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Calpine Corp. Reports First Quarter 2011 Results, Reaffirms 2011 Guidance

04/29/2011

Recent Achievements:

  • Generated 19.0 million MWh1 of electricity
  • Commenced commercial operation at York Energy Center, a 565 MW combined-cycle power plant in eastern Pennsylvania, three months early and under budget
  • Finalized terms of ten-year contract for one of our power plants in the Southeast
  • Successfully issued $1.3 billion Senior Secured Term Loan, refinancing higher-cost project debt while simplifying our capital structure
  • Launched marketing process to monetize value of two power plants
First Quarter 2011 Financial Results:
  • $303 million of Adjusted EBITDA
  • $(21) million of Adjusted Recurring Free Cash Flow
  • $489 million of Commodity Margin
  • $297 million of Net Loss2
Reaffirming 2011 Full Year Guidance:
  • 2011 Adjusted EBITDA guidance of $1,700 - $1,800 million
  • 2011 Adjusted Recurring Free Cash Flow guidance of $440 - $540 million

HOUSTON, Apr 29, 2011 (BUSINESS WIRE) -- Calpine Corporation (NYSE:CPN) today reported first quarter 2011 Adjusted EBITDA of $303 million, compared to $282 million in the prior year first quarter, and first quarter 2011 Adjusted Recurring Free Cash Flow of $(21) million, compared to $(13) million in the first quarter of 2010. Driven in large part by debt extinguishment costs and net losses on interest rate derivatives totaling $202 million, Net Loss2 for the quarter was $297 million, or $0.61 per diluted share, compared to a Net Loss2 of $47 million, or $0.10 per diluted share, in the 2010 period.

"During the first quarter, we made steady progress on our initiatives to monetize our asset base, achieve financially disciplined growth and continue to improve our plants' operating performance. If the merchant market is not fairly valuing our plants, we may monetize them by entering into long-term contracts or selling the plant. Toward that end, we have finalized the terms of a ten-year PPA for one of our power plants in the Southeast and we have commenced a marketing process for the sale of our Broad River and Mankato plants," said Jack Fusco, Calpine's President and Chief Executive Officer. "With respect to growth, we commenced commercial operation at the 565 MW York Energy Center in Pennsylvania, three months ahead of schedule and under budget, an accomplishment for which I commend our construction and operating teams. Operationally, our first quarter fleet-wide starting reliability reached a record high and we beat our target of a 2.5% forced outage factor. Unfortunately, we did experience operating issues during February's extreme cold weather event in Texas, but our operations teams have since conducted root cause analyses and developed additional processes and procedures to alleviate these concerns going forward. On costs, we continued to hold the line with our legacy fleet compared to the prior year first quarter, after having reduced our run rate by more than $100 million over the last two years. Finally, we refinanced $1.3 billion in project debt with a term loan, achieving a lower effective interest rate and with flexible covenants that align well with our bond debt. In summary, we made solid progress on our relentless march toward becoming the premier independent power company in the country."

SUMMARY OF FINANCIAL PERFORMANCE

First Quarter Results

Adjusted EBITDA for the first quarter of 2011 was $303 million compared to $282 million in the first quarter of 2010. The increase was primarily due to a $59 million improvement in Commodity Margin, to $489 million in the first quarter of 2011 from $430 million in the first quarter of 2010. The Commodity Margin increase was due in large part to our North and West segments, which increased by $83 million and $20 million, respectively. Commodity Margin in the North was favorably impacted by the acquisition of our Mid-Atlantic fleet, which closed on July 1, 2010, as well as by strong performance from our legacy plants in the region, which benefited from higher realized spark spreads. The West segment benefited from higher average hedge prices, favorable origination activities and higher renewable energy credit (REC) revenue from new contracts associated with our Geysers power plants. These increases were offset, in part, by a $40 million decrease in Commodity Margin from our Texas segment. Despite higher average hedge prices year-over-year, Commodity Margin in Texas declined primarily as a result of unplanned outages during an extreme cold weather event in early February 2011, as well as lower market heat rates associated with milder weather over the balance of the first quarter of 2011. In addition, Commodity Margin in our Texas segment was impacted by the sale of a 25% undivided interest in our Freestone Energy Center, which closed in December 2010.

Offsetting the year-over-year increase in Commodity Margin, Adjusted EBITDA was negatively impacted by a $21 million decrease in Adjusted EBITDA from discontinued operations associated with the sale of our Colorado plants in December 2010. In addition, although plant operating expense3 increased by $15 million year-over-year, this increase was driven by the addition of our Mid-Atlantic plants in July 2010; consistent with our focus on efficiencies, plant operating expense3 for our legacy fleet was down slightly year-over-year. Sales, general and administrative expense4 remained comparable year-over-year, with the exception of a $10 million credit related to the reversal of a bad debt allowance in the first quarter of 2010 that did not recur in the current period.

Net Loss2 was $297 million for the three months ended March 31, 2011, compared to a Net Loss2 of $47 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted, improved from $153 million in the first quarter of 2010 to $110 million in the first quarter of 2011. The improvement was primarily attributable to an increase in Commodity Margin, offset by increases in plant operating expense and sales, general and administrative expenses, as previously discussed. In addition, income tax expense decreased by $18 million in the first quarter of 2011 compared to the prior year period, after excluding the impact of a $76 million federal deferred income tax benefit recorded in the first quarter of 2011 associated with our election to consolidate our CCFC subsidiary for tax reporting purposes. This decrease is primarily the result of tax benefits from lower non-cash intraperiod tax allocations, partially offset by an increase in various state and foreign jurisdiction income tax expense.

1Includes generation from unconsolidated power plants and plants owned but not operated by Calpine.

2Reported as net loss attributable to Calpine on our Consolidated Condensed Statements of Operations.

3Increase in plant operating expense excludes changes in major maintenance expense, stock-based compensation expense, non-cash loss on disposition of assets and acquisition-related costs. See the table titled "Consolidated Adjusted EBITDA Reconciliation" for the actual amounts of these items for the three months ended March 31, 2011 and 2010.

4Increase in sales, general and administrative expense excludes changes in stock-based compensation and acquisition-related costs. See the table titled "Consolidated Adjusted EBITDA Reconciliation" for the actual amounts of these items for the three months ended March 31, 2011 and 2010.

Table 1: Summarized Consolidated Condensed Statements of Operations

(Unaudited)
Three Months Ended March 31,
2011 2010
(in millions)
Operating revenues $ 1,499 $ 1,514
Operating expenses 1,490 1,371
(Income) from unconsolidated investments in power plants (9 ) (7 )
Income from operations 18 150
Net interest expense, (gain) loss on interest rate derivatives, debt extinguishment costs, and other (income) expense 397 195
Loss before income taxes and discontinued operations (379 ) (45 )
Income tax expense (benefit) (83 ) 11
Loss before discontinued operations (296 ) (56 )
Discontinued operations, net of tax expense -- 8
Net loss (296 ) (48 )
Net (income) loss attributable to the noncontrolling interest (1 ) 1
Net loss attributable to Calpine $ (297 ) $ (47 )
Discontinued operations, net of tax expense -- (8 )
Debt extinguishment costs(1) 93 --
Unrealized MtM (gains) losses on derivatives(1)(2) 127 (109 )
Other items(1) (3) (33 ) 11
Net Loss, As Adjusted(4) $ (110 ) $ (153 )

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

(2) 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.

(3) Other items include $43 million and $11 million of realized mark-to-market losses associated with the settlement of non-hedged interest rate swaps for the three months ended March 31, 2011 and 2010, respectively. Other items for the three months ended March 31, 2011 also include a $(76) million federal deferred income tax benefit associated with our election to consolidate our CCFC subsidiary for tax reporting purposes.

(4) See "Regulation G Reconciliations" for further discussion of Net Loss, As Adjusted.

REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin by Segment (in millions)

(Unaudited)

Three Months Ended March 31,

2011 2010
West $ 233 $ 213
Texas 67 107
North 135 52
Southeast 54 58
Total $ 489 $ 430

West: Commodity Margin in our West segment increased by $20 million for the three months ended March 31, 2011, compared to the same period in 2010, primarily resulting from higher average hedge prices on a higher hedged position, the positive impact on the current quarter of origination activities and an increase of $10 million related to higher REC revenue from new contracts associated with our Geysers Assets. The increase was partially offset by lower market heat rates on our open position, which resulted from an increase in hydroelectric generation in California in the first quarter of 2011 compared to the same period in 2010.

Texas: Commodity Margin in our Texas segment decreased by $40 million for the three months ended March 31, 2011, compared to the same period in 2010. Despite an increase in average hedge prices, Commodity Margin was negatively impacted by unplanned outages at some of our power plants caused by an extreme cold weather event, which occurred on February 2, 2011. Market heat rates and corresponding spark spreads increased dramatically as a result of the cold weather event and the plant outages, which required us to purchase physical replacement power at prices substantially above our hedged prices. Lower unit availability influenced by higher scheduled outages, as well as the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010, also contributed to the period over period decrease in Commodity Margin.

North: Commodity Margin in our North segment increased by $83 million for the three months ended March 31, 2011, compared to the same period in 2010, primarily due to the acquisition of our Mid-Atlantic fleet, which closed on July 1, 2010. The increase in Commodity Margin also resulted from higher realized spark spreads on open positions among our legacy power plants driven by an increase in market heat rates and higher average hedge prices for the three months ended March 31, 2011, compared to the three months ended March 31, 2010.

Southeast: Commodity Margin in our Southeast segment decreased by $4 million for the three months ended March 31, 2011, compared to the same period in 2010 largely due to the expiration of certain hedge contracts, which benefited the first quarter of 2010.

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Corporate Liquidity

(Unaudited)
March 31, December 31,
2011 2010
(in millions)
Cash and cash equivalents, corporate(1) $ 985 $ 1,058
Cash and cash equivalents, non-corporate 295 269
Total cash and cash equivalents 1,280 1,327
Restricted cash 196 248

Revolving facility(ies) availability(2)

567 623
Letter of credit availability(3) 5 35
Total current liquidity availability $ 2,048 $ 2,233

(1) Includes $23 million and $6 million of margin deposits held by us posted by our counterparties as of March 31, 2011, and December 31, 2010, respectively.

(2) On December 10, 2010, we executed our $1.0 billion Corporate Revolving Facility, which replaced our $1.0 billion revolver under our First Lien Credit Facility. At December 31, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced by letters of credit issued by the Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by Deutsche Bank AG New York Branch. Our letters of credit under our Corporate Revolving Facility as of December 31, 2010, include those that were back-stopped of approximately $83 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011. The balance as of December 31, 2010 includes availability under the NDH Project Debt, which was retired on March 9, 2011.

(3) Includes availability under Calpine Development Holdings, Inc.

Liquidity remained strong at over $2 billion as of March 31, 2011, despite a decrease in availability under our revolving credit facilities that was primarily driven by the retirement of our NDH Project Debt during the first quarter of 2011. Operating activities resulted in net cash proceeds of $149 million during the 2011 period, compared to $281 million in the first quarter of 2010. The year-over-year decrease was primarily due to a $104 million increase in working capital employed (net of adjustments for debt-related balances) related to a decrease in the reductions in margin requirements in the current quarter as compared to the prior period; a $12 million increase in cash paid for interest, largely due to interest payments made on our NDH debt; and a $13 million prepayment premium paid in the first quarter of 2011 on the refinancing of the NDH debt; offset in part by a $35 million increase in income from operations, adjusted for non-cash items. Meanwhile, cash flows from investing activities resulted in a net outflow of $138 million in the first quarter of 2011, driven largely by capital expenditures, including our growth projects at Russell City, Los Esteros and York Energy Centers and our turbine upgrade program. Cash flows from financing activities resulted in a net outflow of $58 million, primarily as a result of scheduled debt payments and the net impact of refinancing activities.

During the first quarter of 2011, we completed the refinancing of our First Lien Credit Facility through the issuance of $1.2 billion in First Lien Notes. This transaction enabled us to retire our legacy credit facility and significantly enhance our strategic and financial flexibility. In addition, we refinanced the project-level debt associated with the acquisition of our Mid-Atlantic fleet, reducing our cost of debt and simplifying our capital structure through the issuance of a $1.3 billion Term Loan at the parent level.

Adjusted Recurring Free Cash Flow was $(21) million for the first quarter of 2011, compared to $(13) million for the prior year first quarter. Despite a $21 million increase in Adjusted EBITDA, Adjusted Recurring Free Cash Flow declined primarily as a result of a $21 million increase in major maintenance expense and capital expenditures resulting from our plant outage schedule and a $5 million increase in interest expense primarily related to the addition of debt associated with our Mid-Atlantic acquisition in July 2010.

PLANT DEVELOPMENT

York Energy Center: We acquired the York Energy Center, a 565 MW dual-fuel, combined-cycle power plant under construction, as part of our acquisition of our Mid-Atlantic fleet. York Energy Center achieved commercial operations for natural gas-fired generation on March 2, 2011, three months early and under budget. (Achievement of commercial operations for oil-fired generation is expected in the second quarter of 2011.) The York Energy Center currently sells power on a merchant basis but will sell power under a six-year PPA with a third party beginning in June 2011.

Russell City Energy Center: The Russell City Energy Center is under construction and continues to move forward with expected commencement of commercial operations in 2013. Upon completion, this project will bring on line approximately 429 MW of net interest baseload capacity (464 MW with peaking capacity) representing our expected share. We are in possession of all required approvals and permits, and we are in the process of obtaining project financing. Upon completion, the Russell City Energy Center is contracted to deliver its full output to PG&E under a ten-year PPA.

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, which will also increase the efficiency and environmental performance of the power plant by lowering the heat rate. The PPA and related agreements with PG&E have received all of the necessary approvals and licenses, which are now effective. The California Energy Commission has renewed our license and emission limits, which is final. The Bay Area Air Quality Management District has issued its renewal of the Authority to Construct. Appeals are undergoing review. We have executed contracts for all major equipment and have selected and contracted the engineering, procurement and construction contractor. We expect COD during the second quarter of 2013.

Turbine Upgrades: We continue to move forward with our turbine upgrade program. Through March 2011, we have completed the upgrade of seven Siemens turbines and two GE turbines, including a total of three upgrades performed during the first quarter of 2011, and have agreed to upgrade approximately 12 additional Siemens and GE turbines (and may upgrade additional turbines in the future). Our turbine upgrade program is expected to increase our generation capacity in total by approximately 275 MW. This upgrade program began in the fourth quarter of 2009 and is scheduled through 2014. The upgraded turbines have been operating with heat rates falling in line with expectations.

Geysers Assets Expansion: We continue to look to expand our production from our Geysers assets. Beginning in the fourth quarter of 2009, we conducted an exploratory drilling program, which effectively proved the commercial viability of the steam field in the northern part of our Geysers assets; however, permitting challenges have emerged that we are continuing to resolve. We were planning to target a 2013 COD for an expansion of our Geysers assets and had been, in parallel, negotiating commercial arrangements to support that, but the permitting challenges have increased the risk that we will not meet a 2013 COD. We continue to believe our northern Geysers assets have potential for development. In the near term, we will connect the test wells to our existing power plants to capture incremental production from those wells, while continuing with the permitting process, baseline engineering work and sales efforts for an expansion.

OPERATIONS UPDATE

First Quarter 2011 Power Operations Achievements:

  • Safety Performance: Maintained top-quartile safety performance with first quarter 2011 lost-time incident rate of 0.40
  • Availability Performance:
    • Achieved 2.4% fleet-wide forced outage factor
    • Delivered first quarter fleet-wide starting reliability of nearly 98%
    • Maintained strong first quarter geothermal availability factor of nearly 99%
  • Natural Gas-Fired Generation: Achieved commercial operation at York Energy Center, a 565 MW combined-cycle power plant in eastern Pennsylvania
  • Geothermal Generation: Provided approximately 1.5 million MWh of renewable baseload generation with 95% capacity factor and 0.30% forced outage factor in the first quarter 2011

First Quarter 2011 Commercial Operations Achievements:

  • Customer-oriented Growth:
    • Finalized terms of a ten-year contract for one of our power plants in the Southeast, subject to the approval of our customer's Board of Directors
    • Completed several seasonal originated contracts in the Southeast
  • Launched marketing process for Broad River and Mankato power plants
  • Secured strategic development site in Delaware, providing opportunity for growth

FINANCIAL OUTLOOK

Table 4: Adjusted EBITDA and Adjusted Recurring Free Cash Flow Guidance

Full Year 2011
(in millions)
Adjusted EBITDA $ 1,700 - 1,800
Less:
Operating lease payments 30
Major maintenance expense and capital expenditures(1) 390
Recurring cash interest, net 825
Cash taxes 15
Adjusted Recurring Free Cash Flow $ 440 - 540
Non-recurring interest rate swap payments(2) 165

(1) Includes projected Major Maintenance Expense of $235 million and maintenance Capital Expenditures of $155 million. Capital Expenditures exclude major construction and development projects.

(2) Interest payments related to legacy LIBOR hedges associated with floating rate First Lien Credit Facility, which has been refinanced.

We are reaffirming our guidance for 2011. Given the significant seasonality of our business, which is weighted toward the summer, it remains our practice not to update our guidance until we release our second quarter financial results.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results for the first quarter of 2011 on Friday, April 29, 2011, at 9 a.m. ET / 8 a.m. CT. A listen-only webcast of the call may be accessed through our website at http://www.calpine.com/, or by dialing 800-967-7187 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 8085815. Presentation materials to accompany the conference call will be made available on our website on April 29, 2011.

ANNUAL MEETING DATE

Calpine's Annual Meeting of Shareholders will be held on Wednesday, May 11, 2011, at 10 a.m. CT in Houston, Texas, at the Magnolia Hotel, 1100 Texas Ave, 77002. Shareholders as of March 14, 2011, will be eligible to vote at this year's meeting.

ABOUT CALPINE

Founded in 1984, Calpine Corporation is a major U.S. power company, currently capable of delivering approximately 28,000 megawatts of clean, cost-effective, reliable and fuel-efficient power from its 92 operating plants to customers and communities in 20 U.S. 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 http://www.calpine.com/ for more information.

Calpine's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 has been filed with the Securities and Exchange Commission (SEC) and may be found on the SEC's website at http://www.sec.gov/.

FORWARD-LOOKING INFORMATION

In addition to historical information, this release contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this report, including without limitation, "Management's Discussion and Analysis." 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:

  • 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;
  • 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 climate change, GHG emissions and derivative transactions;
  • The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated under it;
  • Our ability to manage our liquidity needs and to comply with covenants under our First Lien Notes, Corporate Revolving Facility, Term Loan, CCFC Notes and other existing financing obligations;
  • Risks associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies;
  • Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, 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;
  • Competition, including risks associated with marketing and selling power in the evolving energy markets;
  • The expiration or termination of our Power Purchase Agreements and the related results on revenues;
  • Future capacity revenues may not occur at expected levels;
  • 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 and our corporate headquarters;
  • Disruptions in or limitations on the transportation of natural gas, fuel oil and transmission of power;
  • Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions;
  • Our ability to attract, motivate and retain key employees;
  • Present and possible future claims, litigation and enforcement actions; 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 Annual Report on Form 10-K for the year ended December 31, 2010.

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 the date hereof. 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 March 31,
2011 2010
(in millions, except share and

per share amounts)

Operating revenues $ 1,499 $ 1,514
Operating expenses:
Fuel and purchased energy expense 1,069 969
Plant operating expense 238 218
Depreciation and amortization expense 131 136
Sales, general and other administrative expense 32 22
Other operating expense 20 26
Total operating expenses 1,490 1,371
(Income) from unconsolidated investments in power plants (9 ) (7 )
Income from operations 18 150
Interest expense 191 181
(Gain) loss on interest rate derivatives, net 109 11
Interest (income) (3 ) (2 )
Debt extinguishment costs 93 --
Other (income) expense, net 7 5
Loss before income taxes and discontinued operations (379 ) (45 )
Income tax expense (benefit) (83 ) 11
Loss before discontinued operations (296 ) (56 )
Discontinued operations, net of tax expense -- 8
Net loss (296 ) (48 )
Net (income) loss attributable to the noncontrolling interest (1 ) 1
Net loss attributable to Calpine $ (297 ) $ (47 )
Basic and diluted loss per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 486,191 485,921
Loss before discontinued operations attributable to Calpine (0.61 ) (0.11 )
Discontinued operations, net of tax expense, attributable to Calpine -- 0.01
Net loss per common share attributable to Calpine - basic and diluted $ (0.61 ) $ (0.10 )

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

March 31, December 31,
2011 2010

(in millions, except
share and per share amounts)

ASSETS
Current assets:
Cash and cash equivalents $ 1,280 $ 1,327
Accounts receivable, net of allowance of $2 and $2 555 669
Margin deposits and other prepaid expense 187 221
Restricted cash, current 148 195
Derivative assets, current 649 725
Inventory and other current assets 267 292
Total current assets 3,086 3,429
Property, plant and equipment, net 12,965 12,978
Restricted cash, net of current portion 48 53
Investments 98 80
Long-term derivative assets 135 170
Other assets 517 546
Total assets $ 16,849 $ 17,256
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 448 $ 514
Accrued interest payable 158 132
Debt, current portion 227 152
Derivative liabilities, current 716 718
Other current liabilities 301 273
Total current liabilities 1,850 1,789
Debt, net of current portion 10,023 10,104
Deferred income taxes, net of current 1 77
Long-term derivative liabilities 275 370
Other long-term liabilities 242 247
Total liabilities 12,391 12,587
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; 446,415,081 and 444,883,356 shares issued, respectively, and 445,843,601 and 444,435,198 shares outstanding, respectively 1 1
Treasury stock, at cost, 571,480 and 448,158 shares, respectively (6 ) (5 )
Additional paid-in capital 12,286 12,281
Accumulated deficit (7,806 ) (7,509 )
Accumulated other comprehensive loss (52 ) (125 )
Total Calpine stockholders' equity 4,423 4,643
Noncontrolling interest 35 26
Total stockholders' equity 4,458 4,669
Total liabilities and stockholders' equity $ 16,849 $ 17,256

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

Three Months Ended March 31,
2011 2010
(in millions)
Cash flows from operating activities:
Net loss $ (296 ) $ (48 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization expense(1) 140

158
Debt extinguishment costs 80 --
Deferred income taxes (110 ) 14
Loss on disposal of assets 5 9
Unrealized mark-to-market activity, net 127 (109 )
Income from unconsolidated investments in power plants (9 ) (7 )
Stock-based compensation expense 5 6
Other 3 3
Change in operating assets and liabilities:
Accounts receivable 116 161
Derivative instruments, net (13 ) (37 )
Other assets 65 228
Accounts payable and accrued expenses (11 ) (103 )
Liabilities related to non-hedging interest rate swaps 43 11
Other liabilities 4 (5 )
Net cash provided by operating activities 149 281
Cash flows from investing activities:
Purchases of property, plant and equipment (144 ) (66 )
Cash acquired due to consolidation of Otay Mesa Energy Center -- 8
Purchases of deferred transmission credits (3 ) --
Decrease in restricted cash 52 212
Settlement of non-hedging interest rate swaps (43 ) (11

)

Net cash provided by (used in) investing activities (138 ) 143
Cash flows from financing activities:
Repayments of project financing, notes payable and other

(64 )

(259 )
Repayments on NDH Project Debt (1,283 ) --
Borrowings under Term Loan 1,300 --
Issuance of First Lien Notes 1,200 --
Repayments on First Lien Credit Facility (1,184 ) (36 )
Capital contributions from noncontrolling interest holder 8 --
Financing costs (34 ) --
Other (1 ) (1 )
Net cash used in financing activities (58 ) (296 )
Net increase (decrease) in cash and cash equivalents (47 ) 128
Cash and cash equivalents, beginning of period 1,327 989
Cash and cash equivalents, end of period $ 1,280 $ 1,117
Cash paid during the period for:
Interest, net of amounts capitalized $ 156 $ 144
Income taxes $ 6 $ 3

(1) Includes depreciation and amortization that is also recorded in fuel and purchased energy expense, interest expense and discontinued operations on our Consolidated Condensed Statements of Operations.

REGULATION G RECONCILIATIONS

Net Loss, As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Recurring 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 U.S. GAAP measures of performance.

Net Loss, As Adjusted, represents net income (loss) attributable to Calpine, adjusted for certain non-cash and non-recurring items as previously detailed in Table 1, including discontinued operations, net of tax expense, debt extinguishment costs, gain on sale of assets, net, impairment losses, unrealized mark-to-market (gains) losses on derivatives, and other adjustments. Net Loss, As Adjusted, is presented because we believe it is a useful tool for assessing the operating performance of our company in the current period. Net Loss, As Adjusted, is not intended to represent net income (loss), the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

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 income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

Adjusted EBITDA represents earnings 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 U.S. GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with U.S. GAAP. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

Adjusted Recurring 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 Recurring Free Cash Flow is presented because our management uses this measure, among others, to make decisions about capital allocation. Adjusted Recurring Free Cash Flow is not intended to represent cash flows from operations as defined by U.S. 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 tables reconcile our Commodity Margin to its U.S. GAAP results for the three months ended March 31, 2011 and 2010 (in millions):

Three Months Ended March 31, 2011
Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin $ 233 $ 67 $ 135 $ 54 $ -- $ 489

Add: Mark-to-market commodity activity, net and
other revenue(1)

5 (60 ) 4 (4 ) (6 ) (61)
Less:
Plant operating expense 87 80 45 33 (7 ) 238
Depreciation and amortization expense 46 30 33 23 (1 ) 131
Sales, general and other administrative expense 11 10 6 5 -- 32
Other operating expense(2) 8 -- 7 1 2 18
(Income) from unconsolidated investments in power plants -- -- (9 ) -- -- (9)
Income (loss) from operations $ 86 $ (113 ) $ 57 $ (12 ) $ -- $ 18

Three Months Ended March 31, 2010
Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin $ 213 $ 107 $ 52 $ 58 $ -- $ 430

Add: Mark-to-market commodity activity, net and
other revenue(1)

8 96 (3 ) 22 (8 ) 115
Less:

Plant operating expense

90 84 22 28 (6 ) 218
Depreciation and amortization expense 53 36 20 29 (2 ) 136
Sales, general and other administrative expense 15 -- 3 4 -- 22
Other operating expense(2) 17 7 8 3 (9 ) 26
(Income) from unconsolidated investments in power plants -- -- (7 ) -- -- (7)
Income from operations $ 46 $ 76 $ 3 $ 16 $ 9 $ 150

(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.

(2) Excludes $2 million and nil of RGGI compliance costs and other environmental costs for the three months ended March 31, 2011 and 2010, 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 Recurring Free Cash Flow to our net loss attributable to Calpine for the three months ended March 31, 2011 and 2010, as reported under U.S. GAAP.

(Unaudited)
Three Months Ended March 31,
2011 2010
(in millions)
Net loss attributable to Calpine $ (297 ) $ (47 )
Net income (loss) attributable to noncontrolling interest 1 (1 )
Discontinued operations, net of tax expense -- (8 )
Income tax expense (benefit) (83 ) 11
Other (income) expense and debt extinguishment costs, net 100 5
(Gain) loss on interest rate derivatives, net 109 11
Interest expense, net 188 179
Income from operations 18 150
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1) 132 137
Major maintenance expense 60 55
Operating lease expense 8 11
Unrealized (gain) losses on commodity derivative mark-to-market activity 65 (112 )
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2) 8 7
Stock-based compensation expense 5 6
Non-cash loss on dispositions of assets 5 6
Other 2 1
Adjusted EBITDA from continuing operations 303 261
Adjusted EBITDA from discontinued operations -- 21
Total Adjusted EBITDA $ 303 $ 282
Less:
Lease payments 8 11
Major maintenance expense and capital expenditures(3) 111 91
Cash interest(4) 198 192
Cash taxes 4 2
Other 3 (1 )
Adjusted Recurring Free Cash Flow(5) $ (21 ) $ (13 )

(1)Depreciation and amortization expense in the income from operations calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets.


(2)Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized gains (losses) on mark-to-market activity of nil for both the three months ended March 31, 2011 and 2010.


(3)Includes $61 million and $58 million in major maintenance expense for the three months ended March 31, 2011 and 2010, respectively, and $50 million and $33 million in maintenance capital expenditures for the three months ended March 31, 2011 and 2010, respectively.


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


(5)Excludes decrease in working capital of $100 million and $60 million for the three months ended March 31, 2011 and 2010. Adjusted Recurring Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance.


In the following table, we have reconciled our Adjusted EBITDA to our Commodity Margin, both of which are non-GAAP measures, for the three months ended March 31, 2011 and 2010. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above.

(Unaudited)
Three Months Ended March 31,
2011 2010
(in millions)
Commodity Margin $ 489 $ 430
Other revenue 4 3
Plant operating expense(1) (170 ) (155 )
Sales, general and administrative expense(2) (28 ) (19 )
Other operating expense(3) (9 ) (13 )
Adjusted EBITDA from unconsolidated investments in power plants(4) 17 14
Adjusted EBITDA from discontinued operations(5) -- 21
Other -- 1
Adjusted EBITDA $ 303 $ 282

(1)Shown net of major maintenance expense, stock-based compensation expense, non-cash loss on dispositions of assets and acquisition-related costs.


(2)Shown net of stock-based compensation expense and acquisition-related costs.


(3)Excludes $2 million and nil of RGGI compliance and other environmental costs for the three months ended March 31, 2011 and 2010, respectively, which are components of Commodity Margin.


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


(5)Represents Adjusted EBITDA from Blue Spruce and Rocky Mountain power plants, which were sold in December 2010.


Adjusted EBITDA and Adjusted Recurring Free Cash Flow Reconciliation for Guidance

Full Year 2011 Range: Low High
(in millions)
GAAP Net Income (Loss) $ (25 ) $ 75
Plus:
Interest expense, net of interest income 820 820
Depreciation and amortization expense 560 560
Major maintenance expense 230 230
Operating lease expense 35 35
Other(1) 80 80

Adjusted EBITDA

$ 1,700 $ 1,800
Less:
Operating lease payments 30 30
Major maintenance expense and maintenance capital expenditures(2) 390 390
Recurring cash interest, net(3) 825 825
Cash taxes 15 15
Adjusted Recurring Free Cash Flow $ 440 $ 540
Non-recurring interest rate swap payments(4) 165 165

(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 $235 million and maintenance capital expenditures of $155 million. Capital expenditures exclude major construction and development projects.

(3) Includes fees for letters of credit, net of interest income.

(4) Interest payments related to legacy LIBOR hedges associated with floating rate First Lien Credit Facility, which has been refinanced.

CASH FLOW ACTIVITIES

The following table summarizes our cash flow activities for the three months ended March 31, 2011 and 2010:

(Unaudited)
Three Months Ended March 31,
2011 2010
(in millions)
Beginning cash and cash equivalents $ 1,327 $ 989
Net cash provided by (used in):
Operating activities 149 281
Investing activities (138 ) 143
Financing activities (58 ) (296 )
Net increase (decrease) in cash and cash equivalents (47 ) 128
Ending cash and cash equivalents $ 1,280 $ 1,117

OPERATING PERFORMANCE METRICS

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

Three Months Ended March 31,
2011 2010
Total MWh generated (in thousands)(1) 18,127 20,357
West 6,195 9,216
Texas 5,319 6,642
North 2,328 1,074
Southeast 4,285 3,425
Average availability 88.9% 90.3%
West 91.9% 93.2%
Texas 79.6% 82.7%
North 91.1% 92.2%
Southeast 94.4% 95.7%
Average capacity factor, excluding peakers 36.9% 46.0%
West 46.3% 68.1%
Texas 35.4% 43.0%
North 24.1% 26.1%
Southeast 38.1% 30.3%
Steam adjusted Heat Rate 7,369 7,229
West 7,386 7,266
Texas 7,253 7,104
North 7,746 7,570
Southeast 7,298 7,288

(1) Excludes generation from unconsolidated power plants, plants owned but not operated and discontinued operations.

SOURCE: Calpine Corporation

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