Calpine Corp. Reports Second Quarter 2010 Results, Updates & Raises Lower End of 2010 Guidance Range; Closes Strategic Acquis...

Calpine Corporation (NYSE:CPN) today reported second quarter 2010 Adjusted EBITDA of $381 million, down $76 million, or 17%, over the prior year period. The company also reported second quarter 2010 Adjusted Free Cash Flow of $117 million, compared to $171 million in the second quarter of 2009. Net loss1 for the quarter was $115 million, or $0.24 per diluted share, compared to a net loss1 of $78 million, or $0.16 per diluted share, in the 2009 period.

“Calpine made solid progress on two important fronts during the second quarter. First, we had solid operating performance, enabling us not only to reaffirm our full year guidance but to tighten it by raising the lower end of that guidance,” said Jack Fusco, Calpine’s President and Chief Executive Officer. “Second, we executed on our strategic initiative to diversify and expand our portfolio of plants in the eastern U.S. markets by closing the acquisition of the almost 4,500 MW Conectiv fleet of plants in the PJM market in a remarkable 70 days, enabling us to benefit from the July heat wave in the eastern United States. I also am very encouraged by the greater-than-expected PJM 2013-14 capacity auction results in May and the increased utilization of these plants this summer, which reinforces our view that this was a timely and strategically important acquisition that will deliver near-term and long-term value to our shareholders. Also worth mentioning is that we continue to make significant progress on our organic growth projects, most notably the test drilling at The Geysers where we have completed eight out of 13 exploratory wells. We are now evaluating the feasibility of adding at least 40 MW of capacity there to benefit from the California renewable energy market pricing.”

SUMMARY OF FINANCIAL PERFORMANCE

Second Quarter Results

Adjusted EBITDA was $381 million in the second quarter of 2010 compared to $457 million in the prior year period. The year-over-year decline was primarily due to a $91 million decrease in Commodity Margin concentrated in our Texas and West segments that declined by $68 million and $20 million respectively. In addition to lower average hedge prices and lower realized margin on our open positions relative to the same period in 2009, $26 million of the Commodity Margin decrease relates to the expiration of the PCF arrangement in our West segment at the end of 2009, the impact of new generation additions in Texas, which dampened prices, and higher rainfall in the West, which caused increased hydroelectric generation, were key drivers of the lower realized margins on open positions.

Partially offsetting these declines, positive contributions to Commodity Margin from the second quarter of 2009 to the second quarter of 2010 were an increase of $23 million related to higher renewable energy credit (REC) revenue from new contracts associated with our Geysers power plants and an increase of $21 million related to our Otay Mesa Energy Center, which achieved commercial operation in October 2009. Other revenue also increased by $14 million, primarily due to revenue related to prior periods associated with a major maintenance contract.

Net loss1 increased to $115 million for the three months ended June 30, 2010, from $78 million in the prior year period. As detailed in Table 1, net income, excluding reorganization items, discontinued operations, other items and unrealized mark-to-market gains or losses, decreased from $61 million in 2009 to a net loss of $42 million in 2010. The decrease was primarily attributable to the $91 million decline in Commodity Margin previously discussed.

Year-to-Date Results

Adjusted EBITDA for the six months ended June 30, 2010, was $663 million as compared to $788 million in the prior year period. The year-over-year decline in Adjusted EBITDA was primarily caused by a $165 million decline in Commodity Margin. Similar to the second quarter results discussed above, the Commodity Margin decrease was attributable to the expiration of the PCF arrangement at the end of 2009 in our West segment, which accounted for $51 million of the year-over-year decline, as well as lower average hedge margins and lower realized spark spreads on open positions due to weaker market conditions in the first half of 2010 compared to the same period in 2009.

For the year-to-date 2010 period, we have reduced aggregate plant operating expense2, sales, general and administrative expense2, and components of other cost of revenue by $30 million. These cost improvements were due, in large part, to efficiency efforts that we implemented over the course of 2009. In addition, other revenue has increased from $11 million year-to-date 2009 to $22 million year-to-date 2010 related to revenue from prior periods associated with a major maintenance contract.

Cash flows provided by operating activities for the six months ended June 30, 2010, resulted in net inflows of $156 million compared to cash flows used in operating activities of $36 million for the same period in 2009. The change in cash flows from operating activities was primarily due to decreases in working capital, which decreased by approximately $267 million during the period after adjusting for debt related balances which did not impact cash provided by operating activities. In addition, the working capital decrease was due to reductions in margin deposits and certain derivative activity. Cash paid for interest decreased by $36 million to $362 million for the six months ended June 30, 2010, as compared to $398 million for the same period in 2009, primarily due to the refinancing of Calpine Construction Financing Company and other project financing. This was partially offset by a decrease in gross profit which, after excluding non-cash items decreased, by $126 million in 2010.

Net loss1 increased to $162 million for the six months ended June 30, 2010, from $46 million in the prior year period. As detailed in Table 1, net loss, excluding reorganization items, discontinued operations, other items and unrealized mark-to-market gains or losses, increased from $30 million in 2009 to $198 million in 2010. The decrease was primarily due to the $165 million decline in Commodity Margin previously discussed.

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

2 Plant operating expense and sales, general and administrative expense exclude, in the aggregate, decreases in major maintenance expense of $4 million, decreases in stock-based compensation expense of $10 million, decreases in non-cash loss on dispositions of assets of $12 million, increases in depreciation and amortization of $53 million, Conectiv acquisition related costs of $19 million, and plant operating expense associated with Otay Mesa Energy Center of $7 million. See the table titled "Consolidated Adjusted EBITDA Reconciliation" for the actual amounts of these items for the six months ended June 30, 2010 and 2009.

Table 1: Summarized Consolidated Condensed Statements of Operations

(Unaudited) Three Months Ended June 30, Six Months Ended June 30, 2010 2009 2010 2009 (in millions) Operating revenues $ 1,430 $ 1,445 $ 2,944 $ 3,097 Cost of revenue (1,273 ) (1,256 ) (2,614 ) (2,642 ) Gross profit 157 189 330 455 SG&A, (income) from unconsolidated investments in power plants and other operating expense 49 30 72 62 Income from operations 108 159 258 393 Net interest expense, debt extinguishment costs and other (income) expense 220 231 415 434 Loss before reorganization items, income taxes and discontinued operations (112 ) (72 ) (157 ) (41 ) Reorganization items – 3 – 6 Income tax expense 6 15 17 24 Loss before discontinued operations (118 ) (90 ) (174 ) (71 ) Discontinued operations, net of tax expense 4 11 12 23 Net loss $ (114 ) $ (79 ) $ (162 ) $ (48 ) Net (income) loss attributable to the noncontrolling interest (1 ) 1 – 2 Net loss attributable to Calpine $ (115 ) $ (78 ) $ (162 ) $ (46 ) Reorganization items(1) – 3 – 6 Other items(1)(2) 26 33 26 33 Net loss net of reorganization and other items (89 ) (42 ) (136 ) (7 ) Unrealized MtM (gains) losses on derivatives(1)(3) 47 103 (62 ) (23 ) Net income (loss), net of reorganization items, other items and unrealized MtM impacts $ (42 ) $ 61 $ (198 ) $ (30 )

(1)

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

(2)

Other items for the three and six months ended June 30, 2010, include $7 million in debt extinguishment costs and $19 million in Conectiv acquisition-related costs.Other items for the three and six months ended June 30, 2009, include $33 million in debt extinguishment costs.

(3)

Represents unrealized mark-to-market (MtM) (gains) losses on contracts that did not qualify as hedges under the hedge accounting guidelines or qualified under the hedge accounting guidelines and the hedge accounting designation had not been elected. Includes amounts related to Blue Spruce and Rocky Mountain for the three and six months ended June 30, 2009.

REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin by Segment (in millions)

Three Months Ended June 30, Six Months Ended June 30, 2010 2009 2010 2009 West $ 258 $ 278 $ 471 $ 550 Texas 128 196 235 318 Southeast 68 80 126 141 North 79 70 131 119 Total $ 533 $ 624 $ 963 $ 1,128

West: Commodity Margin in our West segment decreased by $20 million for the three months ended June 30, 2010 compared to the same period in 2009, primarily resulting from a decrease of $26 million related to the expiration of the PCF arrangement in the fourth quarter of 2009, lower average hedge prices for the second quarter of 2010 compared to 2009, and lower realized spark spreads on our open positions due in part to strong hydro conditions in June 2010 compared to the same period in 2009. The decrease in Commodity Margin was partially offset by an increase of $23 million related to higher REC revenue from new contracts associated with our Geysers assets, $21 million from our Otay Mesa Energy Center (OMEC) that achieved commercial operation in October 2009 and a $12 million credit recognized in the second quarter of 2010 related to overcharges associated with a gas transportation contract.

For the six-month period, Commodity Margin in our West segment decreased by $79 million primarily resulting from a decrease of $51 million related to the expiration of the PCF arrangement in the fourth quarter of 2009, lower average hedge prices in the first half of 2010 compared to 2009, lower realized spark spreads on our open positions and a decrease of $11 million for the sale of surplus emission allowances in the first quarter of 2009 which did not reoccur in the same period in 2010. The decrease in Commodity Margin was partially offset by an increase of $26 million related to higher REC revenue from new contracts associated with our Geysers assets and $40 million from OMEC.

Texas: Commodity Margin in our Texas segment decreased by $68 million for the three months ended June 30, 2010, compared to the same period in 2009, primarily resulting from lower average hedge prices and lower realized spark spreads on open positions, particularly in June 2010, which did not benefit from the extreme heat, congestion-driven pricing and tighter reserve margin that prevailed in June 2009.

Commodity Margin in our Texas segment decreased by $83 million for the six months ended June 30, 2010, compared to the same period in 2009, primarily resulting from lower average hedge prices and lower realized spark spreads on open positions.

Southeast: Commodity Margin in our Southeast segment decreased by $12 million primarily resulting from lower average hedge prices and lower realized spark spreads for our Oneta and Pine Bluff power plants partially offset by the non-recurring negative impact of the settlement of a disputed steam contract in the second quarter of 2009.

For the first half of 2010, Commodity Margin in our Southeast segment decreased by $15 million. The six-month results were largely impacted by the same factors that drove performance for the second quarter, as previously discussed.

North: Commodity Margin in our North segment increased by $9 million primarily due to higher average hedge prices and higher realized spark spreads on open positions driven by much warmer weather for May and June 2010 compared to the same period in 2009.

Commodity Margin in our North segment increased by $12 million. Again, the six month results were largely impacted by the same factors that drove performance for the second quarter, as previously discussed.

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Corporate Liquidity

June 30, December 31, 2010 2009 (in millions) Cash and cash equivalents, corporate(1) $ 758 $ 725 Cash and cash equivalents, non-corporate 213 264 Total cash and cash equivalents 971 989 Restricted cash 345 562 Letter of credit availability(2) 65 34 Revolver availability 763 794 Total current liquidity $ 2,144 $ 2,379

(1)

Includes $58 million and $9 million of margin deposits held by us posted by our counterparties as of June 30, 2010, and December 31, 2009, respectively.

(2)

Includes available balances for Calpine Development Holdings, Inc, which increased our availability by $50 million under this letter of credit facility on June 30, 2010.

We maintained strong liquidity during the second quarter, ending the period with liquidity in excess of $2.1 billion; however, liquidity declined by more than $200 million during the first half of 2010 from $2.4 billion at December 31, 2009. As previously discussed, operating activities resulted in net cash proceeds of $156 million during the 2010 period, compared to a net outflow of $36 million during the 2009 period. In addition, cash flows from investing activities resulted in a net inflow of $138 million during the first half of 2010, driven largely by reduced restricted cash balances associated primarily with the maturity of our PCF project financing instrument, partially offset by $97 million in total capital expenditures during the quarter, including $47 million spent for previously announced growth projects. Cash flows from financing activities resulted in a net outflow of $312 million, primarily as a result of our repayment of the PCF financing and other payments made under project debt waterfall provisions. Additionally, consistent with our efforts to maintain strong liquidity, during the second quarter of 2010, we increased the availability of the Calpine Development Holdings, Inc. letter of credit facility by $50 million to a total of $200 million.

During the first half of 2010, we generated $104 million of Adjusted Free Cash Flow, representing a decline of $80 million over 2009 results for the same period. The year-over-year decline in Adjusted Free Cash Flow was primarily the result of the $125 million decrease in Adjusted EBITDA, as previously discussed, partially offset by a $53 million improvement in major maintenance expense and capital expenditures from 2009 to 2010.

Subsequent to the end of this reporting period, the company utilized a portion of cash and cash equivalents to help fund the acquisition of Conectiv, as previously discussed, and retired $100 million of debt associated with the Commodity Collateral Revolver on July 8, 2010, which together reduced liquidity by $465 million. However, this reduction in liquidity is expected to be offset by the anticipated receipt of net proceeds of $315 million related to the sale of our Colorado assets, expected to close by the end of the year.

PLANT DEVELOPMENT

York Energy Center (formerly the Delta Project): We acquired the 565 MW dual fuel, combined-cycle power plant under construction in Peach Bottom Township, Pennsylvania, formerly referred to as the Delta Project, as part of the Conectiv acquisition. Because Calpine already had a plant named Delta Energy Center, this project has been renamed York Energy Center. The York Energy Center remains on budget and on schedule. All permits have been received and commercial operations are expected to commence in the summer of 2011. The York Energy Center will sell power under a six-year Power Purchase Agreement (PPA) with a Baltimore based energy company. As part of the Conectiv purchase, the project subsidiary (New Development Holdings, LLC) plans to fund the remaining expected capital expenditures of approximately $110 million to complete construction.

Russell City Energy Center: Russell City Energy Center remains under advanced stages of development. The Russell City Energy Center is currently contracted to deliver its full output of 600 MW to Pacific Gas & Electric (PG&E) under a PPA, which was executed in December 2006 and approved by the California Public Utilities Commission (CPUC) in January 2007. The PPA was amended in 2008 and again on April 9, 2010, to extend the expected commercial operation date to June 2013 as a result of delays in obtaining certain permits. We are in possession of all material permits; however the permits are subject to an appeal period related to our air permit and possible amendments to our California Energy Commission license. We and other parties filed a joint petition on April 15, 2010, seeking CPUC approval of the amendment to the PPA. We do not expect the CPUC to act on the petition for approval prior to September 2010. Upon completion, this project would bring on line approximately 362 MW of net interest baseload capacity (390 MW with peaking capacity) representing our 65% share.

Geysers Expansion: We continue to consider expanding production from our Geysers assets in northern California. To date, we have completed eight out of 13 planned test wells. The completed wells, in aggregate, have met or exceeded our expectations. We expect to make a determination before the end of 2010 if the new wells will produce enough additional steam to warrant the construction of additional geothermal power plants at our Geysers assets.

Los Esteros Expansion: During 2009, we and PG&E negotiated a new PPA to replace the existing California Department of Water Resources contract and facilitate the upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle generation power plant to a 308 MW combined-cycle generation power plant. In addition to the increase in capacity, the upgrade will increase the efficiency and environmental performance of the power plant by lowering the heat rate. The PPA received approval from the CPUC on July 29, 2010.

Turbine Upgrades: We continue to move forward with our turbine upgrade program. We have completed the upgrade of four Siemens turbines and plan to upgrade approximately nine additional Siemens turbines. Our Siemens turbine upgrade program is expected to increase our generation capacity in total by approximately 195 MW with estimated remaining capital expenditures of approximately $90 million. These upgrades began in the fourth quarter of 2009 and are scheduled through 2014. To date, the initial testing of the upgraded turbines has indicated additional capacity and improvements in operating heat rates falling in line with expectations of 15 MW per turbine and an incremental heat rate of less than 5,000 Btu/KWh.

OPERATIONS UPDATE

2010 Power Operations Achievements:

Safety Performance:
- First quartile lost-time incident rate of 0.19 year-to-date
- No employee lost-time accidents recorded during the second quarter of 2010
Availability Performance:
- Achieved a strong second quarter geothermal availability factor of 98%
- Maintained second quarter fleet-wide average availability factor of nearly 88%
- Achieved a fleet-wide starting reliability of nearly 98%
Geothermal Generation: Provided approximately 1.5 million MWh of renewable baseload generation with 95% capacity factor and 0.37% forced outage factor
Natural Gas-fired Generation:
- Increased production from natural gas-fired plants by nearly 5%
- Successfully integrated 18 new operating plants into our fleet from the Conectiv acquisition
- Westbrook Energy Center earned Star Worksite designation under the stringent federal Voluntary Protection Program. This award is OSHA’s highest level of recognition for exemplary workplace health and safety efforts.
Sustainable Cost Reductions: Reduced plant operating expense2, sales, general and administrative expense2 and components of other cost of revenue, largely through efficiency efforts and disciplined cost controls by $30 million through June 2010. Along with savings achieved in 2009, we are very close to our goal of $100 million in expense savings from our 2008 amounts.

2010 Commercial Operations Achievements:

Customer-oriented Growth:
- Signed new seven-year, 200 MW PPA for capacity and energy supply to Southwestern Public Service Company, a subsidiary of Xcel Energy, from our Oneta Energy Center
- Received CPUC approval for a 425 MW geothermal supply to Pacific Gas & Electric Company
- Received CPUC approval for a 25 MW geothermal supply to San Diego Gas & Electric, a subsidiary of Sempra Energy

FINANCIAL OUTLOOK

Table 4: Adjusted EBITDA and Adjusted Free Cash Flow Guidance

Full Year 2010 (in millions) Adjusted EBITDA $ 1,650 – 1,725 Less: Operating lease payments 45 Major maintenance expense and capital expenditures(1) 300 Cash interest, net 815 Cash taxes 15 Adjusted Free Cash Flow $ 475 – 550

(1)

Includes projected Major Maintenance Expense of $180 million and maintenance Capital Expenditures of $120 million. Capital Expenditures exclude major construction and development projects.

(2)

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

Today, we are updating and tightening our 2010 guidance, which includes the estimated impact of the planned sale of our Colorado power plants. Including this transaction, we are projecting Adjusted EBITDA of $1,650 million to $1,725 million and Adjusted Free Cash Flow of $475 million to $550 million. We are also updating estimates of our growth capital for 2010. We expect to invest $220 million in growth-related projects during the year, including the ongoing projects that we have acquired from Conectiv Energy, our ongoing turbine upgrade program, the addition of incremental steam wells at The Geysers, and the proposed 120 MW upgrade of our Los Esteros plant and our proposed 600 MW Russell City Energy Center.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results for the second quarter of 2010 on Friday, July 30, 2010, at 10:00 a.m. ET / 9:00 a.m. CT. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing 888-857-6930 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 our website. The recording also can be accessed by dialing 888-203-1112 or 719-457-0820 for international listeners and providing Confirmation Code 2778412. Presentation materials to accompany the conference call will be made available on our website on July 30, 2010.

ABOUT CALPINE

Founded in 1984, Calpine Corporation is a major U.S. power company, currently capable of delivering nearly 29,000 megawatts of clean, cost-effective, reliable and fuel-efficient power from its 93 operating plants to customers and communities in 21 states and Canada. Calpine Corporation is committed to helping meet the needs of an economy that demands more and cleaner sources of electricity. Calpine owns, leases and operates primarily 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 our website at www.calpine.com for more information.

Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, has been filed with the Securities and Exchange Commission (SEC) and may be found on the SEC’s website at www.sec.gov.

FORWARD-LOOKING INFORMATION

In addition to historical information, our Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the Exchange Act. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” 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, the timing and strength of an economic recovery, if any, and their impacts on our business including demand for our power and steam products, the ability of customers, suppliers, service providers and other contractual counterparties to perform under their contracts with us and the cost and availability of capital and credit;
Financial results that may be volatile and may not reflect historical trends due to, among other things, fluctuations in prices for commodities such as natural gas and power, fluctuations in liquidity and volatility in the energy commodities markets and our ability to hedge risks;
Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions;
Our ability to manage our significant liquidity needs and to comply with covenants under our existing financing obligations, including our First Lien Credit Facility, First Lien Notes and New Development Holdings Project Debt;
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 and derivative transactions;
Natural disasters such as hurricanes, earthquakes and floods, or acts of terrorism 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 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, variables associated with the injection of wastewater to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;
Risks associated with the operation, construction and development of power plants, including unscheduled outages or delays and plant efficiencies;
Present and possible future claims, litigation and enforcement actions;
The expiration or termination of our power purchase agreements and the related results on revenues;
Our planned sale of Blue Spruce and Rocky Mountain may not close as planned;
Future PJM capacity revenues expected from the Conectiv acquisition may not occur at expected levels; and
Other risks identified in this release or in our reports and registration statements filed with the SEC, including, without limitation, the risk factors identified in our Quarterly Report on Form 10-Q for the three months ended June 30, 2010, and in our Annual Report on Form 10-K for the year ended December 31, 2009.

Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of today’s date. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

Three Months Ended June 30, Six Months Ended June 30, 2010 2009 2010 2009 (in millions, except share and per share amounts) Operating revenues $ 1,430 $ 1,445 $ 2,944 $ 3,097 Cost of revenue: Fuel and purchased energy expense 904 922 1,873 1,937 Plant operating expense 213 206 431 449 Depreciation and amortization expense 132 108 265 213 Other cost of revenue 24 20 45 43

Total cost of revenue

1,273 1,256 2,614 2,642 Gross profit 157 189 330 455 Sales, general and other administrative expense 53 48 78 93 (Income) from unconsolidated investments in power plants (6 ) (23 ) (13 ) (40 ) Other operating expense 2 5 7 9 Income from operations 108 159 258 393 Interest expense 216 203 408 409 Interest (income) (4 ) (4 ) (6 ) (10 ) Debt extinguishment costs 7 33 7 33 Other (income) expense, net 1 (1 ) 6 2 Loss before reorganization items, income taxes and discontinued operations (112

)

(72 ) (157 ) (41 ) Reorganization items

—

3 — 6 Loss before income taxes and discontinued operations (112 ) (75 ) (157 ) (47 ) Income tax expense 6 15 17 24 Loss before discontinued operations $ (118 ) $ (90 ) $ (174 ) $ (71 ) Discontinued operations, net of tax expense 4 11 12 23 Net loss $ (114 ) $ (79 ) $ (162 ) $ (48 ) Net (income) loss attributable to the noncontrolling interest (1 ) 1 — 2 Net loss attributable to Calpine $ (115 ) $ (78 ) $ (162 ) $ (46 ) Basic and diluted loss per common share attributable to Calpine: Weighted average shares of common stock outstanding (in thousands) 486,057 485,675 485,989 485,560 Loss before discontinued operations $ (0.25 ) $ (0.18 ) $ (0.35 ) $ (0.14 ) Discontinued operations, net of tax expense 0.01 0.02 0.02 0.05 Net loss per common share – basic and diluted $ (0.24 ) $ (0.16 ) $ (0.33 ) $ (0.09 )

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

June 30,

December 31, 2010 2009

(in millions, except share and per share amounts)

ASSETS Current assets: Cash and cash equivalents ($207 and $242 attributable to VIEs) $ 971 $ 989 Accounts receivable, net of allowance of $2 and $14 679 750 Margin deposits and other prepaid expense 331 490 Restricted cash, current ($267 and $322 attributable to VIEs) 298 508 Derivative assets, current 1,240 1,119 Assets held for sale ($548 attributable to VIEs) 548 — Inventory and other current assets 222 243

Total current assets

4,289 4,099 Property, plant and equipment, net ($5,208 and $5,319 attributable to VIEs) 11,408 11,583 Restricted cash, net of current portion ($40 and $45 attributable to VIEs) 47 54 Investments 89 214 Long-term derivative assets 223 127 Other assets 593 573 Total assets $ 16,649 $ 16,650 LIABILITIES & STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable $ 482 $ 578 Accrued interest payable 59 54 Debt, current portion ($575 and $106 attributable to VIEs) 699 463 Derivative liabilities, current 1,244 1,360 Liabilities held for sale 13 — Other current liabilities 276 294 Total current liabilities 2,773 2,749 Debt, net of current portion ($2,816 and $3,042 attributable to VIEs) 8,827 8,996 Deferred income taxes, net of current portion 112 54 Long-term derivative liabilities 382 197 Other long-term liabilities 216 208 Total liabilities 12,310 12,204 Commitments and contingencies Stockholders’ equity: Preferred stock, $.001 par value per share; 100,000,000 shares authorized; none issued and outstanding — — Common stock, $.001 par value per share; 1,400,000,000 shares authorized; 445,034,189 and 443,325,827 shares issued, respectively, and 444,586,271 and 442,998,255 shares outstanding, respectively 1 1 Treasury stock, at cost, 447,918 and 327,572 shares, respectively (5 ) (3 ) Additional paid-in capital 12,268 12,256 Accumulated deficit (7,702 ) (7,540 ) Accumulated other comprehensive loss (223 ) (266 ) Total Calpine stockholders’ equity 4,339 4,448 Noncontrolling interest —

)

Total stockholders’ equity 4,339 4,446 Total liabilities and stockholders’ equity $ 16,649 $ 16,650

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended June 30, 2010 2009 (in millions) Cash flows from operating activities: Net loss $ (162

)

$ (48 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation and amortization expense(1) 298 268 Debt extinguishment costs 7 7 Deferred income taxes (4 ) 26 Loss on disposal of assets 9 20 Unrealized mark-to-market activity, net (62 ) (23 ) Income from unconsolidated investments in power plants (13 ) (40 ) Stock-based compensation expense 12 22 Other 1 1 Change in operating assets and liabilities: Accounts receivable 68 29 Derivative instruments, net (81 ) (257 ) Other assets 171 173 Accounts payable and accrued expenses (91 ) (23 ) Other liabilities 3 (191 ) Net cash provided by (used in) operating activities 156 (36 ) Cash flows from investing activities: Purchases of property, plant and equipment (97 ) (97 ) Cash acquired due to consolidation of Otay Mesa Energy Center 8 — Contributions to unconsolidated investments

—

)

(Increase) decrease in restricted cash 224 (31 ) Other 3 (1 ) Net cash provided by (used in) investing activities 138 (137 )

Cash flows from financing activities:

Repayments of project financing, notes payable and other

(277

)

(969

)

Borrowings from project financing, notes payable and other

—

1,027

Issuance of First Lien Notes

400

—

Repayments on First Lien Credit Facility

(430

)

(30

)

Refund of financing costs

—

Financing costs

(15

)

(29

)

Other

—

)

Net cash used in financing activities

(312

)

Net decrease in cash and cash equivalents

(18

)

(175

)

Cash and cash equivalents, beginning of period

989

1,657

Cash and cash equivalents, end of period

971

1,482

Cash paid during the period for:

Interest, net of amounts capitalized

362

398

Income taxes

Reorganization items included in operating activities, net

—

Supplemental disclosure of non-cash investing and financing activities:

Settlement of commodity contract with project financing

—

Change in capital expenditures included in accounts payable

)

—

(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 be viewed as a supplement to and not a substitute for our GAAP measures of performance.

Commodity Margin includes our power and steam revenues, sales of purchased power and natural gas, capacity revenue, revenue from renewable energy credits, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, RGGI compliance and other environmental costs 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 revenues. 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. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Adjusted EBITDA is not a measure calculated in accordance with GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with GAAP. 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, 2010 and 2009:

Three Months Ended June 30, 2010

(in millions)

Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 258 $ 128 $ 68 $ 79 $ — $ 533 Add: Mark-to-market commodity activity, net and other revenue(1) 10 (10 ) (9 ) 3 (6 ) (12 ) Less: Plant operating expense 88 78 31 23 (7 ) 213 Depreciation and amortization expense 50 39 26 18 (1 ) 132 Other cost of revenue(2) 10 (5 ) — 7 7 19 Gross profit $ 120 $ 6 $ 2 $ 34 $ (5 ) $ 157 Three Months Ended June 30, 2009

(in millions)

Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 278 $ 196 $ 80 $ 70 $ — $ 624 Add: Mark-to-market commodity activity, net and other revenue(1) 57 (140 ) (25 ) 14 (9 ) (103 ) Less: Plant operating expense 96 50 35 23 2 206 Depreciation and amortization expense 47 31 17 15 (2 ) 108 Other cost of revenue(2) 12 2 1 7 (4 ) 18 Gross profit (loss) $ 180 $ (27 ) $ 2 $ 39 $ (5 ) $ 189

(1)

Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations for the three months ended June 30, 2010 and 2009.

(2)

Excludes $5 million and $2 million of RGGI compliance and other environmental costs for the three months ended June 30, 2010 and 2009, respectively, which are included as a component of Commodity Margin.

The following table reconciles our Commodity Margin to its GAAP results for the six months ended June 30, 2010 and 2009:

Six Months Ended June 30, 2010

(in millions)

Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 471 $ 235 $ 126 $ 131 $ — $ 963 Add: Mark-to-market commodity activity, net and other revenue(1) 18 86 13 — (14 ) 103 Less: Plant operating expense 178 162 59 45 (13 ) 431 Depreciation and amortization expense 101 74 55 38 (3 ) 265 Other cost of revenue(2) 25 1 2 14 (2 ) 40 Gross profit $ 185 $ 84 $ 23 $ 34 $ 4 $ 330 Six months Ended June 30, 2009

(in millions)

Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 550 $ 318 $ 141 $ 119 $ — $ 1,128 Add: Mark-to-market commodity activity, net and other revenue(1) 79 (50 ) 6 16 (23 ) 28 Less: Plant operating expense 218 128 67 43 (7 ) 449 Depreciation and amortization expense 92 61 33 31 (4 ) 213 Other cost of revenue(2) 27 5 4 13 (10 ) 39 Gross profit $ 292 $ 74 $ 43 $ 48 $ (2 ) $ 455

(1)

(2)

Excludes $5 million and $4 million of RGGI compliance and other environmental costs for the six months ended June 30, 2010 and 2009, respectively, which are 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 Net Income for the three and six months ended June 30, 2010 and 2009, as reported under GAAP.

Three Months Ended June 30, Six Months Ended June 30, 2010 2009 2010 2009 (in millions) GAAP net loss attributable to Calpine $ (115 ) $ (78 ) $ (162 ) $ (46 ) Net income (loss) attributable to noncontrolling interest 1 (1 ) — (2 ) Discontinued operations, net of tax expense (4 ) (11 ) (12 ) (23 ) Income tax expense 6 15 17 24 Reorganization items — 3 — 6 Other (income) expense and debt extinguishment costs, net 8 32 13 35 Interest expense, net 212 199 402 399 Income from operations $ 108 $ 159 $ 258 $ 393 Add: Adjustments to reconcile income from operations to Adjusted EBITDA: Depreciation and amortization expense, excluding deferred financing costs(1) 136 111 273 220 Major maintenance expense 43 40 98 102 Operating lease expense 11 11 22 23 Unrealized (gains) losses on commodity derivative mark-to-market activity 31 108 (81 ) (17 ) Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2),(3) 8 (15 ) 15 (17 ) Stock-based compensation expense 6 9 12 22 Non-cash loss (gain) on dispositions of assets (1 ) 9 5 17 Conectiv acquisition-related costs & Other(4) 19 5 20 4 Adjusted EBITDA from continuing operations 361 437 622 747 Adjusted EBITDA from discontinued operations 20 20 41 41 Total adjusted EBITDA $ 381 $ 457 $ 663 $ 788 Less: Lease payments 11 11 22 23 Major maintenance expense and capital expenditures(5) 55 76 146 199 Cash interest(6) 192 196 384 385 Cash taxes 6 1 8 (8 ) Other —

(1 ) 5 Adjusted Free Cash Flow(7)(8) $ 117 $ 171 $ 104 $ 184

(1)

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.

(2)

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

(3)

Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized gains on mark-to-market activity of nil and $26 million for the three months ended June 30, 2010 and 2009, respectively, and nil and $41 million for the six months ended June 30, 2010 and 2009, respectively.

(4)

Includes fees for letters of credit. Includes Conectiv acquisition-related costs of $19 million for the three and six months ended June 30, 2010.

(5)

Includes $43 million and $101 million in major maintenance expense for the three and six months ended June 30, 2010, respectively, and $10 million and $42 million in maintenance capital expenditures for the three and six months ended June 30, 2010, respectively. Includes $40 million and $102 million in major maintenance expense for the three and six months ended June 30, 2009, respectively, and $36 million and $97 million in maintenance capital expenditures for the three and six months ended June 30, 2009, respectively.

(6)

Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income.

(7)

Excludes decrease in working capital of $141 million and $80 million for the three and six months ended June 30, 2010 and $47 million and $29 million for the three and six months ended June 30, 2009.

(8)

Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance. Results for the three and six months ended June 30, 2009 have been recast to conform to this method.

In the following table, we have reconciled our Adjusted EBITDA to our Commodity Margin, both of which are non-GAAP measures, for the three and six months ended June 30, 2010 and 2009. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable GAAP measures are provided above.

Three Months Ended June 30, Six Months Ended June 30, 2010 2009 2010 2009 (in millions) Commodity Margin $ 533 $ 624 $ 963 $ 1,128 Other revenue 19 5 22 11 Plant operating expense(1) (168 ) (155 ) (323 ) (321 ) Other cost of revenue(2) (7 ) (7 ) (16 ) (14 ) Sales, general and administrative expense(3) (27 ) (38 ) (46 ) (74 ) Adjusted EBITDA from unconsolidated investments in power plants(4) 14 9 28 24 Other operating expense (3 ) (6 ) (7 ) (11 ) Adjusted EBITDA from discontinued operations(5) 20 20 41 41 Other — 5 1 4 Adjusted EBITDA $ 381 $ 457 $ 663 $ 788

(1)

Shown net of major maintenance expense, stock-based compensation expense, and non-cash loss on dispositions of assets.

(2)

Excludes $5 million and $2 million of RGGI compliance and other environmental costs for the three months ended June 30, 2010 and 2009, respectively, and $5 million and $4 million for the six months ended June 30, 2010 and 2009, respectively, which are included as a component of Commodity Margin.

(3)

Shown net of depreciation and amortization, stock-based compensation expense and acquisition-related costs.

(4)

Amount is comprised of income from unconsolidated investments in power plants, as well as adjustments to reflect Adjusted EBTIDA from unconsolidated investments.

(5)

Includes Adjusted EBITDA from Blue Spruce and Rocky Mountain.

Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance

Full Year 2010 Range: Low High (in millions) GAAP Net Income $ (45 ) $ 30 Plus: Interest expense, net of interest income 800 800 Depreciation and amortization expense 585 585 Major maintenance expense 185 185 Operating lease expense 45 45 Other(1) 80 80 Adjusted EBITDA $ 1,650 $ 1,725 Less: Operating lease payments 45 45 Major maintenance expense and maintenance capital expenditures(2) 300 300 Cash interest, net(3) 815 815 Cash taxes 15 15 Adjusted Free Cash Flow $ 475 $ 550

(1)

Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, and other items.

(2)

Includes projected Major Maintenance Expense of $180 million and maintenance Capital Expenditures of $120 million. Capital Expenditures exclude major construction and development projects.

(3)

Includes fees for letters of credit, net of interest income.

CASH FLOW ACTIVITIES

The following table summarizes our cash flow activities for the six months ended June 30, 2010 and 2009:

Six Months Ended June 30, 2010 2009 (in millions) Beginning cash and cash equivalents $ 989 $ 1,657 Net cash provided by (used in): Operating activities 156 (36 ) Investing activities 138 (137 ) Financing activities (312 ) (2 ) Net decrease in cash and cash equivalents (18 ) (175 ) Ending cash and cash equivalents $ 971 $ 1,482

OPERATING PERFORMANCE METRICS

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

Three Months Ended June 30, Six Months Ended June 30, 2010 2009 2010 2009 Total MWh generated (in thousands) 19,246 18,422 39,604 36,576 West 5,485 5,747 14,702 13,571 Texas 8,243 7,605 14,885 12,812 Southeast 4,222 3,957 7,647 7,836 North 1,296 1,113 2,370 2,357 Average availability 87.7% 90.6% 89.0% 90.6% West 88.4% 90.7% 90.8% 89.9% Texas 88.4% 90.7% 85.5% 89.5% Southeast 87.1% 87.7% 91.4% 90.9% North 85.4% 96.0% 88.9% 94.0% Average capacity factor, excluding peakers 42.5% 42.3% 44.3% 42.3% West 40.2% 46.0% 54.2% 54.9% Texas 52.4% 48.7% 47.8% 41.3% Southeast 35.3% 34.8% 32.8% 34.7% North 31.3% 26.3% 28.8% 28.6% Steam adjusted heat rate (mmbtu/kWh) 7,306 7,274 7,266 7,239 West 7,359 7,458 7,298 7,340 Texas 7,222 7,132 7,169 7,086 Southeast 7,319 7,241 7,305 7,235 North 7,648 7,687 7,613 7,658

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