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Calpine Reports First Quarter 2012 Results,
Raises 2012 Guidance

04/27/2012

Summary of First Quarter 2012 Financial Results (in millions):

Three Months Ended March 31,
2012 2011 % Change
Operating Revenues $ 1,236 $ 1,499

(17.5

)

%

Commodity Margin $ 517 $ 489 5.7 %
Adjusted EBITDA $ 325 $ 303 7.3 %
Adjusted Recurring Free Cash Flow $ (27 ) $ (21 )
Net Loss1 $ (9 ) $ (297 )
Net Loss, As Adjusted2 $ (65 ) $ (110 )

Raising 2012 Full Year Guidance:

Prior Guidance
(as of February 2012) Current Guidance
(in millions)
Adjusted EBITDA $1,600 - 1,725 $1,675 - 1,800
Adjusted Recurring Free Cash Flow $425 - 550 $470 - 595

Recent Achievements:

  • Operations:
    -- Generated 29 million MWh3 of electricity in the first quarter of 2012, a 52% increase compared to the first quarter of 2011
    -- Delivered lowest first quarter fleetwide forced outage factor on record: 1.1%
    -- Produced highest first quarter fleetwide starting reliability on record: 98%
    -- Achieved first quarter on record without a lost-time incident
  • Commercial:
    -- Entered into 20-year PPA for 160 MW - 280 MW of power from our Oneta Energy Center
    -- Advancing more than 800 MW of CCGT development opportunities in ERCOT and PJM
  • Capital Structure:
    -- Doubled size of share repurchase program to $600 million
    -- Terminated legacy interest rate swaps

HOUSTON, Apr 27, 2012 (BUSINESS WIRE) --Calpine Corporation (NYSE:CPN) today reported first quarter 2012 Adjusted EBITDA of $325 million, compared to $303 million in the prior year period, and Adjusted Recurring Free Cash Flow of $(27) million, compared to $(21) million in the prior year period. Net Loss1 for the first quarter narrowed to $9 million, or $0.02 per diluted share, compared to $297 million, or $0.61 per diluted share, in the prior year period. Net Loss, As Adjusted2, for the first quarter of 2012 was $65 million compared to $110 million in the prior year period. The narrowing of Net Loss, As Adjusted2, was primarily related to higher Commodity Margin driven largely by increased generation resulting from lower natural gas prices.

"Calpine's power generation fleet achieved record-breaking performance in the first quarter of 2012, producing 29 million MWh of power - 52% more than the prior year," said Jack Fusco, Calpine's President and Chief Executive Officer. "In short, despite unusually mild winter weather dampening overall market demand for power, the impact of coal-to-gas switching in the Texas, Mid-Atlantic and Southeast markets meaningfully increased demand for power production from our natural gas-fired units. In the face of this increased demand, our plant personnel were able to execute exceptionally well, as exemplified by 98% starting reliability with only a 1% forced outage factor and no lost-time incidents while holding plant operating expenses flat.

"As a result of this solid operating performance and despite tighter power prices resulting from the milder weather and market dynamics, we delivered improved financial results with Commodity Margin up 6% and Adjusted EBITDA up 7% versus first quarter 2011. Based on this performance and our favorable outlook for the balance of the year, we are raising our full-year guidance for Adjusted EBITDA to $1,675 million to $1,800 million and for Adjusted Free Cash Flow to $470 million to $595 million," said Fusco.

"We expect the secular shift toward greater utilization of combined-cycle gas technology and the tightening of supply/demand dynamics in key power markets to continue. These trends, supported by continued strong operating and commercial execution, should lead to volume and margin expansion for Calpine for the balance of this year and beyond," concluded Fusco.

"We continue to focus on enhancing shareholder value through effective capital allocation," added Zamir Rauf, Calpine's Chief Financial Officer. "During the first quarter, we updated our capital allocation outlook given the low natural gas price environment. Based on the increased clarity and favorable outlook we now have for the balance of 2012 and beyond, we are pursuing several strategies. We are advancing more than 800 MW of disciplined growth projects, requiring almost $550 million in investments over the next three years. In addition, our Riverside facility sale remains on target and we continue to seek opportunities to monetize the value of our Southeast fleet through long-term contracts or asset divestitures. Finally, we are increasing our share repurchase program by $300 million, bringing the total program size to $600 million. Going forward, as a normal course of capital allocation decision-making, this may evolve into a continuous share repurchase program in which we may not announce incremental share repurchase targets, but we would provide quarterly updates on our progress."

SUMMARY OF FINANCIAL PERFORMANCE

First Quarter Results

Adjusted EBITDA for the first quarter of 2012 was $325 million compared to $303 million in the prior year period. The period-over-period increase in Adjusted EBITDA was primarily due to a $28 million increase in Commodity Margin, partially offset by modest increases in sales, general and administrative expenses and other operating expense4. The increase in Commodity Margin was primarily due to:

+ higher generation volumes driven by a low natural gas price environment and
+ an extreme cold weather event in Texas in February 2011 that resulted in unplanned outages, causing us to purchase power at prices substantially above our hedge prices, which did not recur in the first quarter of 2012, partially offset by
- lower regulatory capacity prices and the expiration of contracts subsequent to the first quarter of 2011 and
- lower super-peak prices in Texas and the North due to milder weather conditions during the first quarter of 2012 compared to the prior year period.

Net Loss1 declined to $9 million for the first quarter of 2012, compared to $297 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted, was $65 million in the first quarter of 2012 compared to $110 million in the prior year period. The period-over-period reduction in Net Loss, As Adjusted, was driven largely by:

+ higher Commodity Margin, as previously discussed, and
+ lower major maintenance expense resulting from our plant outage schedule, offset in part by
- an increase in depreciation and amortization expense due to a revision in the expected settlement dates of asset retirement obligations that benefited the first quarter of 2011 and did not recur in the first quarter of 2012.

____________

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

2 Refer to Table 1 for further detail of Net Loss, As Adjusted.

3 Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants.

4 Increase in sales, general and administrative expense and other operating expense excludes changes in stock-based compensation expense, amortization and other items. See the table titled "Consolidated Adjusted EBITDA Reconciliation" for the actual amounts of these items for the three months ended March 31, 2012 and 2011.

Table 1: Net Loss, As Adjusted

(Unaudited)
Three Months Ended March 31,
2012 2011
(in millions)
Net loss attributable to Calpine $ (9 ) $ (297 )
Debt extinguishment costs(1) 12 93
Unrealized MtM (gain) loss on derivatives(1) (2) (224 ) 127
Other items(1) (3) 156 (33 )
Net Loss, As Adjusted(4) $ (65 ) $ (110 )

__________

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

(2) Represents unrealized mark-to-market (MtM) (gain) loss 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 realized mark-to-market losses associated with the settlement of non-hedged interest rate swaps totaling $156 million and $43 million for the three months ended March 31, 2012 and 2011, 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)

Three Months Ended March 31,
2012 2011 Variance
West $ 208 $ 233 (25 )
Texas 109 67 42
North 144 135 9
Southeast 56 54 2
Total $ 517 $ 489 28

West Region

First Quarter: Commodity Margin in our West segment decreased by $25 million in the first quarter of 2012 compared to the prior year period. Primary drivers included:

- lower revenue due to the expiration of regulated capacity contracts and a PPA
- lower Commodity Margin associated with our Sutter Energy Center, which did not run in the first quarter of 2012 and
- lower Commodity Margin contribution from hedges associated with our Geysers assets, which are based on absolute power price, partially offset by
+ increased generation due to lower hydroelectric generation in California, which resulted in higher spark spreads in the first quarter of 2012 compared to the prior year period.

Texas Region

First Quarter: Commodity Margin in our Texas segment increased by $42 million in the first quarter of 2012 compared to the prior year period. Primary drivers included:

+ an extreme cold weather event in Texas in February 2011 that resulted in unplanned outages, causing us to purchase power at prices substantially above our hedge prices, which did not recur in the first quarter of 2012
+ increased generation driven by lower natural gas prices and
+ higher Commodity Margin earned during overnight periods related to the must-run obligations of certain of our cogeneration power plants, partially offset by
- lower on-peak and super-peak power prices resulting from milder weather conditions during the first quarter of 2012 compared to the prior year period.

North Region

First Quarter: Commodity Margin in our North segment increased by $9 million in the first quarter of 2012 compared to the prior year period. Primary drivers included:

+ York Energy Center achieving commercial operation in March 2011
+ increased Commodity Margin from fixed-price power contracts that benefited from spark spread expansion and
+ higher generation driven by lower natural gas prices, partially offset by
- lower regulatory capacity revenues and
- lower super-peak power prices resulting from milder weather conditions during the first quarter of 2012 compared to the prior year period.

Southeast Region

First Quarter: Commodity Margin in our Southeast segment increased by $2 million in the first quarter of 2012 compared to the prior year period. Primary drivers included:

+ higher generation at power plants contracted and dispatched by third parties, largely offset by
- lower revenues resulting from the expiration of a PPA subsequent to the first quarter of 2011.

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Liquidity

(Unaudited)
March 31, December 31,
2012 2011
(in millions)
Cash and cash equivalents, corporate(1) $ 899 $ 946
Cash and cash equivalents, non-corporate 171 306
Total cash and cash equivalents 1,070 1,252
Restricted cash 171 194
Corporate Revolving Facility availability 649 560
Letter of credit availability(2) 74 7
Total current liquidity availability $ 1,964 $ 2,013

__________

(1) Includes $111 million and $34 million of margin deposits held by us posted by our counterparties at March 31, 2012 and December 31, 2011, respectively.

(2) Includes availability under our CDHI letter of credit facility. On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to January 2, 2016.

Liquidity remained strong at nearly $2.0 billion as of March 31, 2012.

Cash flows provided by operating activities for the three months ended March 31, 2012, resulted in net inflows of $71 million compared to $149 million in the prior year period. The decrease in cash provided by operating activities primarily resulted from an increase in cash paid for interest due to timing of interest payments on our bonds and term loans, as compared to the previously outstanding First Lien Credit Facility and project debt.

Cash flows used in investing activities were $314 million for the three months ended March 31, 2012, compared to $138 million in the prior year period. The activity in the first quarter of 2012 was driven largely by our termination of the legacy interest rate swaps and by an increase in capital expenditures associated with construction activity at our Russell City Energy Center and Los Esteros Critical Energy Facility along with our turbine upgrade program.

Cash flows provided by financing activities were $61 million for the three months ended March 31, 2012, and were primarily related to the receipt of proceeds from project debt related to our Russell City and Los Esteros construction projects. In addition, we incurred lower finance costs and lower repayments on project debt due in part to the refinancing activities we completed in the first quarter of 2011.

Adjusted Recurring Free Cash Flow was $(27) million for the first quarter of 2012, compared to $(21) million for the prior year period. Despite a $22 million increase in Adjusted EBITDA during the period, Adjusted Recurring Free Cash Flow declined primarily due to a $35 million increase in maintenance capital expenditures related to our plant outage schedule.

SHARE REPURCHASE PROGRAM

On August 23, 2011, we announced that our Board of Directors had authorized the repurchase of up to $300 million in shares of our common stock. In April 2012, our Board of Directors authorized us to double the size of our share repurchase program, increasing our permitted cumulative repurchases to $600 million in shares of our common stock. The announced share repurchase program did not specify an expiration date. The repurchases may be commenced or suspended from time to time without prior notice. Through the filing of this release, a total of 8,524,576 shares of our outstanding common stock have been repurchased under this program for approximately $124 million at an average price of $14.60 per share. The shares repurchased as of the date of this release were purchased in open market transactions.

PLANT DEVELOPMENT

West:

Russell City Energy Center: The Russell City Energy Center is under construction and continues to move forward with expected COD in 2013. Upon completion, this project will bring online approximately 429 MW of net interest baseload capacity (464 MW with peaking capacity) representing our 75% share. Upon completion, the Russell City Energy Center is contracted to deliver its full output to PG&E under a 10-year PPA.

Los Esteros: 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 309 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 existing 188 MW simple-cycle facility was shut down at the end of 2011 to allow for major maintenance on the combustion turbines and installation of the new heat recovery steam generators and a steam turbine generator in connection with the new PPA. Construction is ongoing and COD is expected in the third quarter of 2013.

Texas:

Channel and Deer Park Expansions: We are actively permitting the addition of 520 MW of combined-cycle capacity at existing sites in ERCOT, based on tightening reserve margins and the potential impact of EPA regulations on generation in Texas. At both our Deer Park and Channel Energy Centers, we have the ability to install an additional combustion turbine generator and connect to the existing steam turbine generator to expand the capacity of these facilities and to improve overall plant efficiency. In September and November 2011, we filed air permit applications with the Texas Commission on Environmental Quality and the EPA to expand the Deer Park and Channel Energy Centers by approximately 260 MW each. We continue to move forward with development and permitting activities and expect COD in summer 2014 for these expansions.

North:

Garrison Energy Center: We are actively permitting 618 MW of new combined-cycle capacity at a development site secured by a lease option with the City of Dover. PJM has completed a feasibility study and a system impact study and is currently conducting a facility study for the first phase (309 MW). The feasibility study has been completed and a system impact study is ongoing for the second phase (309 MW). Environmental permitting, site development planning and development engineering are underway, and the first phase's capacity will be bid into PJM's 2015/2016 base residual auction.

All Segments:

Turbine Upgrades: We continue to move forward with our turbine upgrade program. Through March 31, 2012, we have completed the upgrade of ten Siemens and five GE turbines and have agreed to upgrade approximately six 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 more efficient heat rates consistent with expectations.

OPERATIONS UPDATE

First Quarter 2012 Power Operations Achievements:

  • Safety Performance:
    -- Achieved first quarter on record without a lost-time incident
  • Availability Performance:
    -- Delivered lowest first quarter fleetwide forced outage factor on record: 1.1%
    -- Produced highest first quarter fleetwide starting reliability on record: 98%
  • Cost Performance:
    -- Held plant operating expense5 flat year over year, despite a 52% increase in generation volume3
  • Geothermal Generation:
    -- Provided over 1.5 million MWh of renewable baseload generation with 97% capacity factor during the first quarter of 2012
  • Natural Gas-fired Generation:
    -- Increased combined-cycle capacity factor in first quarter of 2012 to 54% compared to 35% in the prior year period
    -- Westbrook and Oneta Energy Centers: 100% starting reliability and greater than 98% availability

First Quarter 2012 Commercial Operations Achievements:

  • Customer-oriented Growth:
    -- Signed 20-year PPA with Western Farmers Electric Cooperative to provide 160 MW of power and capacity from our Oneta Energy Center beginning June 2014. The capacity under contract will increase in increments, up to a maximum of 280 MW in years 2019 - 2035.

First Quarter 2012 Financial Achievements:

  • Simplifying Capital Structure:
    -- Retired legacy interest rate swaps
    -- Closed on purchase of two of the third-party equity interests in our subsidiary associated with our California peaking plants
    -- Unwound sale-leaseback financing at Agnews Power Plant

__________

5 Change in plant operating expense excludes changes in major maintenance expense, stock-based compensation expense and non-cash loss on disposition of assets. See the table titled "Consolidated Adjusted EBITDA Reconciliation" for the actual amounts of these items for the three months ended March 31, 2012 and 2011.

FINANCIAL OUTLOOK

Full Year 2012
(in millions)
Adjusted EBITDA $ 1,675 - 1,800
Less:
Operating lease payments 35
Major maintenance expense and maintenance capital expenditures(1) 350
Accelerated parts purchases to support upgrades(2) 30
Recurring cash interest, net(3) 770
Cash taxes 10
Other 10
Adjusted Recurring Free Cash Flow $ 470 - 595
Non-recurring interest rate swap payments(4) $ (156 )
Growth capital expenditures (net of debt funding)(5) $ (100 )
Riverside sale proceeds $ 392

__________

(1) Includes projected major maintenance expense of $185 million and maintenance capital expenditures of $165 million in 2012. Capital expenditures exclude major construction and development projects. 2012 figures exclude amounts to be funded by project debt.

(2) Incremental impact on 2012 maintenance capital expenditures related to acceleration of future turbine upgrades into 2012 and deferral of use of on-hand parts to post-2012 periods.

(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.

(5) Though our construction projects at Russell City and Los Esteros will continue through 2012, we met our equity contribution requirements on these projects in 2011, such that all costs incurred in 2012 and beyond will be funded from the project debt we have secured for these projects.

As detailed above, today we are raising our 2012 guidance. We now project Adjusted EBITDA of $1,675 million to $1,800 million and Adjusted Recurring Free Cash Flow of $470 million to $595 million. We also expect to invest $100 million, net of debt funding, in growth-related projects during the year. This updated projection of 2012 growth capital expenditures represents a $90 million increase to our previous guidance, which is attributable to the advancements of our Garrison Energy Center development project and the expansion of our Deer Park and Channel Energy Centers, as previously discussed. Finally, we continue to expect to receive approximately $392 million during the fourth quarter of 2012 from one of our customers related to its intended exercise of a call option to purchase our Riverside Energy Center, which was approved by the Wisconsin Public Service Commission during April 2012.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results for the first quarter of 2012 on Friday, April 27, 2012, at 10 a.m. ET / 9 a.m. CT. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing (800) 447-0521 in the United States or (847) 413-3238 outside the United States. The confirmation code is 32033908. An archived recording of the call will be made available for a limited time on our website or by dialing (888) 843-7419 in the United States or (630) 652-3042 outside the United States and providing confirmation code 32033908. Presentation materials to accompany the conference call will be available on our website on April 27, 2012.

ABOUT CALPINE

Calpine Corporation is the largest independent power producer in the U.S., with a fleet of 93 power generation plants representing more than 28,000 megawatts of generation capacity. Last year our plants generated more than 94 million megawatt hours of power for our wholesale customers in 20 states and Canada. Our 91 operating plants as well as two under construction consist primarily of natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our modern, clean, efficient and cost-effective fleet stands ready to respond to the increased need for cleaner and more affordable power as the economy recovers, as new environmental rules are implemented and force older, dirtier plants to retire or reduce generation, as variable renewable power generation from wind and solar grows and with it the need for flexible natural gas generation to assure firm supply to the grid, and finally, as natural gas becomes economically competitive with coal as a fuel for power generation. Please visit www.calpine.com to learn more about why Calpine is a generation ahead - today.

Calpine's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, 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, this release contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this release. 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, changes in U.S. macroeconomic conditions, 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 the environment and derivative transactions;
  • The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated thereunder;
  • Our ability to manage our liquidity needs and to comply with covenants under our First Lien Notes, Corporate Revolving Facility, First Lien Term Loans, CCFC Notes and other existing financing obligations;
  • Risks associated with the continued economic and financial conditions affecting certain countries in Europe including financial institutions located within those countries and their ability to fund their financial commitments;
  • 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 early termination of our PPAs and the related results on revenues;
  • Future capacity revenues may not occur at expected levels;
  • Natural disasters, such as hurricanes, earthquakes and floods, acts of terrorism or cyber attacks 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 press release and in our 2011 Form 10-K.

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 of this release. 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,
2012 2011
(in millions, except share and per share amounts)
Operating revenues $ 1,236 $ 1,499
Operating expenses:
Fuel and purchased energy expense 632 1,069
Plant operating expense 221 238
Depreciation and amortization expense 140 131
Sales, general and other administrative expense 33 32
Other operating expenses 24 20
Total operating expenses 1,050 1,490
(Income) from unconsolidated investments in power plants (9 ) (9 )
Income from operations 195 18
Interest expense 185 191
Loss on interest rate derivatives 14 109
Interest (income) (3 ) (3 )
Debt extinguishment costs 12 93
Other (income) expense, net 2 7
Loss before income taxes (15 ) (379 )
Income tax benefit (6 ) (83 )
Net loss (9 ) (296 )
Net income attributable to the noncontrolling interest -- (1 )
Net loss attributable to Calpine $ (9 ) $ (297 )
Basic and diluted loss per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 478,106 486,191
Net loss per common share attributable to Calpine - basic and diluted $ (0.02 ) $ (0.61 )
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)

March 31,

December 31,

2012

2011
(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 1,070 $ 1,252
Accounts receivable, net of allowance of $13 and $13 386 598
Margin deposits and other prepaid expense 213 193
Restricted cash, current 119 139
Derivative assets, current 1,403 1,051
Inventory and other current assets 293 329
Total current assets 3,484 3,562
Property, plant and equipment, net 13,101 13,019
Restricted cash, net of current portion 52 55
Investments 92 80
Long-term derivative assets 186 113
Other assets 541 542
Total assets $ 17,456 $ 17,371
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 334 $ 435
Accrued interest payable 156 200
Debt, current portion 103 104
Derivative liabilities, current 1,301 1,144
Other current liabilities 315 279
Total current liabilities 2,209 2,162
Debt, net of current portion 10,392 10,321
Long-term derivative liabilities 257 279
Other long-term liabilities 237 245
Total liabilities 13,095 13,007
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding -- --
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 491,935,530 and 490,468,815 shares issued, respectively, and 482,797,421 and 481,743,738 shares outstanding, respectively 1 1
Treasury stock, at cost, 9,138,109 and 8,725,077 shares, respectively (131 ) (125 )
Additional paid-in capital 12,310 12,305
Accumulated deficit (7,708 ) (7,699 )
Accumulated other comprehensive loss (173 ) (178 )
Total Calpine stockholders' equity 4,299 4,304
Noncontrolling interest 62 60
Total stockholders' equity 4,361 4,364
Total liabilities and stockholders' equity $ 17,456 $ 17,371
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended March 31,
2012 2011
(in millions)
Cash flows from operating activities:
Net loss $ (9 ) $ (296 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization expense(1) 151 140
Debt extinguishment costs -- 80
Deferred income taxes (1 ) (110 )
Loss on disposition of assets 2 5
Unrealized mark-to-market activity, net (224 ) 127
(Income) from unconsolidated investments in power plants (9 ) (9 )
Stock-based compensation expense 6 5
Other -- 3
Change in operating assets and liabilities:
Accounts receivable 211 116
Derivative instruments, net (66 ) (13 )
Other assets 20 65
Accounts payable and accrued expenses (153 ) (11 )
Settlement of non-hedging interest rate swaps 151 43
Other liabilities (8 ) 4
Net cash provided by operating activities 71 149
Cash flows from investing activities:
Purchases of property, plant and equipment (181 ) (144 )
Settlement of non-hedging interest rate swaps (151 ) (43 )
Decrease in restricted cash 23 52
Purchases of deferred transmission credits (8 ) (3 )
Other 3 --
Net cash used in investing activities $ (314 ) $ (138 )
Cash flows from financing activities:
Borrowings under First Lien Term Loans

--

1,300

Repayments on NDH Project Debt -- (1,283 )
Issuance of 2023 First Lien Notes -- 1,200
Repayments on First Lien Credit Facility -- (1,184 )
Borrowings from project financing, notes payable and other 114 --
Repayments of project financing, notes payable and other (38 ) (64 )
Capital contributions from noncontrolling interest holder -- 8
Financing costs (5 ) (34 )
Stock repurchases (6 ) --
Other (4 ) (1 )
Net cash provided by (used in) financing activities 61 (58 )
Net decrease in cash and cash equivalents (182 ) (47 )
Cash and cash equivalents, beginning of period 1,252 1,327
Cash and cash equivalents, end of period $ 1,070 $ 1,280
Cash paid during the period for:
Interest, net of amounts capitalized $ 226 $ 156
Income taxes $ 6 $ 6
Supplemental disclosure of non-cash investing activities:
Change in capital expenditures included in accounts payable $ 47 $ (2 )

__________

(1) Includes depreciation and amortization included in fuel and purchased energy expense and interest expense 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 loss attributable to Calpine, adjusted for certain non-cash and non-recurring items as previously detailed in Table 1, including debt extinguishment costs, unrealized mark-to-market (gain) loss 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 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 physical 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 including natural gas transactions hedging future power sales 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 (loss) 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 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, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and 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 table reconciles our Commodity Margin to its U.S. GAAP results for the three months ended March 31, 2012 and 2011 (in millions):

Three Months Ended March 31, 2012
Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin $ 208 $ 109 $ 144 $ 56 $ -- $ 517
Add: Mark-to-market commodity activity, net and other(1)(2) 36 34 12 10 (8 ) 84
Less:
Plant operating expense 81 68 45 33 (6 ) 221
Depreciation and amortization expense 50 35 33 23 (1 ) 140
Sales, general and other administrative expense 8 11 6 8 -- 33
Other operating expenses(3) 11 2 9 1 (2 ) 21
(Income) from unconsolidated investments in power plants -- -- (9 ) -- -- (9 )

Income from operations

$ 94 $ 27 $ 72 $ 1 $ 1 $ 195
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(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 expenses(3) 8 -- 7 1 2 18
(Income) from unconsolidated investments in power plants -- -- (9 ) -- -- (9 )
Income (loss) from operations $ 86 $ (113 ) $ 57 $ (12 ) $ -- $ 18

__________

(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 March 31, 2012 and 2011.

(2) Includes $(8) million of lease levelization and $4 million of amortization expense for the three months ended March 31, 2012, related to contracts that became effective in June and August 2011.

(3) Excludes $3 and $2 million of RGGI compliance and other environmental costs for the three months ended March 31, 2012 and 2011, respectively, which are components 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, 2012 and 2011, as reported under U.S. GAAP.

Three Months Ended March 31,
2012 2011
(in millions)
Net loss attributable to Calpine $ (9 ) $ (297 )
Net income attributable to the noncontrolling interest -- 1
Income tax benefit (6 ) (83 )
Debt extinguishment costs and other (income) expense, net 14 100
Loss on interest rate derivatives 14 109
Interest expense, net 182 188
Income from operations $ 195 $ 18
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1) 141 132
Major maintenance expense 46 60
Operating lease expense 9 8
Unrealized (gain) loss on commodity derivative mark-to-market activity (78 ) 65
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3) 7 8
Stock-based compensation expense 6 5
Loss on dispositions of assets 2 5
Acquired contract amortization 4 --
Other (7 ) 2
Total Adjusted EBITDA $ 325 $ 303
Less:
Lease payments 9 8
Major maintenance expense and capital expenditures(4) 146 111
Cash interest, net(5) 191 198
Cash taxes 4 4
Other 2 3
Adjusted Recurring Free Cash Flow(6) $ (27 ) $ (21 )

_________

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

(2) Included on 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 (gain) loss on mark-to-market activity of nil for both the three months ended March 31, 2012 and 2011.

(4) Includes $47 million and $58 million in major maintenance expense for the three months ended March 31, 2012 and 2011, respectively, and $99 million and $53 million in maintenance capital expenditures for the three months ended March 31, 2012 and 2011, respectively.

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

(6) Excludes decrease in working capital of $76 million and $100 million for the three months ended March 31, 2012 and 2011, respectively. 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, 2012 and 2011. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above.

Three Months Ended March 31,
2012 2011
(in millions)
Commodity Margin $ 517 $ 489
Other revenue 3 4
Plant operating expense(1) (170 ) (170 )
Sales, general and administrative expense(2) (30 ) (28 )
Other operating expense(3) (11 ) (9 )
Adjusted EBITDA from unconsolidated investments in power plants(4) 16 17
Adjusted EBITDA $ 325 $ 303

_________

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

(2) Shown net of stock-based compensation expense.

(3) Excludes RGGI compliance and other environmental costs of $3 and $2 million for each of the three months ended March 31, 2012 and 2011, respectively. Shown net of amortization expense.

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

Adjusted EBITDA and Adjusted Recurring Free Cash Flow Reconciliation for Guidance

Full Year 2012 Range: Low High
(in millions)
GAAP Net Income (Loss)(1) $ (20 ) $ 105
Plus:
Debt extinguishment costs 12 12
Loss on interest rate derivatives 14 14
Interest expense, net of interest income 765 765
Depreciation and amortization expense 575 575
Major maintenance expense 195 195
Operating lease expense 35 35
Other(2) 99 99
Adjusted EBITDA $ 1,675 $ 1,800
Less:
Operating lease payments 35 35
Major maintenance expense and maintenance capital expenditures(3) 350 350
Accelerated parts purchases to support upgrades(4) 30 30
Recurring cash interest, net(5) 770 770
Cash taxes 10 10
Other 10 10
Adjusted Recurring Free Cash Flow $ 470 $ 595
Non-recurring interest rate swap payments(6) $ (156 ) $ (156 )

_________

(1) For purposes of Net Income (Loss) guidance reconciliation, unrealized mark-to-market adjustments are assumed to be nil.

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

(3) Includes projected major maintenance expense of $185 million and maintenance capital expenditures of $165 million. Capital expenditures exclude major construction and development projects. 2012 figures exclude amounts to be funded by project debt.

(4) Incremental impact on 2012 maintenance capital expenditures related to acceleration of future turbine upgrades into 2012 and deferral of use of on-hand parts to post-2012 periods.

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

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

OPERATING PERFORMANCE METRICS

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

Three Months Ended March 31,
2012 2011
Total MWh generated (in thousands)(1) 28,055 18,127
West 8,203 6,195
Texas 9,143 5,319
Southeast 5,722 4,285
North 4,987 2,328
Average availability 90.3 % 88.9 %
West 93.5 % 91.9 %
Texas 85.7 % 79.6 %
Southeast 94.1 % 94.4 %
North 89.1 % 91.1 %
Average capacity factor, excluding peakers 54.9 % 36.9 %
West 60.3 % 46.3 %
Texas 59.8 % 35.4 %
Southeast 48.7 % 38.1 %
North 47.1 % 24.1 %
Steam adjusted heat rate (mmbtu/kWh) 7,272 7,369
West 7,140 7,386
Texas 7,081 7,253
Southeast 7,271 7,298
North 7,818 7,746

________

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

SOURCE: Calpine Corporation

Calpine Corporation
Media Relations:
Norma F. Dunn, 713-830-8883
norma.dunn@calpine.com
or
Investor Relations:
Bryan Kimzey, 713-830-8777
bryan.kimzey@calpine.com