | — | |
Downstream | | | | | | — | | | | | | | | | | | | | | — | |
Regulated Energy Delivery | | | | | | | | $ | — | | | | | | | | | | | — | |
Customer Risk Management | | | | | | | | | | | $ | (18 | ) | | | | | | | (18 | ) |
Other | | | | | | | | | | | | | | | $ | (32 | ) | | | (32 | ) |
| | |
|
| |
|
| |
|
| |
|
|
| |
|
|
| |
|
|
|
Operating income (loss) | | | 115 | | | — | | | — | | | (18 | ) | | | (32 | ) | | $ | 65 | |
Earnings from unconsolidated investments | | | 7 | | | — | | | — | | | — | | | | — | | | | 7 | |
Other items, net | | | 2 | | | — | | | — | | | (5 | ) | | | 3 | | | | — | |
Add: Depreciation and amortization expense, a component of operating income (loss) | | | 53 | | | — | | | — | | | — | | | | 3 | | | | 56 | |
| | |
|
| |
|
| |
|
| |
|
|
| |
|
|
| |
|
|
|
EBITDA from continuing operations (1) | | | 177 | | | — | | | — | | | (23 | ) | | | (26 | ) | | | 128 | |
EBITDA from discontinued operations, pre-tax (2) | | | — | | | 88 | | | — | | | (2 | ) | | | — | | | | 86 | |
| | |
|
| |
|
| |
|
| |
|
|
| |
|
|
| |
|
|
|
EBITDA (1) | | $ | 177 | | $ | 88 | | $ | — | | $ | (25 | ) | | $ | (26 | ) | | $ | 214 | |
Depreciation and amortization expense | | | | | | | | | | | | | | | | | | | | (58 | ) |
Interest expense | | | | | | | | | | | | | | | | | | | | (114 | ) |
| | | | | | | | | | | | | | | | | | | |
|
|
|
Pre-tax income | | | | | | | | | | | | | | | | | | | | 42 | |
Income tax expense | | | | | | | | | | | | | | | | | | | | (13 | ) |
| | | | | | | | | | | | | | | | | | | |
|
|
|
Net income | | | | | | | | | | | | | | | | | | | $ | 29 | |
| | | | | | | | | | | | | | | | | | | |
|
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, 2004
| |
| | | GEN
| | NGL
| | REG
| | CRM
| | | OTHER
| | | Total
| |
Generation | | $ | 71 | | | | | | | | | | | | | | | | $ | 71 | |
Natural Gas Liquids | | | | | | | | | | | | | | | | | | | | | |
Upstream | | | | | $ | — | | | | | | | | | | | | | | — | |
Downstream | | | | | | — | | | | | | | | | | | | | | — | |
Regulated Energy Delivery | | | | | | | | $ | 83 | | | | | | | | | | | 83 | |
Customer Risk Management | | | | | | | | | | | $ | (32 | ) | | | | | | | (32 | ) |
Other | | | | | | | | | | | | | | | $ | (57 | ) | | | (57 | ) |
| | |
|
| |
|
| |
|
| |
|
|
| |
|
|
| |
|
|
|
Operating income (loss) | | | 71 | | | — | | | 83 | | | (32 | ) | | | (57 | ) | | $ | 65 | |
Earnings from unconsolidated investments | | | 99 | | | — | | | — | | | — | | | | — | | | | 99 | |
Other items, net | | | — | | | — | | | 2 | | | (3 | ) | | | 1 | | | | — | |
Add: Depreciation and amortization expense, a component of operating income (loss) | | | 50 | | | — | | | — | | | 1 | | | | 7 | | | | 58 | |
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|
| |
|
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|
| |
|
|
| |
|
|
| |
|
|
|
EBITDA from continuing operations (1) | �� | | 220 | | | — | | | 85 | | | (34 | ) | | | (49 | ) | | | 222 | |
EBITDA from discontinued operations, pre-tax (2) | | | — | | | 92 | | | — | | | (1 | ) | | | — | | | | 91 | |
| | |
|
| |
|
| |
|
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|
|
| |
|
|
| |
|
|
|
EBITDA (1) | | $ | 220 | | $ | 92 | | $ | 85 | | $ | (35 | ) | | $ | (49 | ) | | $ | 313 | |
Depreciation and amortization expense, a component of operating income (loss) | | | | | | | | | | | | | | | | | | | | (79 | ) |
Interest expense | | | | | | | | | | | | | | | | | | | | (125 | ) |
| | | | | | | | | | | | | | | | | | | |
|
|
|
Pre-tax income | | | | | | | | | | | | | | | | | | | | 109 | |
Income tax expense | | | | | | | | | | | | | | | | | | | | (31 | ) |
| | | | | | | | | | | | | | | | | | | |
|
|
|
Net income | | | | | | | | | | | | | | | | | | | $ | 78 | |
| | | | | | | | | | | | | | | | | | | |
|
|
|
| (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.” |
- more -
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | |
| | | Nine Months Ended September 30, 2005
| |
| | | GEN
| | NGL
| | REG
| | CRM
| | | OTHER
| | | Total
| |
Generation | | $ | 194 | | | | | | | | | | | | | | | | $ | 194 | |
Natural Gas Liquids | | | | | | | | | | | | | | | | | | | | | |
Upstream | | | | | $ | — | | | | | | | | | | | | | | — | |
Downstream | | | | | | — | | | | | | | | | | | | | | — | |
Regulated Energy Delivery | | | | | | | | $ | — | | | | | | | | | | | — | |
Customer Risk Management | | | | | | | | | | | $ | (225 | ) | | | | | | | (225 | ) |
Other | | | | | | | | | | | | | | | $ | (353 | ) | | | (353 | ) |
| | |
|
| |
|
| |
|
| |
|
|
| |
|
|
| |
|
|
|
Operating income (loss) | | | 194 | | | — | | | — | | | (225 | ) | | | (353 | ) | | $ | (384 | ) |
Earnings from unconsolidated investments | | | 14 | | | — | | | — | | | — | | | | — | | | | 14 | |
Other items, net | | | 4 | | | — | | | — | | | (5 | ) | | | 10 | | | | 9 | |
Add: Depreciation and amortization expense, a component of operating income (loss) | | | 150 | | | — | | | — | | | 1 | | | | 14 | | | | 165 | |
| | |
|
| |
|
| |
|
| |
|
|
| |
|
|
| |
|
|
|
EBITDA from continuing operations (1) | | | 362 | | | — | | | — | | | (229 | ) | | | (329 | ) | | | (196 | ) |
EBITDA from discontinued operations, pre-tax (2) | | | — | | | 229 | | | — | | | 3 | | | | — | | | | 232 | |
| | |
|
| |
|
| |
|
| |
|
|
| |
|
|
| |
|
|
|
EBITDA (1) | | $ | 362 | | $ | 229 | | $ | — | | $ | (226 | ) | | $ | (329 | ) | | $ | 36 | |
Depreciation and amortization expense | | | | | | | | | | | | | | | | | | | | (202 | ) |
Interest expense | | | | | | | | | | | | | | | | | | | | (324 | ) |
| | | | | | | | | | | | | | | | | | | |
|
|
|
Pre-tax loss | | | | | | | | | | | | | | | | | | | | (490 | ) |
Income tax benefit | | | | | | | | | | | | | | | | | | | | 295 | |
| | | | | | | | | | | | | | | | | | | |
|
|
|
Net loss | | | | | | | | | | | | | | | | | | | $ | (195 | ) |
| | | | | | | | | | | | | | | | | | | |
|
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Nine Months Ended September 30, 2004
| |
| | | GEN
| | NGL
| | REG
| | CRM
| | | OTHER
| | | Total
| |
Generation | | $ | 159 | | | | | | | | | | | | | | | | $ | 159 | |
Natural Gas Liquids | | | | | | | | | | | | | | | | | | | | | |
Upstream | | | | | $ | — | | | | | | | | | | | | | | — | |
Downstream | | | | | | — | | | | | | | | | | | | | | — | |
Regulated Energy Delivery | | | | | | | | $ | 158 | | | | | | | | | | | 158 | |
Customer Risk Management | | | | | | | | | | | $ | 45 | | | | | | | | 45 | |
Other | | | | | | | | | | | | | | | $ | (201 | ) | | | (201 | ) |
| | |
|
| |
|
| |
|
| |
|
|
| |
|
|
| |
|
|
|
Operating income (loss) | | | 159 | | | — | | | 158 | | | 45 | | | | (201 | ) | | $ | 161 | |
Earnings (losses) from unconsolidated investments | | | 187 | | | — | | | — | | | — | | | | — | | | | 187 | |
Other items, net | | | — | | | — | | | 3 | | | (1 | ) | | | 4 | | | | 6 | |
Add: Depreciation and amortization expense, a component of operating income (loss) | | | 145 | | | — | | | 10 | | | 1 | | | | 27 | | | | 183 | |
| | |
|
| |
|
| |
|
| |
|
|
| |
|
|
| |
|
|
|
EBITDA from continuing operations (1) | | | 491 | | | — | | | 171 | | | 45 | | | | (170 | ) | | | 537 | |
EBITDA from discontinued operations, pre-tax (2) | | | — | | | 277 | | | — | | | 17 | | | | 3 | | | | 297 | |
| | |
|
| |
|
| |
|
| |
|
|
| |
|
|
| |
|
|
|
EBITDA (1) | | $ | 491 | | $ | 277 | | $ | 171 | | $ | 62 | | | $ | (167 | ) | | $ | 834 | |
Depreciation and amortization expense, a component of operating income (loss) | | | | | | | | | | | | | | | | | | | | (249 | ) |
Interest expense | | | | | | | | | | | | | | | | | | | | (402 | ) |
| | | | | | | | | | | | | | | | | | | |
|
|
|
Pre-tax income | | | | | | | | | | | | | | | | | | | | 183 | |
Income tax expense | | | | | | | | | | | | | | | | | | | | (27 | ) |
| | | | | | | | | | | | | | | | | | | |
|
|
|
Net income | | | | | | | | | | | | | | | | | | | $ | 156 | |
| | | | | | | | | | | | | | | | | | | |
|
|
|
| (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.” |
- more -
DYNEGY INC.
SIGNIFICANT ITEMS
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, 2005
| |
| | | GEN
| | NGL
| | REG
| | CRM
| | | OTHER
| | Total
| |
Legal and settlement charges (1) | | $ | — | | $ | — | | $ | — | | $ | (29 | ) | | $ | 4 | | $ | (25 | ) |
Discontinued operations (2) | | | — | | | 71 | | | — | | | (2 | ) | | | — | | | 69 | |
| | |
|
| |
|
| |
|
| |
|
|
| |
|
| |
|
|
|
Total | | $ | — | | $ | 71 | | $ | — | | $ | (31 | ) | | $ | 4 | | $ | 44 | |
| | |
|
| |
|
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|
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|
|
| |
|
| |
|
|
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, 2004
| |
| | | GEN
| | | NGL
| | REG
| | | CRM
| | | Other
| | Total
| |
Impairment of West Coast Power (3) | | $ | (45 | ) | | $ | — | | $ | — | | | $ | — | | | $ | — | | $ | (45 | ) |
Loss on sale of Illinois Power (4) | | | — | | | | — | | | (24 | ) | | | — | | | | — | | | (24 | ) |
Gain on sale of Joppa (5) | | | 75 | | | | — | | | — | | | | — | | | | — | | | 75 | |
Gain on sale of Oyster Creek (6) | | | 15 | | | | — | | | — | | | | — | | | | — | | | 15 | |
Taxes (7) | | | — | | | | — | | | — | | | | — | | | | 13 | | | 13 | |
Discontinued operations (8) | | | — | | | | 61 | | | — | | | | (1 | ) | | | — | | | 60 | |
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|
|
| |
|
| |
|
|
| |
|
|
| |
|
| |
|
|
|
Total | | $ | 45 | | | $ | 61 | | $ | (24 | ) | | $ | (1 | ) | | $ | 13 | | $ | 94 | |
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|
|
| |
|
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|
|
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|
|
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|
| |
|
|
|
| (1) | We recognized a pre-tax loss of approximately $25 million ($15 million after-tax) related to legal and settlement charges. A benefit of $4 million ($3 million after-tax) is included in the pre-tax loss of approximately $25 million related to the settlement of our class action shareholder lawsuit. This loss is included in General and administrative expenses. |
| (2) | We recognized a pre-tax gain of approximately $69 million ($43 million after-tax) related to discontinued operations. The gain consists primarily of income associated with our NGL segment of $71 million, which was reclassified to discontinued operations due to the anticipated sale of DMSLP. Included in the $71 million of income from our NGL segment is a pre-tax gain of approximately $10 million ($7 million after-tax) on the sale of the Port Everglades property. |
| (3) | We recognized a pre-tax charge of approximately $45 million ($28 million after-tax) related to an impairment of our investment in West Coast Power. This charge is included in Earnings from unconsolidated investments. |
| (4) | We recognized a pre-tax loss of approximately $24 million ($15 million after-tax) related to the sale of Illinois Power. This charge is included in Loss on sale of assets, net. |
| (5) | 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 from unconsolidated investments. |
| (6) | 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 from unconsolidated investments. |
| (7) | We recognized a net income tax benefit of approximately $13 million primarily related to the release of a deferred tax valuation allowance related to anticipated gains on asset sales. |
| (8) | We recognized a pre-tax gain of approximately $60 million ($36 million after-tax) related to discontinued operations. The gain consists primarily of income associated with our NGL segment of $61 million, which was reclassified to discontinued operations due to the anticipated sale of DMSLP. |
- more -
DYNEGY INC.
SIGNIFICANT ITEMS
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | |
| | | Nine Months Ended September 30, 2005
| |
| | | GEN
| | NGL
| | REG
| | CRM
| | | OTHER
| | | Total
| |
Legal and settlement charges (1) | | $ | — | | $ | — | | $ | — | | $ | (29 | ) | | $ | (249 | ) | | $ | (278 | ) |
Independence toll settlement charge (2) | | | — | | | — | | | — | | | (169 | ) | | | — | | | | (169 | ) |
Discontinued operations (3) | | | — | | | 152 | | | — | | | 3 | | | | — | | | | 155 | |
Taxes (4) | | | — | | | — | | | — | | | — | | | | 125 | | | | 125 | |
| | |
|
| |
|
| |
|
| |
|
|
| |
|
|
| |
|
|
|
Total | | $ | — | | $ | 152 | | $ | — | | $ | (195 | ) | | $ | (124 | ) | | $ | (167 | ) |
| | |
|
| |
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|
|
| |
|
|
| |
|
|
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Nine Months Ended September 30, 2004
| |
| | | GEN
| | | NGL
| | REG
| | | CRM
| | OTHER
| | | Total
| |
Illinois Power asset impairment and loss on sale (5) | | $ | — | | | $ | — | | $ | (93 | ) | | $ | — | | $ | — | | | $ | (93 | ) |
Legal and settlement charges (6) | | | 2 | | | | — | | | (1 | ) | | | — | | | (57 | ) | | | (56 | ) |
Impairment of West Coast Power (7) | | | (45 | ) | | | — | | | — | | | | — | | | — | | | | (45 | ) |
Acceleration of financing costs (8) | | | — | | | | — | | | — | | | | — | | | (14 | ) | | | (14 | ) |
Gas transportation contracts (9) | | | — | | | | — | | | — | | | | 88 | | | — | | | | 88 | |
Gain on sale of Joppa (10) | | | 75 | | | | — | | | — | | | | — | | | — | | | | 75 | |
Taxes (11) | | | — | | | | — | | | — | | | | — | | | 43 | | | | 43 | |
Gain on sale of Oyster Creek (12) | | | 15 | | | | — | | | — | | | | — | | | — | | | | 15 | |
Discontinued operations (13) | | $ | — | | | $ | 195 | | $ | — | | | $ | 17 | | $ | 3 | | | $ | 215 | |
| | |
|
|
| |
|
| |
|
|
| |
|
| |
|
|
| |
|
|
|
Total | | $ | 47 | | | $ | 195 | | $ | (94 | ) | | $ | 105 | | $ | (25 | ) | | $ | 228 | |
| | |
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|
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|
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| |
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|
| |
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|
|
| (1) | We recognized a pre-tax loss of approximately $278 million ($191 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. |
| (2) | We recognized a pre-tax loss of approximately $169 million ($109 million after-tax) related to the Independence toll settlement 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. |
| (3) | We recognized a pre-tax gain of approximately $155 million ($222 million after-tax) related to discontinued operations. The gain consists primarily of income associated with our NGL segment of $152 million, which was reclassified to discontinued operations due to the anticipated sale of DMSLP, and a $3 million pre-tax gain on our UK CRM business. Included in the $152 million of income from our NGL segment is a pre-tax gain of approximately $10 million ($7 million after-tax) on the sale of the Port Everglades property. |
| (4) | We recognized an income tax benefit of approximately $125 million for the reversal of a deferred tax capital loss valuation allowance primarily related to gains on the anticipated sale of DMSLP. The benefit is included in the $222 million after-tax Income from discontinued operations. |
| (5) | We recognized a pre-tax loss of approximately $93 million ($58 million after-tax) related to expenses expected to be incurred in connection with the sale of Illinois Power and impairment of assets. The loss is included in Loss on sale of assets, net, and Impairment and other charges. |
| (6) | We recognized a pre-tax loss of approximately $56 million ($35 million after-tax) related to legal and settlement charges. The loss is primarily included in General and administrative expenses and Impairment and other charges. |
| (7) | We recognized a pre-tax charge of approximately $45 million ($28 million after-tax) related to an impairment of our investment in West Coast Power. This charge is included in Earnings from unconsolidated investments. |
| (8) | 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 a $600 million term loan. This charge is included in Interest expense. |
| (9) | 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. |
| (10) | 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 from unconsolidated investments. |
| (11) | We recognized a net income tax benefit of approximately $43 million for the reversal of a deferred tax capital loss valuation allowance related to anticipated gains on asset sales offset by charges resulting from the conclusion of prior year tax audits. A benefit of $63 million is included in Income tax benefit, partially offset by a $20 million charge in the $113 million after-tax Income from discontinued operations. |
| (12) | 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 from unconsolidated investments. |
| (13) | We recognized a pre-tax gain of approximately $215 million ($113 million after-tax) related to discontinued operations. The gain consists primarily of income associated with our NGL segment of $195 million, which was reclassified to discontinued operations due to the anticipated sale of DMSLP, $17 million pre-tax gain on our UK CRM business and a $3 million pre-tax gain associated with our global communications business. Included in the $195 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 and 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. |
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DYNEGY INC.
SUMMARY CASH FLOW INFORMATION
(UNAUDITED) (IN MILLIONS)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Nine Months Ended September 30, 2005
| |
| | | GEN
| | | NGL
| | | REG
| | | CRM
| | | OTHER
| | | Total
| |
Cash Flow from Operations | | $ | 354 | | | $ | 241 | | | $ | — | | | $ | (64 | ) | | $ | (709 | ) | | $ | (178 | ) |
| | | | | | |
Capital Expenditures | | | (87 | ) | | | (39 | ) | | | — | | | | — | | | | (6 | ) | | | (132 | ) |
| | | | | | |
Business Acquisition Costs | | | (120 | ) | | | — | | | | — | | | | — | | | | — | | | | (120 | ) |
| | | | | | |
Proceeds from Asset Sales (1) | | | 1 | | | | 10 | | | | (5 | ) | | | — | | | | 100 | | | | 106 | |
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Free Cash Flow (2) | | $ | 148 | | | $ | 212 | | | $ | (5 | ) | | $ | (64 | ) | | $ | (615 | ) | | $ | (324 | ) |
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| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Nine Months Ended September 30, 2004
| |
| | | GEN
| | | NGL
| | | REG
| | | CRM
| | | OTHER
| | | Total
| |
Cash Flow from Operations | | $ | 351 | | | $ | 194 | | | $ | 213 | | | $ | (179 | ) | | $ | (459 | ) | | $ | 120 | |
| | | | | | |
Capital Expenditures | | | (78 | ) | | | (41 | ) | | | (92 | ) | | | — | | | | (10 | ) | | | (221 | ) |
| | | | | | |
Proceeds from Asset Sales | | | 245 | | | | 65 | | | | 217 | | | | — | | | | — | | | | 527 | |
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Free Cash Flow (2) | | $ | 518 | | | $ | 218 | | | $ | 338 | | | $ | (179 | ) | | $ | (469 | ) | | $ | 426 | |
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| (1) | During the first quarter 2005, we paid approximately $5 million to Ameren related to the working capital adjustment for our sale of Illinois Power. |
| (2) | Free cash flow is a non-GAAP financial measure. Free cash flow consists of cash flows from operations less capital expenditures and business acquisition costs, net, adjusted for proceeds from asset sales. We use free cash flow to measure the cash generating ability of our operating asset-based energy businesses relative to their capital expenditure obligations. Free cash flow should not be used in lieu of GAAP measures with respect to cash flows and should not be interpreted as available for discretionary expenditures, as mandatory expenditures such as debt obligations are not deducted from the measure. A reconciliation of free cash flow to cash flow from operations by segment for the periods presented is included above. |
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DYNEGY INC.
OPERATING DATA
| | | | | | | | | | | | |
| | | Three Months Ended
September 30,
| | Nine Months Ended
September 30,
|
| | | 2005
| | 2004
| | 2005
| | 2004
|
GEN | | | | | | | | | | | | |
Million Megawatt Hours Generated - Gross | | | 11.2 | | | 9.6 | | | 28.7 | | | 29.3 |
Million Megawatt Hours Generated - Net | | | 11.0 | | | 9.1 | | | 27.8 | | | 27.8 |
| | | | |
Average Natural Gas Price - Henry Hub ($/MMBtu) (1) | | $ | 9.66 | | $ | 5.49 | | $ | 7.66 | | $ | 5.73 |
Average On-Peak Market Power Prices ($/MWh): | | | | | | | | | | | | |
Cinergy | | $ | 80 | | $ | 43 | | $ | 61 | | $ | 43 |
Commonwealth Edison (NI Hub) | | $ | 75 | | $ | 41 | | $ | 59 | | $ | 42 |
Southern | | $ | 90 | | $ | 50 | | $ | 65 | | $ | 49 |
New York - Zone G | | $ | 110 | | $ | 57 | | $ | 86 | | $ | 61 |
New York - Zone A | | $ | 91 | | $ | 48 | | $ | 70 | | $ | 52 |
ERCOT | | $ | 107 | | $ | 50 | | $ | 76 | | $ | 47 |
SP-15 | | $ | 83 | | $ | 57 | | $ | 65 | | $ | 53 |
| | | | |
NGL | | | | | | | | | | | | |
Field Plant Gross NGL Production (MBbls/d) | | | 55.1 | | | 58.9 | | | 56.2 | | | 57.6 |
Straddle Plant Gross NGL Production (MBbls/d) | | | 18.5 | | | 29.6 | | | 25.9 | | | 25.7 |
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Total Gross NGL Production | | | 73.6 | | | 88.5 | | | 82.1 | | | 83.3 |
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Natural Gas (Residue) Sales (BBtu/d) | | | 187.9 | | | 190.7 | | | 184.4 | | | 185.2 |
| | | | |
Natural Gas Field Plant Inlet Volumes (MMCFD) | | | 512.4 | | | 545.8 | | | 515.6 | | | 549.4 |
Natural Gas Straddle Plant Inlet Volumes (MMCFD) | | | 794.1 | | | 1,249.9 | | | 1,113.5 | | | 968.8 |
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Total Natural Gas Inlet Volumes | | | 1,306.5 | | | 1,795.7 | | | 1,629.1 | | | 1,518.2 |
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Fractionation Volumes (MBbls/d) | | | 185.4 | | | 257.2 | | | 174.3 | | | 218.6 |
Natural Gas Liquids Sold (MBbls/d) | | | 262.8 | | | 290.4 | | | 266.4 | | | 281.4 |
| | | | |
Average Commodity Prices: | | | | | | | | | | | | |
Crude Oil - WTI ($/Bbl) | | $ | 60.30 | | $ | 42.22 | | $ | 53.44 | | $ | 38.51 |
Natural Gas - Henry Hub ($/MMBtu) (2) | | $ | 8.51 | | $ | 5.76 | | $ | 7.18 | | $ | 5.81 |
Natural Gas Liquids ($/Gal) | | $ | 0.96 | | $ | 0.75 | | $ | 0.84 | | $ | 0.67 |
Fractionation Spread ($/MMBtu) - daily | | $ | 1.76 | | $ | 2.93 | | $ | 2.34 | | $ | 1.84 |
| | | | |
REG(3) | | | | | | | | | | | | |
Electric Sales in KWH (Millions): | | | | | | | | | | | | |
Residential | | | — | | | 1,592 | | | — | | | 4,182 |
Commercial | | | — | | | 1,217 | | | — | | | 3,389 |
Industrial | | | — | | | 1,168 | | | — | | | 3,859 |
Transportation of Customer-Owned Electricity | | | — | | | 975 | | | — | | | 2,407 |
Other | | | — | | | 99 | | | — | | | 287 |
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Total Electricity Delivered | | | — | | | 5,051 | | | — | | | 14,124 |
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Gas Sales in Therms (Millions): | | | | | | | | | | | | |
Residential | | | — | | | 20 | | | — | | | 214 |
Commercial | | | — | | | 11 | | | — | | | 85 |
Industrial | | | — | | | 11 | | | — | | | 40 |
Transportation of Customer-Owned Gas | | | — | | | 46 | | | — | | | 171 |
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Total Gas Delivered | | | — | | | 88 | | | — | | | 510 |
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Cooling Degree Days - Actual | | | — | | | 559 | | | — | | | 932 |
Cooling Degree Days - 10 year rolling average | | | — | | | 862 | | | — | | | 1,236 |
Heating Degree Days - Actual | | | — | | | 49 | | | — | | | 3,145 |
Heating Degree Days - 10 year rolling average | | | — | | | 59 | | | — | | | 3,190 |
| (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. |
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DYNEGY INC.
2005 EARNINGS GUIDANCE ESTIMATES (1)
(IN MILLIONS)
| | | | | | | | | | | | | | | | | | |
| | | GEN
| | CRM
| | OTHER
| | Total Core
Business
| | Non-Core (3)
| | Total
|
EBITDA (2) | | $ | 480 - 500 | | $ | (55) | | $ | (100 - 95) | | $ | 325 - 350 | | $ | 918 | | $ | 1,243 - 1,268 |
| | | | | | |
Depreciation and Amortization | | | (210) | | | — | | | (15) | | | (225) | | | (37) | | | (262) |
| | | | | | |
Interest Expense | | | | | | | | | | | | (385) | | | (50) | | | (435) |
| | | | | | |
Income Tax Benefit (Expense) | | | | | | | | | | | | 112 - 107 | | | (201) | | | (89 - 94) |
| | | | | | |
Preferred stock dividends | | | | | | | | | | | | (22) | | | — | | | (22) |
| | | | | | | | | | | |
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|
Net Income (Loss) | | | | | | | | | | | $ | (195 - 175) | | $ | 630 | | $ | 435 - 455 |
| | | | | | | | | | | |
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|
2005 CASH FLOW GUIDANCE ESTIMATES (1)
(IN MILLIONS)
| | | | | | | | | | | | |
| | | GEN
| | CRM
| | OTHER
| | Total Core
Business
| | Non-Core (5)
| | Total
|
Cash Flow from Operations | | $ 465 - 470 | | $(50) | | $ (490 - 485) | | $ (75 - 65) | | $(23) | | $ (98 - 88) |
Capital Expenditures and Business Acquisitions | | (130) | | — | | (6) | | (136) | | (202) | | (338) |
Proceeds from Asset Sales | | — | | — | | — | | — | | 2,450 | | 2,450 |
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| |
| |
| |
| |
| |
|
Free Cash Flow (4) | | $ 335 - 340 | | $(50) | | $ (496 - 491) | | $ (211 - 201) | | $2,225 | | $ 2,014 - 2,024 |
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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. 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) | The following summarizes the items included in Non-core business in our earnings guidance estimate. |
| | | | | | | | | | | | | | | | | | | | |
| | | EBITDA
| | | Depreciation and
Amortization
| | | Interest Expense
| | | Income Tax
Benefit (Expense)
| | | Net Income
(Loss)
| |
Independence toll settlement charge (CRM segment) | | $ | (169 | ) | | $ | — | | | $ | — | | | $ | 60 | | | $ | (109 | ) |
Legal and settlement charges (CRM and Other segment) | | | (278 | ) | | | — | | | | — | | | | 87 | | | | (191 | ) |
NGL operating results (NGL segment) | | | 265 | | | | (37 | ) | | | (50 | ) | | | (66 | ) | | | 112 | |
Gain on sale of NGL (NGL segment) | | | 1,100 | | | | — | | | | — | | | | (282 | ) | | | 818 | |
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|
| |
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|
|
Total | | $ | 918 | | | $ | (37 | ) | | $ | (50 | ) | | $ | (201 | ) | | $ | 630 | |
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|
|
| (4) | 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. |
| (5) | The following summarizes the items included in Non-core business in our cash flow guidance estimate. |
| | | | | | | | | | | | | | | | |
| | | Cash Flow from
Operations
| | | Capital Exp. and
Business Acq.
| | | Proceeds from
Asset Sales
| | | Free Cash Flows
| |
ANR/Middleton Gas Payment (CRM segment) | | $ | (26 | ) | | $ | — | | | $ | — | | | $ | (26 | ) |
Sithe Energies Acquisition (GEN segment) | | | — | | | | (120 | ) | | | — | | | | (120 | ) |
Baldwin Escrow Release (Other segment) | | | — | | | | — | | | | 100 | | | | 100 | |
Legal and settlement charges (Other segment) | | | (268 | ) | | | — | | | | — | | | | (268 | ) |
Illinois Power Working Capital / Other (Other segment) | | | (9 | ) | | | — | | | | (5 | ) | | | (14 | ) |
NGL operating and investing cash flow (NGL segment) | | | 280 | | | | — | | | | 10 | | | | 290 | |
NGL capital expenditures (NGL segment) | | | — | | | | (47 | ) | | | — | | | | (47 | ) |
Net proceeds from sale of NGL (NGL segment) | | | — | | | | — | | | | 2,345 | | | | 2,345 | |
Development Capital Expenditures (All segments) | | | — | | | | (35 | ) | | | — | | | | (35 | ) |
| | |
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|
|
Total | | $ | (23 | ) | | $ | (202 | ) | | $ | 2,450 | | | $ | 2,225 | |
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-end-
