CPN: NYSE 15.12
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America’s Premier Power Generation Company
... Creating Power for a Sustainable Future

Calpine Corp. Reports 2008 Fourth Quarter and Full Year Results, with Strong Year-over-Year Results and Liquidity; Provides 2009 Guidance

02/27/2009

Full Year 2008 Highlights:

  • $9.9 billion of Operating Revenues, a 25% increase from 2007
  • $2.7 billion of Commodity Margin, a 22% increase from 2007
  • $1.7 billion of Adjusted EBITDA, an 18% increase from 2007
  • $2.2 billion of liquidity, a 24% increase from 2007

Fourth Quarter 2008 Highlights:

  • $2.0 billion of Operating Revenues
  • $597 million of Commodity Margin
  • $325 million of Adjusted EBITDA

2008 Operational Highlights:

  • Generated 89.0 million MWh of power, the most among pure-play U.S. IPPs, including over 6 million MWh of renewable baseload power at The Geysers geothermal facilities
  • Substantially hedged 2009 projected volume to mitigate recessionary influences
  • Commenced commercial operations at the 1,005 MW Greenfield Energy Centre
  • Delivered first quartile safety performance for the fourth consecutive year

2009 Guidance:

  • Adjusted EBITDA guidance of $1.6-1.7 billion
  • Adjusted Free Cash Flow guidance of $400-500 million

HOUSTON & SAN JOSE, Calif.--(BUSINESS WIRE)--Feb. 27, 2009-- Calpine Corporation (NYSE:CPN) today reported operating revenues of $9.9 billion for the year ended December 31, 2008, compared to$8.0 billion in the prior year. Commodity Margin for the full year 2008 was $2.7 billion compared to $2.2 billion in 2007. Adjusted EBITDA increased to $1.7 billion in 2008 from $1.4 billion in 2007.

“Our full year 2008 financial performance reflects substantial improvement compared to 2007 and exceeds our 2008 guidance, despite the severe economic and financial conditions that surfaced in late 2008,” said Jack Fusco , Calpine’s President and Chief Executive Officer. “With 2008 successfully behind us, we now turn our attention to 2009. We are pleased to provide Adjusted EBITDA guidance for 2009 of$1.6 to $1.7 billion and, for the first time, Adjusted Free Cash Flow guidance of $400 to $500 million. We have significantly hedged our 2009 Commodity Margin, mitigating natural gas price risk and giving us solid earnings visibility for this year. It is noteworthy that our 2009 Adjusted EBITDA guidance is roughly in line with our 2008 performance, despite expectations that recessionary pressures will continue through 2009. Finally, we are pleased to report that we have significantly hedged our natural gas price risk for 2010.”

Our Commodity Margin increased by $485 million in 2008, largely as a result of strong performance in ourTexas region, where Commodity Margin increased by 63% over 2007, and from improved performance associated with our fleet-wide hedging program. Adjusted EBITDA increased by $254 million in 2008 compared to 2007, primarily due to the increase in Commodity Margin discussed above, offset largely by greater cash-realized mark-to-market losses associated with our hedging activities, and, to a lesser degree, an increase in plant operating expense (net of major maintenance expense and non-cash stock-based compensation expense) and higher sales, general and other administrative expense (net of non-cash stock-based compensation expense).

Cash flows provided by operating activities for the year ended December 31, 2008, resulted in net inflows of $494 million compared to net inflows of $187 million for the same period in 2007. A primary reason for this improvement was that gross profit, excluding changes in depreciation and impairments, increased by$222 million in 2008 due primarily to increases in Commodity Margin, as previously discussed. The favorable margins were partially offset by higher plant operating expenses and higher sales, general and administrative expenses, as previously mentioned. In addition, working capital employed relating to operating assets and liabilities changed by approximately $53 million during the year, after adjusting for actual cash flows from derivative activities that are included in net derivative assets and liabilities. This increase was primarily the result of a slight increase in inventory levels compared to 2007.

We believe that a comparison of net income (loss), as reported, from 2007 to 2008 is not meaningful, as both periods include significant impacts from restructuring during bankruptcy and other one-time items. Net income or loss, excluding reorganization items, discontinued operations, other one-time items and non-cash mark-to-market gains or losses improved by $340 million in 2008 to income of $15 million, compared to a loss of $325 million in 2007. This year-over-year increase is primarily attributed to the increase in Commodity Margin, as previously discussed.

For the 2008 fourth quarter, operating revenues increased to $2.0 billion from $1.9 billion in the prior year period. Net loss, excluding reorganization items, discontinued operations, other one-time items and non-cash mark-to-market gains or losses was $146 million in the fourth quarter of 2008, compared to $90 million for the same period of 2007.

SUMMARY OF FINANCIAL PERFORMANCE

Table 1: Summarized Consolidated Statements of Operations

(Unaudited)
Three Months Ended December 31, Years Ended December 31,
2008 2007 2008 2007
(in millions)
Operating revenues $ 1,968 $ 1,924 $ 9,937 $ 7,970
Cost of revenue (1,791 ) (1,766 ) (8,779 ) (7,075 )
Gross profit 177 158 1,158 895
SG&A, loss from unconsolidated investments in power plants and other operating expenses (112 ) (54 ) (470 ) (190 )
Income from operations 65 104 688 705
Net interest expense, minority interest and other (income) expense (223 ) (817 ) (1,050 ) (1,816 )
Loss before reorganization items, income taxes and discontinued operations (158 ) (713 ) (362 ) (1,111 )
Reorganization items (39 ) 108 (302 ) (3,258 )
Provision (benefit) for income taxes 13 (679 ) (47 ) (546 )
Income (loss) before discontinued operations (132 ) (142 ) (13 ) 2,693
Discontinued operations, net of tax 23 23
Net income (loss) $ (109 ) $ (142 ) $ 10 $ 2,693
Reorganization items(1) (39 ) 108 (302 ) (3,258 )
Discontinued operations, net of tax (23 ) (23 )
Other one-time items(1),(2) 33 (80 ) 348 238
Net income (loss), net of reorganization items, discontinued operations and other one-time items (138 ) (114 ) 33 (327 )
MtM (gains) losses on commodity derivatives (non-cash portion)(1),(3) (8 ) 24 (18 ) 2
Net income (loss), net of reorganization items, discontinued operations, other one-time items and MtM impacts $ (146 ) $ (90 ) $ 15 $ (325 )

__________

(1) Shown net of tax, assuming a 0% effective tax rate for these items.

(2) One-time items in the fourth quarter of 2008 include an impairment charge of approximately $33 million related to the Auburndale Peaker power plant. One-time items in the fourth quarter of 2007 include a $485 million income tax benefit related to the release of valuation allowance, offset by $405 million in post-petition interest expense.

One-time items in 2008 include an impairment charge of approximately $33 million related to the Auburndale Peaker power plant, an impairment charge of approximately $180 million related to our interest in the Auburndale power plant, which was sold in the fourth quarter, and a charge of $135 million in post-petition interest expense associated with our emergence from bankruptcy. One-time items in 2007 include a $485 million income tax benefit related to the release of valuation allowance, offset by $723 million in post-petition interest expense.

(3) Represents the non-cash portion of net mark-to-market (MtM) gains (losses) on contracts that do not qualify for hedge accounting treatment.

REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin(1)by Segment

Years Ended December 31,
2008 2007
(in millions)
West $ 1,191 $ 1,196
Texas 815 500
Southeast 300 268
North 280 283
Other 124 (22 )
Total $ 2,710 $ 2,225

__________

(1) “Commodity Margin” includes electricity and steam revenues, hedging and optimization activities, renewable energy credit revenue, transmission revenue and expenses, and fuel and purchased energy expense, but excludes mark-to-market activity and other service revenues.

West: Commodity Margin in our West segment decreased by $5 million for the year ended December 31, 2008, compared to the year ended December 31, 2007. The decrease resulted primarily from lower realized margins in the fourth quarter of 2008 compared to 2007 and a negative year-on-year variance associated with natural gas storage inventory. The decrease was partially offset by a 1% increase in generation and improvement in our Steam Adjusted Heat Rate during the year ended December 31, 2008, compared to 2007, higher on-peak market spark spreads in the second quarter of 2008, and the favorable impact of new and renegotiated power contracts.

Texas: Commodity Margin in our Texas segment increased by $315 million, or 63%, for the year endedDecember 31, 2008, compared to 2007, due primarily to higher market spark spreads driven by higher natural gas prices in the second and third quarters of 2008 and transmission congestion in the South andHouston zones in the second quarter of 2008. Also positively impacting Commodity Margin were higher realized spark spreads on hedged positions in the fourth quarter of 2008 despite lower market spark spreads during the same period.

Southeast: Commodity Margin in our Southeast segment increased by $32 million, or 12%, for the year ended December 31, 2008, compared to the year ended December 31, 2007, resulting from the impact of more favorable pricing on our hedged volumes and the favorable impact of new power contracts. In addition, we recognized $21 million of Commodity Margin during the second quarter of 2008 related to a transmission capacity contract for which we received approval from FERC during the second quarter of 2008. The increase was partially offset by a decrease in market spark spreads on open positions for the year ended December 31, 2008, compared to 2007.

North: Commodity Margin in our North segment decreased by $3 million resulting from lower realized spark spreads during the fourth quarter of 2008 compared to the same period in 2007 and the deconsolidation of RockGen in January 2008. This was partially offset by higher hedged levels at more favorable pricing during the third quarter of 2008 compared to the same period in 2007.

Other: Commodity Margin in our Other segment increased by $146 million year over year, from the settlement of dedesignated hedges, the value for which was previously reflected in OCI.

REVIEW OF KEY PERFORMANCE MEASUREMENT

We have revised our definition of Adjusted EBITDA to include our ownership interest in the Adjusted EBITDA from unconsolidated investments. Management believes that the new methodology is a more comprehensive metric for measuring the performance of the entire portfolio.

Adjusted EBITDA increased by $254 million during 2008. This increase was primarily due to the increase in Commodity Margin, as previously discussed, offset in part by greater cash-realized mark-to-market losses associated with our hedging activities. In addition, plant operating expense (net of major maintenance expense and non-cash stock-based compensation expense) increased by $52 million during 2008, including $31 million related to higher costs of chemicals and other consumables and increases in routine repairs. Also a component of plant operating expense, expenses for outages caused by equipment failures, many of which occurred in 2007, and net of insurance recoveries, increased by $16 million. Sales, general and other administrative expense (net of non-cash stock-based compensation expense) increased by $44 million during 2008 as a result of higher legal and consulting expenses and information technology-related expenses.

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Corporate Liquidity

December 31, December 31,
2008 2007
(in millions)
Cash and cash equivalents, corporate(1) $ 1,361 $ 1,658
Cash and cash equivalents, non-corporate 296 257
Total cash and cash equivalents 1,657 1,915
Restricted cash 503 581
Letter of credit availability(2) 2
Revolver availability(3) 16 765
Total current liquidity(4) $ 2,178 $ 3,261
Less: Cash subsequently used to satisfy restructuring requirements 1,502
Total current liquidity, excluding cash used for restructuring $ 2,178 $ 1,759

__________

(1) Includes $169 million and $21 million of margin deposits held from counterparties as of December 31, 2008 and 2007, respectively.

(2) Includes available balances for Calpine Development Holdings Inc. as of December 31, 2008.

(3) Balance as of December 31, 2007 represents availability under the DIP Facility, which was repaid upon emergence from bankruptcy during the first quarter 2008.

(4) Excludes contingent amounts of $150 million under the Knock-in Facility and $200 million under the Commodity Collateral Revolver at December 31, 2008.

After adjusting for restructuring events, liquidity increased by $419 million in 2008 compared to 2007. This increase was primarily driven by net cash provided by operating activities of $494 million in 2008, as previously discussed.

During the third quarter of 2008, in light of turbulent economic conditions, we proactively elected to draw$725 million under our Exit Credit Facility revolver. Management intends to maintain this draw until it believes that financial markets have become more stable. Meanwhile, we have continued our efforts to improve liquidity by utilizing the first lien program, reducing prepayments made to counterparties and negotiating more unsecured credit to support commercial activities.

During the first quarter of 2009, we opportunistically recapitalized the Deer Park Energy Center. This transaction allowed us to remove a complicated financing structure and to resolve below-market power pricing, all while achieving an attractive interest rate under difficult market conditions. This demonstrates our continuing efforts to simplify our capital structure, with the three-year tenor of the new financing giving us flexibility for further simplification in the future.

PLANT DEVELOPMENT AND CONSTRUCTION

Otay Mesa Energy Center: The 596 MW combined-cycle, natural gas-fired Otay Mesa plant near San Diego is under construction and scheduled to begin commercial operations in the fall of 2009. After Otay Mesa begins commercial operations, all 596 MW of production will be sold under a ten-year power purchase agreement with San Diego Gas & Electric.

Russell City Energy Center: The 600 MW combined-cycle, natural gas-fired Russell City plant is a joint development project to be located in Hayward, California. We hold a 65% interest in the project, and an affiliate of General Electric Capital Corporation holds a 35% interest. In the third quarter of 2008, the power purchase agreement (PPA) between Pacific Gas & Electric Company (PG&E) and Russell City Energy Company, LLC, under which PG&E would take 100% of the generation for ten years, was amended to provide for continued development with an expected commercial operation in June 2012. The PPA is now before the CPUC for approval as amended. All permits for the projects have been issued and approved with the exception of a certain air permit now pending before the local air quality board. Completion of the Russell City development project is dependent upon obtaining the necessary permits and regulatory approvals, construction contracts and construction funding under project financing facilities.

OPERATIONS UPDATE

Commercial Operations Achievements: During 2008, our commercial operations group made significant contributions to our performance, despite an increasingly difficult economic environment. In 2008, they:

  • Substantially hedged our 2009 projected volume at prices we believe will allow us to deliver strong Commodity Margin and to mitigate gas price risk from the portfolio, despite ongoing volatility in the marketplace
  • Increased hedges for 2010 and 2011 to provide additional financial stability, while leaving upside for market recovery
  • Completed over 1,000 MW of one-year or greater origination transactions to capture value for assets in less liquid markets
  • Successfully navigated challenging power market conditions subsequent to Hurricane Ike

Power Operations Achievements: Our plants had an exceptional year with achievements in several important categories:

  • Safety: Delivered first quartile safety performance, achieving a fleet-wide lost time incident rate of 0.17 in 2008
  • Geothermal: Provided over 6 million MWh of renewable baseload generation with a forced outage factor below 0.5%
  • Natural Gas Generation: Achieved forced outage factor of 3.39% across all natural gas plants, our lowest rate in four years, or 3.08% after adjusting for hurricanes
  • Organization: Streamlined organization and resolved organizational ambiguities

OUTLOOK FOR 2009

Table 4: Adjusted EBITDA and Adjusted Free Cash Flow Guidance for 2009

Full Year 2009 Recurring
(in millions)
Adjusted EBITDA $ 1,600 – 1,700
Less:
Operating lease payments 50 $ 50
Major maintenance expense and capital expenditures(1) 350 ~300
Cash interest, net 755 750
Cash taxes 5 10
Working capital and other adjustments(2) 40
Adjusted Free Cash Flow $ 400 – 500

__________

(1) Includes Major Maintenance Expense of $205 million and Capital Expenditures of $145 million in 2009. Capital expenditures exclude major construction and development projects.

(2) Excludes changes in cash collateral for commodity procurement and risk management activities.

Using the revised definition of Adjusted EBITDA, we are providing 2009 Adjusted EBITDA guidance of $1.6 to $1.7 billion. This guidance reflects opportunistic hedging accomplished over the course of 2008, with 86% hedged on expected 2009 energy deliveries at an average spark spread price of $27 per MWh based on our portfolio as of February 11, 2009. In addition, we are providing for the first time Adjusted Free Cash Flow guidance for 2009 of $400 to $500 million.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results for the full year and fourth quarter 2008, on Friday, February 27, 2009, at 10:30 a.m. ET / 9:30 a.m. CT. A listen-only webcast of the call may be accessed through our web site at www.calpine.com, or by dialing 877-874-1589 (or 719-325-4764 for international listeners) at least 10 minutes prior to the beginning of the call. An archived recording of the call will be made available for a limited time on the web site. It also can be accessed by dialing 888-203-1112 or 719-457-0820 (International) and providing Confirmation Code 4233358. In addition, presentation materials to accompany the conference call will be made available on our web site on February 27, 2009.

ABOUT CALPINE

Calpine Corporation is helping meet the needs of an economy that demands more and cleaner sources of electricity. Founded in 1984, Calpine is a major U.S. power company, currently capable of delivering over 24,000 megawatts of clean, cost-effective, reliable and fuel-efficient power to customers and communities in 16 states in the United States and Canada. Calpine owns, leases, and operates low-carbon, natural gas-fired, and renewable geothermal power plants. Using advanced technologies, Calpine generates power in a reliable and environmentally responsible manner for the customers and communities it serves. Please visit www.calpine.com for more information.

Calpine’s Annual Report on form 10-K for the year ended December 31, 2008, has been filed with theSecurities and Exchange Commission (SEC) and may be found on the SEC’s web site at www.sec.gov.

FORWARD-LOOKING INFORMATION

In addition to historical information, this Report contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to:

  • The uncertain length and severity of the current general financial and economic downturn and its impacts on our business including demand for our power products, the ability of our counterparties to perform under their contracts with us and the cost and availability of capital and credit;
  • The effects of fluctuations in liquidity and volatility in the energy commodities markets including our ability to hedge risks;
  • The ability of our customers, suppliers, service providers and other contractual counterparties to perform under their contracts with us;
  • Our ability to manage our significant liquidity needs and to comply with covenants under our Exit Credit Facility and other existing financing obligations;
  • Financial results that may be volatile and may not reflect historical trends due to, among other things, general economic and market conditions outside of our control, the ability of our counterparties to perform their contracts with us and the effects of our Chapter 11 reorganization;
  • Seasonal fluctuations of our results and exposure to variations in weather patterns;
  • Fluctuations in prices for commodities such as natural gas and power;
  • Our ability to implement our new business plan and strategy;
  • Our ability to attract and retain customers and counterparties, including suppliers and service providers, and to manage our customer and counterparty exposure and credit risk, including our commodity positions;
  • Competition, including risks associated with marketing and selling power in the evolving energy markets;
  • Regulation in the markets in which we participate and our ability to effectively respond to changes in laws and regulations or the interpretation thereof including changing market rules and evolving federal, state and regions laws and regulations including those related to GHG emissions;
  • Present and possible future claims, litigation and enforcement actions, including our ability to complete the implementation of our Plan of Reorganization;
  • Our ability to attract, retain and motivate key employees;
  • Natural disasters such as hurricanes, earthquakes and floods that may impact our power plants or the markets our power plants serve;
  • Disruptions in or limitations on the transportation of natural gas and transmission of power;
  • Risks associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies;
  • Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements and variables associated with the injection of waste water to the steam reservoir;
  • The expiration or termination of our PPAs and the related results on revenues; and
  • Other risks identified in this release or in Calpine’s reports and registration statements filed with theSEC, including, without limitation, the risk factors identified in its Annual Report on Form 10-K for the year ended December 31, 2008.

Actual results or developments may differ materially from the expectations expressed or implied in the forward-looking statements, and Calpine undertakes no obligation to update any forward-looking statements, whether as a result of new information, future developments or otherwise. Unless specified otherwise, all information set forth in this release is as of today’s date, and Calpine undertakes no duty to update this information. For additional information about Calpine’s Chapter 11 reorganization or general business operations, please refer to Calpine’s Annual Report on Form 10-K for the fiscal year endedDecember 31, 2008, and any other recent Calpine report filed with the Securities and Exchange Commission. These filings are available by visiting the Securities and Exchange Commission’s web site at www.sec.gov or Calpine’s web site at www.calpine.com.

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 2008 and 2007

2008 2007
(in millions, except
share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 1,657 $ 1,915
Accounts receivable, net of allowance of $37 and $54 846 878
Accounts receivable, related party 4 226
Inventory 163 114
Margin deposits and other prepaid expense 776 452
Restricted cash, current 337 422
Current derivative assets 3,653 731
Current assets held for sale 195
Other current assets 64 98
Total current assets 7,500 5,031
Property, plant and equipment, net 11,908 12,292
Restricted cash, net of current portion 166 159
Investments 144 260
Long-term derivative assets 404 290
Other assets 616 1,018
Total assets $ 20,738 $ 19,050
LIABILITIES & STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable $ 574 $ 642
Accrued interest payable 85 324
Debt, current portion 716 1,710
Current derivative liabilities 3,799 806
Income taxes payable 5 51
Other current liabilities 437 571
Total current liabilities 5,616 4,104
Debt, net of current portion 9,756 9,946
Deferred income taxes, net of current portion 93 38
Long-term derivative liabilities 698 578
Other long-term liabilities 203 245
Total liabilities not subject to compromise 16,366 14,911
Liabilities subject to compromise 8,788
Commitments and contingencies
Minority interest 2 3
Stockholders’ equity (deficit):
Preferred stock, $.001 par value per share; authorized 100,000,000 shares, none issued and outstanding in 2008; authorized 10,000,000 shares, none issued and outstanding in 2007
Common stock, $.001 par value per share; authorized 1,400,000,000 shares, 429,025,057 shares issued and 428,960,025 shares outstanding in 2008; authorized 2,000,000,000 shares, 568,314,685 issued and 479,314,685 outstanding in 2007 1 1
Treasury stock, at cost, 65,032 shares at September 30, 2008, and none at December 31, 2007 (1 )
Additional paid-in capital 12,217 3,263
Accumulated deficit (7,689 ) (7,685 )
Accumulated other comprehensive income (loss) (158) (231 )
Total stockholders’ equity (deficit) 4,370 (4,652 )
Total liabilities and stockholders’ equity (deficit) $ 20,738 $ 19,050

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)
Three Months Ended December 31, Years Ended December 31,
2008 2007 2008 2007
(in millions, except share and per share amounts)
Operating revenues $ 1,968 $ 1,924 $ 9,937 $ 7,970
Cost of revenue:
Fuel and purchased energy expense 1,346 1,386 7,281 5,683
Plant operating expense 282 188 918 749
Depreciation and amortization expense 104 113 433 463
Operating plant impairments 33 44 33 44
Other cost of revenue 26 35 114 136
Total cost of revenue 1,791 1,766 8,779 7,075
Gross profit 177 158 1,158 895
Sales, general and other administrative expense 61 34 215 146
Loss from unconsolidated investments in power plants 50 21 229 21
Other operating expense 1 (1 ) 26 23
Income from operations 65 104 688 705
Interest expense 234 838 1,071 2,019
Interest (income) (9 ) (16 ) (47 ) (64 )
Minority interest (income) (1 )
Other (income) expense, net (2 ) (5 ) 27 (139 )
Loss before reorganization items, income taxes and discontinued operations (158 ) (713 ) (362 ) (1,111 )
Reorganization items (39 ) 108 (302 ) (3,258 )
Income (loss) before income taxes and discontinued operations (119 ) (821 ) (60 ) 2,147
Provision (benefit) for income taxes 13 (679 ) (47 ) (546 )
Income (loss) before discontinued operations $ (132 ) $ (142 ) $ (13 ) $ 2,693
Discontinued operations, net of tax provision of $14 in 2008 23 23
Net income (loss) $ (109 ) $ (142 ) $ 10 $ 2,693
Basic earnings (loss) per common share:
Weighted average shares of common stock outstanding (in thousands) 485,073 479,315 485,054 479,235
Income (loss) before discontinued operations $

(0.28

) $ (0.30 ) $ (0.03 ) $ 5.62
Discontinued operations, net of tax 0.05 0.05
Net income per share – basic(1) $ (0.23 ) $ (0.30 ) $ 0.02 $ 5.62
Diluted earnings (loss) per common share:
Weighted average shares of common stock outstanding (in thousands) 485,073 479,315 485,546 479,478
Income (loss) before discontinued operations

$

(0.28 )

$

(0.30 ) $ (0.03 ) $ 5.62
Discontinued operations, net of tax 0.05 0.05
Net income per share – diluted(1) $ (0.23 ) $ (0.30 ) $ 0.02 $ 5.62

__________

(1) All shares of the Company’s common stock outstanding prior to January31, 2008, were canceled pursuant to the Plan of Reorganization, and new shares of reorganized Calpine Corporation common stock were issued. Although gain per share information for the three and twelve months ended December 31, 2007, is presented, it is not comparable to the information for the three and twelve months ended December 31, 2008, due to the changes in the Company’s capital structure on January31, 2008, which also included termination of all outstanding convertible securities.

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2008 and 2007

2008 2007
(in millions)
Cash flows from operating activities:
Net income $ 10 $ 2,693
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense(1) 551 554
Deferred income taxes (27 ) (517 )
Impairment charges 46 46
Gain on sale of discontinued operations (37 )
Loss on sale of assets, excluding reorganization items 36 31
Change in the fair value of derivative assets and liabilities 273 18
Derivative contracts classified as financing activities (64 )
Loss from unconsolidated investments in power plants 229 21
Stock-based compensation expense (income) 50 (1 )
Reorganization items (359 ) (3,342 )
Other 16 (2 )
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable 375 (194 )
Other assets (101 ) (102 )
Accounts payable, LSTC and accrued expenses (215 ) 931
Other liabilities (289 ) 51
Net cash provided by operating activities 494 187
Cash flows from investing activities:
Purchases of property, plant and equipment (143 ) (196 )

Proceeds from sale of power plants, turbines and investments

413 541
Proceeds from sale of discontinued operations 79
Cash acquired due to reconsolidation of Canadian Debtors and other foreign entities 64
Contributions to unconsolidated investments (17 ) (68 )
Return of investment from unconsolidated investments 27 179
Decrease in restricted cash 78 37
Cash effect of deconsolidation of VIEs (29 )
Other 15 9
Net cash provided by investing activities 516 473

(Table continues)

CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)

2008 2007
(in millions)
Cash flows from financing activities:
Repayments of notes payable and lines of credit $ (99 ) $ (135

)

Borrowings from project financing 357 21
Repayments of project financing (311 ) (119

)

Repayments of CalGen Secured Debt (224

)

Borrowings under DIP Facility 614
Repayments of DIP Facility (98 ) (38

)

Borrowings under Exit Facilities 4,248
Repayments of Exit Facilities (1,475 )
Borrowings under Commodity Collateral Revolver 100
Repayments of Second Priority Debt (3,672 )
Proceeds from sale of ULC I bonds 151
Redemptions of preferred interests (166 ) (9

)

Financing costs (207 ) (81 )
Derivative contracts 64
Other (9 ) (2 )
Net cash provided by (used in) financing activities (1,268 ) 178
Net (decrease) increase in cash and cash equivalents (258 ) 838
Cash and cash equivalents, beginning of period 1,915 1,077
Cash and cash equivalents, end of period $ 1,657 $ 1,915
Cash paid (received) during the period for:
Interest, net of amounts capitalized $ 1,060 $ 1,143
Income taxes $ 74 $ 1
Reorganization items included in operating activities, net $ 120 $ 126
Reorganization items included in investing activities, net $ (418 ) $ (582 )
Reorganization items included in financing activities, net $ $ 74
Supplemental disclosure of non-cash investing and financing activities:
Settlement of LSTC through issuance of reorganized Calpine Corporation common stock $ 5,200 $
DIP Facility borrowings converted into exit financing under Exit Facilities $ 3,872 $
Settlement of Convertible Senior Notes and Unsecured Senior Notes with reorganized Calpine Corporation common stock $ 3,703 $
DIP Facility borrowings used to extinguish the Original DIP Facility principal $(989), CalGen Secured Debt principal $(2,309) and operating liabilities $(88) $ $ 3,386
Project financing $(159) and operating liabilities $(33) extinguished with sale of Aries Power Plant $ $ 192
Return of loaned common stock $ $ 145
Letter of credit draws under CalGen Secured Debt used for operating activities $ $ 16
Fair value of Metcalf cooperation agreement, with offsets to notes payable $(6) and operating liabilities $(6) $ $ 12

__________

(1) Includes depreciation and amortization that is recorded in sales, general and other administrative expense and interest expense on our Consolidated Statements of Operations.

REGULATION G RECONCILIATIONS

Adjusted EBITDA, Commodity Margin and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These measures should not be viewed as alternatives to GAAP measures of performance.

Adjusted EBITDA is presented because our management uses Adjusted EBITDA (i) as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends; (ii) as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations; and (iii) in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by GAAP as an indicator of operating performance. Furthermore, Adjusted EBITDA is not necessarily comparable to similarly-titled measures reported by other companies.

Commodity Margin is presented because we believe it is a useful tool for assessing the performance of our core operations, and it is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent gross profit (loss), the most comparable GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly-titled measures reported by other companies.

Adjusted Free Cash Flow is presented because our management uses this measure, among others, to make decisions about capital allocation. Adjusted Free Cash Flow is not intended to represent cash flows from operations as defined by GAAP as an indicator of operating performance and is not necessarily comparable to similarly-titled measures reported by other companies.

Adjusted EBITDA Reconciliation

The table below provides a reconciliation of Adjusted EBITDA to our GAAP net income for the three months and years ended December 31, 2008 and 2007.

(Unaudited)
Three Months Ended December 31, Years Ended December 31,
2008 2007(1) 2008 2007(1)
(in millions)
GAAP net income (loss) $ (109 ) $ (142 ) $ 10 $ 2,693
Less: Income from discontinued operations

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Net income (loss) from continuing operations $ (132 ) $ (142 ) $ (13 ) $ 2,693
Add:
Adjustments to reconcile GAAP net income (loss) to Adjusted EBITDA:
Interest expense, net of interest income 225 822 1,024 1,955
Depreciation and amortization expense, excluding deferred financing costs(2) 110 124 467 507
Provision (benefit) for income taxes 13 (679 ) (47 ) (546 )
Impairment charges 47 46 226 46
Reorganization items (39 ) 108 (302 ) (3,258 )
Major maintenance expense 72 20 190 98
Operating lease expense 11 15 46 54
Non-cash gains on derivatives(3) (8 ) (11 ) (40 ) (53 )
Unrealized (gains) losses on commodity derivative mark-to-market activity (56 ) 22 (35 ) 35
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(4),(5) 54 12 76 20
Claim settlement income (6 ) (135 )
Stock-based compensation expense (income) 14 50 (1 )
Non-cash loss on dispositions of assets 19 8 34 33
Non-cash gain (loss) on repurchase or extinguishment of debt (1 ) 13 (1 )
Other(6) (5 ) 2 10 (2 )
Adjusted EBITDA $ 325 $ 340 $ 1,699 $ 1,445

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(1) 2007 Adjusted EBITDA as previously reported has been recast to conform to our current year definition.

(2) Depreciation and amortization expense in the GAAP net income calculation on our Consolidated Statements of Operations excludes amortization of other assets and amounts classified as sales, general and other administrative expenses.

(3) Includes realized and unrealized non-cash gains and losses on derivatives that do not qualify for hedge accounting.

(4) Recorded on our Consolidated Statements of Operations in loss from unconsolidated investments in power plants.

(5) Adjusted EBITDA from unconsolidated investments includes $57 million and $20 million in unrealized losses on mark-to-market activity for the years ended December 31, 2008 and 2007, respectively.

(6) Other includes foreign currency translation gains or losses, fees associated with issuance of letters of credit and other items.

Consolidated Commodity Margin Reconciliation

The following table reconciles the Company’s Commodity Margin to its GAAP results for the three months and years ended December31, 2008 and 2007 (in millions):

(Unaudited)
Three Months Ended December 31, Years Ended December 31,
2008 2007 2008 2007
Commodity Margin $ 597 $ 536 $ 2,710 $ 2,225
Add: Mark-to-market commodity activity, net and other revenue(1) 25 2 (54 ) 62
(Less): Plant operating expense 282 188 918 749
Depreciation and amortization expense 104 113 433 463
Operating plant impairments 33 44 33 44
Other cost of revenues 26 35 114 136
Gross profit $ 177 $ 158 $ 1,158 $ 895

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(1) Mark-to-market commodity activity is included in operating revenues and fuel and purchased energy expense on our Consolidated Statements of Operations.

Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for 2009 Guidance

Full Year 2009 Range: Low High Recurring
(in millions)
GAAP Net Income $ 160 $ 260
Plus:
Interest expense, net of interest income 765 765
Depreciation and amortization expense 475 475
Major maintenance expense 205 205
Operating lease expense 50 50
Other(1) (55 ) (55 )
Adjusted EBITDA $ 1,600 $ 1,700
Less:
Operating lease payments 50 50 $ 50
Major maintenance expense and maintenance capital expenditures(2) 350 350 ~300
Cash interest, net 755 755 750
Cash taxes 5 5 10
Working capital and other adjustments 40 40
Adjusted Free Cash Flow $ 400 $ 500

__________

(1) Other includes stock compensation expense, minority interest expense, impairments and other adjustments.

(2) Includes major maintenance expense of $205 million and capital expenditures of $145 million in 2009. Capital expenditures exclude major construction and development projects funded with debt.

CASH FLOW ACTIVITIES

The following table summarizes the Company’s cash flow activities for the twelve months ended December 31, 2008 and 2007 (in millions):

2008 2007
Beginning cash and cash equivalents $ 1,915 $ 1,077
Net cash provided by (used in):
Operating activities 494 187
Investing activities 516 473
Financing activities (1,268 ) 178
Net (decrease) increase in cash and cash equivalents (258 ) 838
Ending cash and cash equivalents $ 1,657 $ 1,915

OPERATING PERFORMANCE METRICS

The table below shows the operating performance metrics for continuing operations:

Three Months Ended December 31, Years Ended December 31,
2008 2007 2008 2007
(MWh in thousands)
Total MWh generated(1) 20,397 22,191 88,961 92,103
West 9,435 10,376 37,137 36,837
Texas 5,623 7,846 33,683 34,255
Southeast 3,761 2,865 12,374 14,795
North 1,578 1,104 5,767 6,216
Average availability 89.7 % 88.4 % 90.5 % 90.8 %
West 87.6 % 92.6 % 89.1 % 90.8 %
Texas 84.8 % 88.1 % 88.8 % 90.8 %
Southeast 96.5 % 87.5 % 93.6 % 92.1 %
North 94.2 % 80.7 % 92.6 % 87.4 %
Average capacity factor, excluding peakers 43.4 % 46.9 % 47.8 % 46.6 %
West 66.7 % 73.8 % 66.1 % 65.3 %
Texas 33.5 % 46.9 % 50.9 % 52.1 %
Southeast 32.4 % 23.1 % 26.5 % 25.5 %
North 33.3 % 25.2 % 33.7 % 33.6 %
Steam adjusted Heat Rate 7,183 7,221 7,231 7,190
West 7,208 7,351 7,267 7,336
Texas 7,040 6,855 7,082 6,830
Southeast 7,210 7,679 7,388 7,544

North

7,545 7,586 7,584 7,646

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(1) MWh generated is shown here as our net operating interest. Excludes Auburndale Power Plant’s 446,063 MWh generation for 2008.

Source: Calpine Corporation

Calpine Corporation
Norma F. Dunn, 713-830-8883 (Media Relations)
norma.dunn@calpine.com
Andre K. Walker, 713-830-8775 (Investor Relations)
andrew@calpine.com