Calpine Corp. Reports Solid 2009 Second Quarter Results, Increases Full Year 2009 Guidance

Calpine Corporation (NYSE:CPN) today reported Adjusted EBITDA of $788 million for the six months ended June 30, 2009, compared to $780 million in the same period of 2008. Commodity Margin for the first half of 2009 was $1,179 million, down slightly from $1,188 million in the first half of 2008. In addition, the company reported Adjusted Free Cash Flow of $157 million. Net loss1 was $46 million, or $0.09 per diluted share, in the first half of 2009, compared to a net loss of $17 million, or $0.04 per diluted share, in the prior year period.

“I am pleased to report that, despite the severity of the economic downturn, Calpine has achieved stable year-over-year financial performance using the metrics we rely upon to evaluate our business: Adjusted EBITDA, Commodity Margin and Adjusted Free Cash Flow,” said Jack Fusco, Calpine’s president and chief executive officer. “I am pleased with our progress in rebuilding Calpine as the premier operating company in the IPP sector and our ability to deliver on our promises. Because the execution of our hedging strategy, improvements in operations and sustainable cost-cutting have been better than expected, we are raising and tightening our projected 2009 Adjusted EBITDA to $1.675 - $1.725 billion and our Adjusted Free Cash Flow to $475 - $525 million.”

SUMMARY OF FINANCIAL PERFORMANCE

Second Quarter Results

Adjusted EBITDA was $457 million in the second quarter of 2009, despite weaker market conditions in Texas and California, compared to $479 million in the prior year period. The year-over-year decline was primarily due to a decrease in Commodity Margin from $675 million in 2008 to $650 million in 2009. Our Texas and West segments, where Commodity Margin was down by $19 million and $11 million, respectively, largely drove this decline due to lower market spark spreads given lower power demand and lower natural gas prices. Meanwhile, Commodity Margin in our Southeast and North regions was essentially flat, despite the fact that the 2008 period included $21 million in revenues from the sale of transmission rights in the Southeast which did not recur in 2009. In the Southeast region, higher average hedge prices and higher market heat rates were favorable for our fleet during the second quarter of 2009.

Aside from the decline in Commodity Margin, Adjusted EBITDA was also impacted by a $7 million decrease in other revenue, which resulted from service agreements that terminated in 2008 and from an operation and maintenance contract. These declines were partially offset by a $4 million increase in Adjusted EBITDA from unconsolidated investments in power plants, primarily as a result of Greenfield Energy Centre which began operations in October 2008. In addition, controllable expenses as a component of plant operating expense decreased by $4 million in the 2009 period after accounting for $7 million in reimbursements for insurance claims from prior periods that reduced expenses in the second quarter of 2008.

Net income1 declined from $197 million in the second quarter of 2008 to a net loss of $78 million in the second quarter of 2009. As detailed in Table 1 below, net income, excluding reorganization items, one-time items and unrealized mark-to-market gains or losses, declined from $81 million in the second quarter of 2008 to $49 million in the second quarter of 2009. This decline was primarily associated with the $25 million year-over-year decrease in Commodity Margin, as previously noted, as well as a $10 million decrease in interest income during the 2009 period due to lower interest rates. These factors were partially offset by a $7 million increase in income from unconsolidated investments, primarily related to the Greenfield Energy Centre.

Year-to-Date Results

For the six months ended June 30, 2009, Adjusted EBITDA increased $8 million to $788 million, despite a $9 million decrease in Commodity Margin. The decline in Commodity Margin was largely driven by weaker conditions in our Texas region, where Commodity Margin declined by $36 million in the first half of 2009 compared to the first half of 2008. This decline was partially offset by increases in Commodity Margin in our Southeast region, which improved by $28 million in the 2009 period due to higher market heat rates and higher average hedge prices.

In addition to the decline in Commodity Margin, Adjusted EBITDA was negatively impacted by a $12 million decrease in other revenue, due to the factors previously noted. Offsetting these declines was a $15 million increase in Adjusted EBITDA from unconsolidated investments during the first half of 2009, primarily as a result of the Greenfield Energy Centre. In addition, royalty expenses decreased by $7 million year-over-year as a result of lower revenues at The Geysers during the 2009 period. Lastly, we reduced controllable expenses as a component of plant operating expense by $9 million, after accounting for $15 million in reimbursements for insurance claims from prior periods that reduced expenses in the first half of 2008.

Net loss1 increased from $17 million in the first half of 2008 to $46 million in the first half of 2009. As detailed in Table 1 below, net loss, excluding reorganization items, one-time items and unrealized mark-to-market gains or losses, increased from $40 million in the first half of 2008 to $42 million in the first half of 2009. Interest expense, excluding the one-time items noted below and net of interest income, decreased by $29 million as a result of lower average debt balances and lower average interest rates during the six month 2009 period. In addition, income from unconsolidated investments in power plants increased by $27 million in the first half of 2009, primarily resulting from our investments in Greenfield Energy Centre and Otay Mesa Energy Center. Also benefiting the 2009 period was a reduction of $19 million in other cost of revenue, which declined as a result of the discontinuation of the amortization of other assets associated with the sale of Auburndale in 2008 as well as a decrease in royalty expense at our Geysers facilities resulting from lower revenues in the first half of 2009 compared to 2008. These favorable variances were offset in part by a $20 million increase in plant operating expense, due in part to $15 million in insurance reimbursements reflected in the 2008 period that did not recur in 2009. In addition, the 2008 period included $20 million in non-cash gains from the amortization of prepaid power sales agreements compared to none in the 2009 period. Adjusted EBITDA was also negatively impacted by a $12 million decline in other revenue and a $9 million decline in Commodity Margin, as previously discussed.

For the six months ended June 30, 2009, cash flows used in operating activities improved to a net outflow of $36 million compared to a net outflow of $586 million in the prior year period. The primary driver of this improvement was a $236 million reduction in cash paid for interest, largely as a result of the repayment of certain debts upon our emergence from bankruptcy in the first half of 2008. Meanwhile, working capital employed decreased by approximately $333 million for 2009, after adjusting for debt related balances and assets held for sale, primarily due to reductions in margin deposits partially offset by increases in net current derivative assets. Lastly, cash payments for reorganization items decreased by $103 million year-over-year. These improvements were offset in part by a $59 million decrease in cash received for tax refunds during the 2009 period and a $20 million increase in cash payments for debt extinguishment costs.

1 Reported as net income (loss) attributable to Calpine on our Consolidated Condensed Statements of Operations.

Table 1: Summarized Consolidated Statements of Operations

(Unaudited)

Three Months Ended June 30,

Six Months Ended June 30,

2009 2008 2009 2008 (in millions) Operating revenues $ 1,471 $ 2,828 $ 3,148 $ 4,779 Cost of revenue (1,265 ) (2,352 ) (2,660 ) (4,332 ) Gross profit 206 476 488 447 SG&A, income from unconsolidated investments in power plants and other operating expense (31 ) (43 ) (62 ) (96 ) Income from operations 175 433 426 351 Net interest expense, debt extinguishment costs and other (income) expense (236 ) (193 ) (444 ) (609 ) Income (loss) before reorganization items and income taxes (61 ) 240 (18 ) (258 ) Reorganization items 3 18 6 (261 ) Income tax expense 15 25 24 20 Net income (loss) $ (79 ) $ 197 $ (48 ) $ (17 ) Add: Net loss attributable to the noncontrolling interest 1 — 2 — Net income (loss) attributable to Calpine $ (78 ) $ 197 $ (46 ) $ (17 ) Reorganization items(1) 3 18 6 (261 ) Other one-time items(1)(2) 21 6 21 175 Net income (loss), net of reorganization items and other one-time items (54 ) 221 (19 ) (103 ) Unrealized MtM (gains) losses on derivatives(1)(3) 103 (140 ) (23 ) 63 Net income (loss), net of reorganization items other one-time items and unrealized MtM impacts $ 49 $ 81 $ (42 ) $ (40 )

__________

(1) Shown net of tax, assuming a 0% effective tax rate for these items (other than those referenced in note 2 below).

(2) One-time items in the three and six months ended June 30, 2009 include $33 million in debt extinguishment costs, shown net of tax assuming a 35% effective tax rate. One-time items in the three months ended June 30, 2008 include $6 million in debt extinguishment costs. One-time items in the six months ended June 30, 2008 include $13 million in debt extinguishment costs, $135 million in post-petition interest expense and $27 million in settlement obligations related to our Canadian debtors and other foreign entities recorded prior to their reconsolidation in February 2008, both of which were associated with our emergence from bankruptcy.

(3) Represents unrealized mark-to-market (MtM) (gains) losses on contracts that do not qualify for hedge accounting treatment or qualify for hedge accounting and the hedge accounting designation has not been elected.

REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin by Segment (in millions)

Three Months Ended June 30, Six Months Ended June 30, 2009 2008(1) 2009 2008(1) West $ 304 $ 315 $ 601 $ 593 Texas 196 215 318 354 Southeast 80 78 141 113 North 70 67 119 128 Total $ 650 $ 675 $ 1,179 $ 1,188

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(1) 2008 Commodity Margin as previously reported has been recast to conform to our current year presentation.

West: During the second quarter of 2009, our West segment benefited from higher hedge levels, higher average hedge prices and a 2% increase in our average availability as compared to the second quarter of 2008. Despite these positive factors, a weaker power market price environment driven by lower natural gas prices, lower industrial demand and milder weather led to an $11 million decrease in Commodity Margin for the three months ended June 30, 2009 compared to 2008.

For the six month period, Commodity Margin in the West improved by $8 million in the first half of 2009 compared to the first half of 2008. Although market spark spreads for the first half of 2009 settled substantially lower than the prior year period, higher hedge levels, higher average hedge prices and the sale of surplus emission allowances in the first quarter led to the Commodity Margin increase.

Texas: During the second quarter of 2009, Commodity Margin for the Texas region declined from $215 million in the prior year period to $196 million in 2009. This $19 million decrease primarily resulted from weaker natural gas prices and market heat rates that decreased 68% and 23%, respectively. Although April and May 2009 market heat rates were weak as a result of weak industrial demand and mild weather, market heat rates were robust during June 2009 as a result of much warmer than normal temperatures. Despite the strength seen in June 2009, the overall pricing for the second quarter of 2009 fell well short of the congestion-driven pricing observed in the second quarter of 2008.

Commodity Margin in Texas declined from $354 million for the six months ended June 30, 2008 to $318 million for the 2009 period. This decrease is associated primarily with weaker natural gas prices, weaker market heat rates and congestion-driven power prices that did not recur to the same extent in 2009, as previously discussed.

Southeast: Commodity Margin in our Southeast segment increased by $2 million during the second quarter of 2009, driven by both higher average hedge prices and higher market heat rates compared to the prior year period. The increase in market heat rates and the associated 50% increase in generation for the 2009 second quarter were attributable in part to warmer weather in particular market areas and natural gas generation displacement of coal generation in certain sub-markets in our Southeast segment. In addition, some of our plants benefited from the impact of advantageous transmission, off-take and transportation agreements during the 2009 period. These positive performance factors were largely offset by the negative impact from an unfavorable arbitration ruling on a steam contract, which impacted our operating revenue during the second quarter of 2009 and a gain of $21 million related to the temporary assignment of a transmission capacity contract in the three months ended June 30, 2008.

For the first half of 2009, Commodity Margin in the Southeast improved by $28 million compared to the prior year period. The six month results were largely impacted by the same factors that drove performance for the second quarter, as previously discussed.

North: In the North region, Commodity Margin improved to $70 million in the second quarter of 2009 from $67 million in the prior year period. The improvement in Commodity Margin is primarily due to rate increases for the power sales agreements associated with our New York generation assets, lower fuel expenses and the reconsolidation of RockGen in December 2008. Partially offsetting these positive factors was a reclassification of transmission expense to Commodity Margin that had previously been recognized in plant operating expense as well as lower realized spark spreads for the three months ended June 30, 2009, compared to 2008.

Commodity Margin in the North region decreased by $9 million in the first half of 2009 compared to the prior year period, primarily due to lower average hedge prices during the six months ended June 30, 2009, compared to 2008. The impacts of lower hedge prices were partially offset by rate increases for the power sales agreements associated with our New York generation assets and lower fuel expenses.

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Corporate Liquidity

June 30, December 31, 2009 2008 (in millions) Cash and cash equivalents, corporate(1) $ 1,028 $ 1,361 Cash and cash equivalents, non-corporate 454 296 Total cash and cash equivalents 1,482 1,657 Restricted cash 534 503 Letter of credit availability(2) 2 2 Revolver availability 55 16 Total current liquidity(3) $ 2,073 $ 2,178

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(1) Includes $2 million and $169 million of margin deposits held from counterparties as of June 30, 2009, and December 31, 2008, respectively.

(2) Includes available balances for Calpine Development Holdings, Inc. in both periods shown.

(3) Excludes contingent amounts of $150 million under the Knock-in Facility as of December 31, 2008 and $200 million under the Commodity Collateral Revolver in both periods shown.

We maintained strong liquidity during the second quarter, ending the period with liquidity in excess of $2.0 billion. As previously discussed, operating activities resulted in a net use of cash of $36 million during the first half of 2009. In addition, cash flows used in investing activities resulted in a net outflow of $137 million, driven largely by $97 million in capital expenditures, which were primarily related to well-production maintenance at The Geysers and purchases of engine parts for use in maintaining our natural gas-fired fleet. For the first half of 2009, we generated $157 million of Adjusted Free Cash Flow.

During the second quarter, our subsidiary, Calpine Construction Finance Company, L.P. (“CCFC”), issued $1.0 billion in senior secured notes. Proceeds from this issuance, along with cash on hand, were used to refinance existing CCFC debt, including its approximately $364 million of term loans that would have been due during the third quarter of 2009 and approximately $415 million in notes issued by CCFC and $300 million in preferred shares issued by CCFC’s parent that would have both matured in the second half of 2011. The refinancing allowed us to transition from floating to fixed interest rates on the corresponding debt balances and lowered our coupon rate on such debt to 8.0%.

“Our successful issuance of CCFC’s $1.0 billion notes demonstrates our ability to opportunistically access capital markets even amidst widespread uncertainty during the second quarter,” said Zamir Rauf, Calpine’s chief financial officer. “In addition, it shows clear progress toward our commitment to proactively address near-term maturities and simplify our capital structure. This transaction lowered our interest costs and improved free cash flow, creating value for our shareholders.”

PLANT DEVELOPMENT

Russell City Energy Center: During the second quarter, we announced a landmark agreement with the Bay Area Air Quality Management District to limit greenhouse gas emissions at the Russell City Energy Center, a proposed 600 MW combined-cycle natural gas-fired power plant to be located in Hayward, California. This agreement demonstrates our commitment to environmental stewardship, with Russell City Energy Center becoming the first power plant in the country to be subject to federal greenhouse gas emissions limits. The project is a joint development effort in which we own a 65% interest, and an affiliate of General Electric Capital Corporation holds a 35% interest. Completion of the Russell City development project is dependent upon obtaining necessary permits, construction contracts and construction funding under project financing facilities.

OPERATIONS UPDATE

Power Operations Achievements: During the second quarter of 2009, we continued to focus on our goal of best-in-class operations, as demonstrated by:

Safety: Maintained top-quartile safety performance with year-to-date lost-time incident rate of 0.19
Availability: Achieved near-perfect availability of 99% at Texas fleet during June heat wave when load was high
Geothermal Generation: Provided 1.5 million MWh of renewable baseload generation with a forced outage factor of 0.38% in the second quarter of 2009, compared to 1.50% in the prior year quarter
Natural Gas Generation: Improved gas fleet forced outage factor to 2.88% in the second quarter of 2009 from 3.04% in the second quarter of 2008; Achieved forced outage factor of just 1.92% for Calpine-maintained gas fleet
Sustainable Cost Reductions: Reduced controllable expenses, a component of plant operating expense and SG&A costs, by $17 million year-to-date compared to 2008 after accounting for $15 million in reimbursements for insurance claims from prior periods that reduced expenses in the first half of 2008
Centralized Procurement: Established national contracts for chemicals and transportation, capturing efficiencies and cost savings to deliver near-term benefit

Commercial Operations Achievements: We continued to benefit from the efforts of our commercial operations team during the second quarter of 2009, including:

Effective hedging: Maintained stable year-over-year Commodity Margin during the first half of 2009, despite an 8.5% decline in generation and 67% decline in natural gas prices during the second quarter
Disciplined growth: Russell City development project is the first U.S. project to voluntarily agree to federal greenhouse gas emissions limits in its federal air permit approval process, demonstrating our commitment to environmental stewardship
Liquidity management: Nearly doubled our usage of the first lien hedging program for hedges relating to 2010 and beyond during 2009

UPDATED OUTLOOK FOR 2009

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

Full Year 2009 Recurring (in millions) Adjusted EBITDA $ 1,675 – 1,725 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 $ 475 – 525

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(1) Includes projected Major Maintenance Expense of $190 million and maintenance Capital Expenditures of $160 million in 2009. Capital expenditures exclude major construction and development projects.

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

As previously discussed, we are raising and tightening our 2009 projections for Adjusted EBITDA and Adjusted Free Cash Flow. We are now projecting 2009 Adjusted EBITDA of $1.675 to $1.725 billion, up from the $1.6 - $1.7 billion we projected earlier this year, and 2009 Adjusted Free Cash Flow of $475 to $525 million, up from our previous projection of $400 - $500 million.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results for the second quarter 2009, on Friday, July 31, 2009, at 10:00 a.m. ET / 9:00 a.m. CT. A listen-only webcast of the call may be accessed through our web site at www.calpine.com, or by dialing 888-797-3006 (or 913-312-0388 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. The recording also can be accessed by dialing 888-203-1112 or 719-457-0820 (International) and providing Confirmation Code 1941999. Presentation materials to accompany the conference call will be made available on our web site on July 31, 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 Quarterly Report on Form 10-Q for the period ended June 30, 2009, has been filed with the Securities 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 of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended. 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 and steam products, the ability of our counterparties to perform under their contracts with us and the cost and availability of capital and credit;
Fluctuations in prices for commodities such as natural gas and power;
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;
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 regional laws and regulations including those related to greenhouse gas emissions;
Natural disasters such as hurricanes, earthquakes and floods that may impact our power plants or the markets our power plants serve;
Seasonal fluctuations of our results and exposure to variations in weather patterns;
Disruptions in or limitations on the transportation of natural gas and transmission of power;
Our ability to attract, retain and motivate key employees;
Our ability to implement our new business plan and strategy;
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;
Present and possible future claims, litigation and enforcement actions, including our ability to complete the implementation of our Plan of Reorganization;
The expiration or termination of our power purchase agreements and the related results on revenues;
Risks associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies; and
Other risks identified in this release or in our reports and registration statements filed with the Securities and Exchange Commission (SEC), including, without limitation, the risk factors identified in our Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 30, 2009 and in our 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 we undertake 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 we undertake no duty to update this information. For additional information about our general business operations, please refer to our Annual Report on Form 10-K for the year ended December 31, 2008 and any other recent report we have filed with the SEC. These filings are available by visiting the SEC’s web site at www.sec.gov or our web site at www.calpine.com.

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

June 30, December 31, 2009 2008 (in millions, exceptshare and per share amounts) ASSETS Current assets: Cash and cash equivalents $ 1,482 $ 1,657 Accounts receivable, net of allowance of $40 and $42 822 850 Inventory 171 163 Margin deposits and other prepaid expense 590 776 Restricted cash, current 484 337 Current derivative assets 3,361 3,653 Other current assets 58 64 Total current assets 6,968 7,500 Property, plant and equipment, net 11,760 11,908 Restricted cash, net of current portion 50 166 Investments 204 144 Long-term derivative assets 387 404 Other assets 606 616 Total assets $ 19,975 $ 20,738 LIABILITIES & STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable $ 588 $ 574 Accrued interest payable 59 85 Debt, current portion 634 716 Current derivative liabilities 3,231 3,799 Income taxes payable 6 5 Other current liabilities 223 437 Total current liabilities 4,741 5,616 Debt, net of current portion 9,955 9,756 Deferred income taxes, net of current portion 93 93 Long-term derivative liabilities 479 698 Other long-term liabilities 209 203 Total liabilities 15,477 16,366 Commitments and contingencies Stockholders’ equity: Preferred stock, $.001 par value per share; 100,000,000 shares authorized; none issued and outstanding at June 30, 2009 and December 31, 2008 — — Common stock, $.001 par value per share; 1,400,000,000 shares authorized; 432,412,629 shares issued and 432,112,939 shares outstanding at June 30, 2009; 429,025,057 shares issued and 428,960,025 shares outstanding at December 31, 2008 1 1 Treasury stock, at cost, 299,690 shares at June 30, 2009 and 65,032 shares at December 31, 2008 (3 ) (1 ) Additional paid-in capital 12,240 12,217 Accumulated deficit (7,735 ) (7,689 ) Accumulated other comprehensive loss (5 ) (158 ) Total Calpine stockholders’ equity 4,498 4,370 Noncontrolling interest — 2 Total stockholders’ equity 4,498 4,372 Total liabilities and stockholders’ equity $ 19,975 $ 20,738

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

Three Months Ended June 30, Six Months Ended December 31, 2009 2008 2009 2008 (in millions, except share and per share amounts) Operating revenues $ 1,471 $ 2,828 $ 3,148 $ 4,779 Cost of revenue: Fuel and purchased energy expense 922 2,008 1,937 3,613 Plant operating expense 210 206 458 438 Depreciation and amortization expense 113 108 222 219 Other cost of revenue 20 30 43 62 Total cost of revenue 1,265 2,352 2,660 4,332 Gross profit 206 476 488 447 Sales, general and other administrative expense 48 48 93 96 Income from unconsolidated investments in power plants (23 ) (16 ) (40 ) (13 ) Other operating expense 6 11 9 13 Income from operations 175 433 426 351 Interest expense 207 206 417 625 Interest (income) (4 ) (14 ) (10 ) (27 ) Debt extinguishment costs 33 6 33 13 Other (income) expense, net — (5 ) 4 (2 ) Income (loss) before reorganization items and income taxes (61 ) 240 (18 ) (258 ) Reorganization items 3 18 6 (261 ) Income (loss) before income taxes (64 ) 222 (24 ) 3 Income tax expense 15 25 24 20 Net income (loss) $ (79 ) $ 197 $ (48 ) $ (17 ) Add: Net loss attributable to the noncontrolling interest 1 — 2 — Net income (loss) attributable to Calpine $ (78 ) $ 197 $ (46 ) $ (17 ) Basic earnings (loss) per common share: Weighted average shares of common stock outstanding (in thousands) 485,675 485,004 485,560 485,002 Net income (loss) per common share attributable to Calpine – basic $ (0.16 ) $ 0.41 $ (0.09 ) $ (0.04 ) Diluted earnings (loss) per common share: Weighted average shares of common stock outstanding (in thousands) 485,675 485,732 485,560 485,002 Net income (loss) per common share attributable to Calpine – diluted $ (0.16 ) $ 0.41 $ (0.09 ) $ (0.04 )

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended June 30, 2009 2008 (in millions) Cash flows from operating activities: Net loss $ (48 ) $ (17 ) Adjustments to reconcile net loss to net cash used in operating activities: Depreciation and amortization expense(1) 268 280 Debt extinguishment costs 7 7 Deferred income taxes 26 85 Loss on disposal of assets, excluding reorganization items 20 6 Mark-to-market activity, net (23 ) 63 Income from unconsolidated investments in power plants (40 ) (13 ) Stock-based compensation expense 22 19 Reorganization items — (322 ) Other 1 — Change in operating assets and liabilities: Accounts receivable 29 (246 ) Derivative instruments (257 ) (255 ) Other assets 173 (246 ) Accounts payable, LSTC and accrued expenses (23 ) 382 Other liabilities (191 ) (329 ) Net cash used in operating activities (36 ) (586 ) Cash flows from investing activities: Purchases of property, plant and equipment (97 ) (79 ) Disposals of property, plant and equipment — 11 Proceeds from sale of power plants, turbines and investments — 398 Cash acquired due to reconsolidation of Canadian Debtors and other foreign entities — 64 Contributions to unconsolidated investments (8 ) (9 )

Return of investment from unconsolidated investment

— 24

(Increase) decrease in restricted cash

(31 ) 56 Other (1 ) 4 Net cash provided by (used in) investing activities (137 ) 469 Cash flows from financing activities: Repayments of notes payable $ (54 ) $ (49 ) Repayments of project financing (843 ) (229 ) Borrowings from project financing 1,027 356 Repayments of DIP Facility — (113 ) Borrowings under Exit Facilities — 3,473 Repayments on Exit Facilities (30 ) (855 ) Repayments on Second Priority Debt — (3,672 ) Repayments on capital leases (31 ) (26 ) Redemptions of preferred interests (41 ) (159 ) Financing costs (29 ) (187 ) Derivative contracts classified as financing activities — 34 Other (1 ) (1 ) Net cash used in financing activities (2 ) (1,428 ) Net decrease in cash and cash equivalents (175 ) (1,545 ) Cash and cash equivalents, beginning of period 1,657 1,915 Cash and cash equivalents, end of period $ 1,482 $ 370 Cash paid (received) during the period for: Interest, net of amounts capitalized $ 398 $ 634 Income taxes $ 2 $ 15 Reorganization items included in operating activities, net $ 6 $ 109 Reorganization items included in investing activities, net $ — $

(414

) Supplemental disclosure of non-cash investing and financing activities: Settlement of commodity contract with project financing $ 79 $ — Change in capital expenditures included in accounts payable $ — $ (6 ) 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

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

REGULATION G RECONCILIATIONS

Commodity Margin, Adjusted EBITDA 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.

Commodity Margin includes our power and steam revenues, capacity revenue, revenue and expense from renewable energy credits (“REC”), transmission revenue and expenses, fuel and purchased energy expense, and cash settlements from our marketing, hedging and optimization activities that are included in mark-to-market activity, but excludes the unrealized portion of our mark-to-market activity and other revenue. 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 EBITDA represents net income (loss) before interest, taxes, depreciation and amortization, adjusted for certain non-cash and non-recurring items as detailed in the following reconciliation. 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. We believe Adjusted EBITDA is also used by and is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. 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.

Adjusted Free Cash Flow represents net income before interest, taxes, depreciation and amortization, as adjusted, less operating lease payments, major maintenance expense and maintenance capital expenditures, net cash interest, cash taxes, working capital and other adjustments. 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.

Commodity Margin Reconciliation

The following table reconciles our Commodity Margin to its GAAP results for the three months ended June 30, 2009 and 2008:

Three Months Ended June 30, 2009

(in millions)

Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 304 $ 196 $ 80 $ 70 $ — $ 650 Add: Mark-to-market commodity activity, net and other revenue(1) 57 (140 ) (25 ) 14 (9 ) (103 ) Less: Plant operating expense 100 50 35 23 2 210 Depreciation and amortization expense 52 31 17 15 (2 ) 113 Other cost of revenue(2) 12 2 1 7 (4 ) 18 Gross profit (loss) $ 197 $ (27 ) $ 2 $ 39 $ (5 ) $ 206 Three Months Ended June 30, 2008

(in millions)

Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 315 $ 215 $ 78 $ 67 $ — $ 675 Add: Mark-to-market commodity activity, net and other revenue(1) 64 51 16 22 (8 ) 145 Less: Plant operating expense 101 52 23 24 6 206 Depreciation and amortization expense 44 33 19 13 (1 ) 108 Other cost of revenue(2) 18 6 9 7 (10 ) 30 Gross profit $ 216 $ 175 $ 43 $ 45 $ (3 ) $ 476

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(1) Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, as well as a non-cash gain from amortization of prepaid power sales agreements included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations.

(2) Excludes $2 million and nil of REC expense for the three months ended June 30, 2009 and 2008, respectively, which is included as a component of Commodity Margin.

Commodity Margin Reconciliation (continued)

The following table reconciles our Commodity Margin to its GAAP results for the six months ended June 30, 2009 and 2008:

Six Months Ended June 30, 2009

(in millions)

Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 601 $ 318 $ 141 $ 119 $ — $ 1,179 Add: Mark-to-market commodity activity, net and other revenue(1) 79 (50 ) 6 16 (23 ) 28 Less: Plant operating expense 227 128 67 43 (7 ) 458 Depreciation and amortization expense 101 61 33 31 (4 ) 222 Other cost of revenue(2) 27 5 4 13 (10 ) 39 Gross profit $ 325 $ 74 $ 43 $ 48 $ (2 ) $ 488 Six Months Ended June 30, 2008

(in millions)

Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 593 $ 354 $ 113 $ 128 $ — $ 1,188 Add: Mark-to-market commodity activity, net and other revenue(1) 15 (74 ) 3 45 (11 ) (22 ) Less: Plant operating expense 213 122 53 50 — 438 Depreciation and amortization expense 95 63 38 25 (2 ) 219 Other cost of revenue(2) 35 6 18 13 (10 ) 62 Gross profit $ 265 $ 89 $ 7 $ 85 $ 1 $ 447

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(2) Excludes $4 million and nil of REC expense for the six months ended June 30, 2009 and 2008, respectively, which is included as a component of Commodity Margin.

Consolidated Adjusted EBITDA Reconciliation

In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our Income from operations for the three and six months ended June 30, 2009 and 2008, as reported under GAAP. No items listed below Income from operations as reported on our Consolidated Condensed Statements of Operations are included in the table as they are excluded from Adjusted EBITDA.

Three Months Ended June 30, Six Months Ended June 30, 2009 2008(1) 2009 2008(1) (in millions) Income from operations $ 175 $ 433 $ 426 $ 351 Add: Adjustments to reconcile GAAP income from operations to Adjusted EBITDA: Depreciation and amortization expense, excluding deferred financing costs(2) 116 118 229 240 Impairment charges — 6 — 6 Major maintenance expense 40 42 102 96 Operating lease expense 11 11 23 23 Non-cash gains on derivatives(3) — (11 ) — (20 ) Unrealized (gains) losses on commodity derivative mark-to-market activity 108 (122 ) (17 ) 65 Adjustments to reflect Adjusted EBITDA from unconsolidated investments(4),(5) (15 ) (12 ) (17 ) (5 ) Stock-based compensation expense 9 13 22 19 Non-cash loss on dispositions of assets 9 2 17 8 Other(6) 4 (1 ) 3 (3 ) Adjusted EBITDA $ 457 $ 479 $ 788 $ 780 Less: Lease payments 11 23 Major maintenance expense and capital expenditures(6) 84 197 Cash interest(7) 163 387 Cash taxes 11 2 Working capital and other adjustments 75 22 Adjusted Free Cash Flow $ 113 $ 157

_________

(1) Adjusted EBITDA for the three and six months ended June 30, 2008, has been recast to conform to our current period definition.

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

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

(4) Included in our Consolidated Condensed Statements of Operations in income from unconsolidated investments in power plants.

(5) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include $(20) million and $(14) million in unrealized losses on mark-to-market activity for the three months ended June 30, 2009 and 2008, respectively, and $(28) million and $(8) million for the six months ended June 30, 2009 and 2008, respectively.

(6) Includes $40 million and $102 million in major maintenance expense for the three and six months ended June 30, 2009, respectively, and $44 million and $95 million in capital expenditures for the three and six months ended June 30, 2009, respectively.

(7) Includes fees for letters of credit.

Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for 2009 Guidance

Full Year 2009 Range: Low High Recurring (in millions) Income from operations $ 1,025 $ 1,075 Plus: Depreciation and amortization expense 475 475 Major maintenance expense 190 190 Operating lease expense 50 50 Other(1) (65 ) (65 ) Adjusted EBITDA $ 1,675 $ 1,725 Less: Operating lease payments 50 50 $ 50 Major maintenance expense and maintenance capital expenditures(2) 350 350 ~300 Cash interest, net(3) 755 755 750 Cash taxes 5 5 10 Working capital and other adjustments 40 40 — Adjusted Free Cash Flow $ 475 $ 525

__________

(1) Other includes stock-based compensation expense and other adjustments.

(2) Includes major maintenance expense of $190 million and maintenance capital expenditures of $160 million. Capital expenditures exclude major construction and development projects funded with debt.

(3) Includes fees for letters of credit.

CASH FLOW ACTIVITIES

The following table summarizes our cash flow activities for the six months ended June 30, 2009 and 2008:

(Unaudited) Six Months Ended June 30, 2009 2008 (in millions) Beginning cash and cash equivalents $ 1,657 $ 1,915 Net cash provided by (used in): Operating activities (36 ) (586 ) Investing activities (137 ) 469 Financing activities (2 ) (1,428 ) Net decrease in cash and cash equivalents (175 ) (1,545 ) Ending cash and cash equivalents $ 1,482 $ 370

OPERATING PERFORMANCE METRICS

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

Three Months Ended June 30, Six Months Ended June 30, 2009 2008 2009 2008 Total MWh generated(1) (in thousands) 19,399 21,211 38,666 42,117 West 6,724 7,982 15,661 17,139 Texas 7,605 9,477 12,812 17,218 Southeast 3,957 2,635 7,836 5,305 North 1,113 1,117 2,357 2,455 Average availability 90.8% 89.9% 90.8% 87.9% West 91.2% 89.6% 90.8% 86.5% Texas 90.7% 91.8% 89.5% 86.9% Southeast 87.7% 89.3% 90.9% 90.2% North 96.0% 87.4% 94.0% 89.7% Average capacity factor, excluding peakers 43.0% 46.4% 43.1% 46.3% West 48.5% 57.3% 56.8% 61.9% Texas 48.0% 59.8% 40.7% 54.4% Southeast 34.6% 21.2% 34.5% 21.9% North 27.1% 28.0% 29.5% 31.1% Steam adjusted Heat Rate 7,271 7,268 7,230 7,215 West 7,414 7,319 7,296 7,269 Texas 7,132 7,144 7,086 7,057 Southeast 7,241 7,459 7,235 7,460 North 7,687 7,635 7,658 7,516

__________

(1) MWh generated is shown here as our net operating interest. Excludes generation at RockGen during the three and six months ended June 30, 2008, as the plant was deconsolidated during this period.

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