Calpine Reports Fourth Quarter and Full Year 2012 Results, Raises Adjusted Free Cash Flow Per Share Guidance and Increases Share Repurchase Authorization by $400 Million

February 13, 2013 06:00 AM Eastern Standard Time

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE: CPN)

Summary of 2012 Financial Results (in millions, except per share amounts):

	Three Months Ended December 31,								Year Ended December 31,
	2012			2011			% Change		2012		2011			% Change

Operating Revenues	$	1,367		$	1,459		(6.3	)%	$	5,478	$	6,800		(19.4	)%
Commodity Margin	$	515		$	553		(6.9	)%	$	2,538	$	2,474		2.6	%
Adjusted EBITDA	$	315		$	379		(16.9	)%	$	1,749	$	1,726		1.3	%
Adjusted Free Cash Flow	$	41		$	108		(62.0	)%	$	564	$	489		15.3	%
Per Share (diluted)	$	0.09		$	0.22		(59.1	)%	$	1.20	$	1.01		18.8	%
Net Income (Loss)¹	$	100		$	(13	)			$	199	$	(190	)
Per Share (diluted)	$	0.22		$	(0.03	)			$	0.42	$	(0.39	)
Net Income (Loss), As Adjusted²	$	(86	)	$	(43	)			$	78	$	(13	)


2013 Full Year Guidance (in millions, except per share amounts):
		2013

Adjusted EBITDA		$1,760 - 1,960
Adjusted Free Cash Flow		$575 - 775
Per Share Midpoint (diluted)		$1.50

Recent Achievements:

Operations:
— Generated approximately 116 million MWh³ of electricity in 2012, a record and 23% more than 2011
— Held 2012 normal, recurring plant operating expense⁴ essentially flat, despite increased generation³, after accounting for prior period insurance reimbursements in 2011
— Delivered lowest annual fleetwide forced outage factor on record: 1.6%
— Achieved remarkable annual fleetwide starting reliability: 98.3%

Commercial:
— Entered into a new 10-year PPA with Tennessee Valley Authority to provide the full output of power from our Decatur Energy Center, commencing in January 2013
— Completed sales of Broad River and Riverside Energy Centers for approximately $829 million⁵
— Completed acquisition of Bosque Energy Center for approximately $432 million

Capital Allocation:
— Completed previously announced share repurchase program, having repurchased approximately 35.6 million shares, or 7.25%⁶, of our outstanding common stock
— Announced authorization of $400 million additional share repurchases: cumulative authorized total now $1 billion
— Invested in future growth with development of approximately 1,600 MW of new combined-cycle power plants

Calpine Corporation (NYSE: CPN) today reported fourth quarter 2012 Adjusted EBITDA of $315 million, compared to $379 million in the prior year period, and Adjusted Free Cash Flow of $41 million, or $0.09 per diluted share, compared to $108 million, or $0.22 per diluted share, in the prior year period. Net Income¹ for the fourth quarter was $100 million, or $0.22 per diluted share, compared to a Net Loss¹ of $13 million, or $0.03 per diluted share, in the prior year period. Net Loss, As Adjusted², for the fourth quarter of 2012 was $86 million compared to $43 million in the prior year period. The declines in fourth quarter Adjusted EBITDA, Adjusted Free Cash Flow and Net Loss, As Adjusted², in 2012 compared to 2011 were driven primarily by lower Commodity Margin, largely as a result of differences in the seasonal shaping of our hedging activity which tended to benefit the fourth quarter of 2011 more so than the comparable 2012 period.

Full year 2012 Adjusted EBITDA was $1,749 million, compared to $1,726 million in the prior year period, and Adjusted Free Cash Flow was $564 million, or $1.20 per diluted share, compared to $489 million, or $1.01 per diluted share, in the prior year period. Net Income¹ for 2012 was $199 million, or $0.42 per diluted share, compared to a Net Loss¹ of $190 million, or $0.39 per diluted share, in the prior year period. Net Income, As Adjusted², for 2012 was $78 million compared to a Net Loss, As Adjusted², of $13 million in 2011. The increases in 2012 Adjusted Free Cash Flow and Net Income, As Adjusted², compared to 2011 were primarily due to higher Commodity Margin and lower interest expense resulting from our refinancing efforts.

“2012 was a breakout year for Calpine, as we capitalized on the secular shift toward greater utilization of combined-cycle gas turbines in the power generation industry,” said Jack Fusco, Calpine’s Chief Executive Officer. “We achieved record operating results, generating 116 million MWh – 23% more than last year. The increased generation was primarily due to our excellent power plant operations and unprecedented coal-to-gas switching. Overall, our business continues to be resilient across a wide range of natural gas prices.

“I want to thank our employees for their outstanding response to the increased utilization of our fleet and their success in concurrently decreasing major maintenance cost and holding plant operating expenses essentially flat. This was due in large part to our continued focus on operational excellence and preventative maintenance, which also yielded our lowest annual forced outage factor on record.

“2012 was an active year for allocating capital as well. We sold 1,450 MW at two plants in South Carolina and Wisconsin and redeployed more than half the proceeds to purchase an 800 MW plant in Texas, while also continuing to execute our share repurchase program. We originated more than 2,100 MW of long-term contracts with our customers. In addition, we are on track to bring approximately 1,600 MW of additional natural gas-fired capacity online in California, Texas and Delaware over the next two and a half years.

“Finally, we ended the year with more than $1 billion of excess cash. Based on the strength of our balance sheet at year-end and the completion early this year of our $600 million share repurchase program, our Board has authorized a $400 million increase to our share repurchase program. We will continue to balance this authorization against growth opportunities in order to maximize shareholder value.”

“We successfully delivered on our 2012 financial commitments with Adjusted EBITDA and Adjusted Free Cash Flow of $1,749 million and $564 million, respectively, each of which was at the high end of our original guidance ranges,” said Zamir Rauf, Calpine’s Chief Financial Officer. “This resulted in a 19% increase in Adjusted Free Cash Flow Per Share to $1.20, which is also at the high end of our 15-20% compound annual growth rate target. Turning to 2013, based on the completion of our previously authorized $600 million share repurchase program, we are raising our Adjusted Free Cash Flow Per Share midpoint guidance to $1.50, which represents a 25% increase over 2012, while maintaining our full year Adjusted EBITDA and Adjusted Free Cash Flow guidance ranges.”

__________

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

^{2 Refer to Table 1 for further detail of Net Income, 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 plant operating expense excludes changes in major
maintenance expense, stock-based compensation expense, non-cash loss on
disposition of assets and other costs. See the table titled
“Consolidated Adjusted EBITDA Reconciliation” for the actual amounts of
these items for the three months and years ended December 31, 2011 and
2012.}

^{5 Includes fees associated with a five-year consulting agreement
with the buyer of Broad River Energy Center.}

^{6 Based upon shares outstanding (including shares held in reserve)
as of June 30, 2011, immediately prior to announcement of program.}

SUMMARY OF FINANCIAL PERFORMANCE

Fourth Quarter Results

Adjusted EBITDA for the fourth quarter of 2012 was $315 million, compared to $379 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily due to a $38 million decrease in Commodity Margin and a $20 million increase in plant operating expense⁴. The decrease in Commodity Margin was primarily due to:

						–		lower contribution from hedges and
						–		expiration of contracts, particularly in our West and Southeast segments, some of which have since been recontracted, partially offset by
						+		higher regulatory capacity revenue.

The increase in plant operating expense⁴ was primarily due to reimbursements for insurance claims from prior periods that disproportionately reduced our plant operating expense in the fourth quarter of 2011.

Net Income¹ was $100 million for the fourth quarter of 2012, compared to a Net Loss¹of $13 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted², was $86 million in the fourth quarter of 2012 compared to $43 million in the prior year period. The year-over-year decline was driven largely by:

						–		lower Commodity Margin, as previously discussed and
						–		higher plant operating expense, as previously discussed, partially offset by
						+		an income tax benefit primarily due to a decrease in state income taxes and a reduction in income tax expense related to the application of non-cash intraperiod tax allocations.

Full Year Results

Adjusted EBITDA in 2012 was $1,749 million compared to $1,726 million in 2011. The year-over-year increase in Adjusted EBITDA was primarily due to a $64 million increase in Commodity Margin, partially offset by a $26 million increase in plant operating expense⁴ and a $14 million increase in sales, general and administrative expense⁷. The increase in Commodity Margin was primarily due to:

						+		higher contribution from hedges
						+		higher generation in our Texas and North segments due to lower natural gas prices and higher generation in our West segment due to improved market conditions, less hydroelectric generation and a nuclear power plant outage in California during 2012 and
						+		an extreme cold weather event in Texas that occurred in 2011 that resulted in unplanned outages at some of our power plants, negatively impacting our revenue in 2011, which did not reoccur in 2012, partially offset by
						–		lower regulatory capacity revenue and
						–		expiration of contracts, some of which have since been recontracted.

The increase in plant operating expense⁴was primarily due to prior period insurance reimbursements that benefited 2011 compared to 2012, as previously discussed.

Net Income¹ was $199 million in 2012, compared to a Net Loss¹of $190 million in 2011. As detailed in Table 1, Net Income, As Adjusted², was $78 million in 2012, compared to Net Loss, As Adjusted², of $13 million in 2011. The year-over-year improvement was driven largely by:

						+		higher Commodity Margin, as previously discussed
						+		lower interest expense, primarily resulting from a decrease in our annual effective interest rate and
						+		lower income tax expense related to the application of intraperiod tax allocation and a decrease in various state and federal jurisdiction income taxes, partially offset by
						–		modestly higher plant operating expenses, as previously discussed.

___________

^{7 Increase in sales, general and administrative 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 years
ended December 31, 2011 and 2012.}

Table 1: Net Income, As Adjusted

	Three Months Ended December 31,						Year Ended December 31,
	2012			2011			2012			2011
	(in millions)
Net income (loss) attributable to Calpine	$	100		$	(13	)	$	199		$	(190	)
Debt extinguishment costs⁽¹⁾	18			—			30			94
(Gain) on sale of assets, net⁽¹⁾	(222		)	—			(222		)	—
Unrealized MtM (gain) loss on derivatives^{(1) (2)}	31			(72		)	(72		)	(30		)
Other items^{(1) (3)}	(13		)	42			143			113
Net Income (loss), As Adjusted⁽⁴⁾	$	(86	)	$	(43	)	$	78		$	(13	)

__________

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

^{(2) In addition to changes in market value on derivatives not
designated as hedges, changes in unrealized (gain) loss also includes
de-designation of interest rate swap cash flow hedges and related
reclassification from AOCI into earnings, hedge ineffectiveness and
adjustments to reflect changes in credit default risk exposure.}

^{(3) Other items include realized mark-to-market losses associated
with the settlement of non-hedged interest rate swaps totaling nil and
$156 million for the three months and year ended December 31, 2012,
respectively, and $42 million and $189 million for the three months and
year ended December 31, 2011, respectively. Other items for the three
months and year ended December 31, 2012, include a $13 million tax
refund associated with our 2004 amended federal income tax return. Other
items for the year ended December 31, 2011, 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 Income, As Adjusted.}

REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin by Segment (in millions)

	Three Months Ended December 31,							Year Ended December 31,
	2012		2011		Variance			2012		2011		Variance
West	$	246	$	263	$	(17	)	$	994	$	1,061	$	(67	)
Texas	98		112		(14		)	570		469		101
North	138		126		12			729		704		25
Southeast	33		52		(19		)	245		240		5
Total	$	515	$	553	$	(38	)	$	2,538	$	2,474	$	64

West Region

Fourth Quarter: Commodity Margin in our West segment decreased by $17 million in the fourth quarter of 2012 compared to the prior year period. Primary drivers were:

						–		lower contribution from hedges and
						–		lower revenue due to the expiration of contracts, partially offset by
						+		an increase in Commodity Margin on our open position driven by higher market spark spreads on higher generation volumes.

Full Year: Commodity Margin in our West segment decreased by $67 million in 2012 compared to 2011. Primary drivers were:

						–		lower contribution from hedges
						–		lower market power prices associated with our Geysers assets and
						–		lower revenue due to the expiration of contracts, partially offset by
						+		an increase in Commodity Margin on our open position driven by higher market spark spreads and
						+		increased generation driven primarily by improved market conditions, less hydroelectric generation and a nuclear power outage in California during 2012.

Texas Region

Fourth Quarter: Commodity Margin in our Texas segment decreased by $14 million in the fourth quarter of 2012 compared to the prior year period. Primary drivers were:

						–		lower contribution from hedges and
						–		weak market pricing conditions due to mild weather.

Full Year: Commodity Margin in our Texas segment increased by $101 million in 2012 compared to 2011. Primary drivers were:

						+		higher contribution from hedging activities that secured favorable pricing despite lower market prices driven by milder weather in the third quarter of 2012 compared to the prior year period
						+		higher generation driven by lower natural gas prices in the first half of 2012 and
						+		an extreme cold weather event in Texas in February 2011 that negatively impacted our Commodity Margin in the first quarter of the prior year, which did not recur in the current year.

North Region

Fourth Quarter: Commodity Margin in our North segment increased by $12 million in the fourth quarter of 2012 compared to the prior year period. Primary drivers were:

						+		higher regulatory capacity revenues and
						+		to a far lesser extent, increased generation.

Full Year: Commodity Margin in our North segment increased by $25 million in 2012 compared to 2011. Primary drivers were:

						+		York Energy Center achieving commercial operation in March 2011
						+		higher contribution from hedges and
						+		increased generation driven by lower natural gas prices, partially offset by
						–		lower regulatory capacity revenues and
						–		lower nodal pricing in PJM during 2012.

Southeast Region

Fourth Quarter: Commodity Margin in our Southeast segment decreased by $19 million in the fourth quarter of 2012 compared to the prior year period. The primary drivers were:

						–		expiration of a PPA during the third quarter of 2012, which has since been recontracted, and
						–		lower contribution from hedges.

Full Year: Commodity Margin in our Southeast segment increased by $5 million in 2012 compared to 2011. Primary drivers were:

						+		higher contribution from hedges and
						+		higher generation resulting from lower natural gas prices, largely offset by
						–		the negative impact from the expiration of a PPA during the third quarter of 2012, which has since been recontracted.

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Liquidity


	December 31,		December 31,
	2012		2011
	(in millions)
Cash and cash equivalents, corporate⁽¹⁾	$	1,153	$	946
Cash and cash equivalents, non-corporate	131		306
Total cash and cash equivalents	1,284		1,252
Restricted cash	253		194
Corporate Revolving Facility availability	757		560
Letter of credit availability⁽²⁾	—		7
Total current liquidity availability	$	2,294	$	2,013

__________

^{(1) Includes $11 million and $34 million of margin deposits held by
us posted by our counterparties at December 31, 2012, and 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. As a
result of the completion of the sale of Riverside Energy Center, LLC, a
wholly owned subsidiary of CDHI, on December 31, 2012, we are required
to cash collateralize letters of credit issued in excess of $225 million
until replacement collateral is contributed to the CDHI collateral
package, which we are in the process of arranging. At December 31, 2012,
we had $28 million of cash collateral posted in support of outstanding
letters of credit under our CDHI letter of credit facility. We do not
believe that this change will have a material impact on our liquidity.}

Liquidity increased to approximately $2.3 billion as of December 31, 2012, up from approximately $2.0 billion at December 31, 2011.

Cash flows from operating activities in 2012 resulted in net inflows of $653 million compared to $775 million in 2011. The decrease in cash provided by operating activities was primarily due to an increase in cash paid for interest due to timing of interest payments on our debt and an increase in working capital driven by higher margin requirements.

Cash flows used in investing activities decreased to $470 million in 2012 compared to $836 million in 2011, driven largely by higher proceeds from the sales of our Broad River and Riverside Energy Centers, partially offset by the purchase of our Bosque Energy Center.

Cash flows used in financing activities were $151 million in 2012, driven largely by $463 million in share repurchases in 2012, partially offset by net proceeds from borrowing on our project debt facilities and our 2012 refinancing activities, as further described below.

Consistent with our efforts to optimize and simplify our capital structure, during 2012, we entered into an $835 million first lien term loan, the proceeds of which were used to redeem 10% (or approximately $590 million) of our senior secured notes and to retire variable rate project-level BRSP debt (approximately $218 million remaining balance). The term loan, which amortizes at a rate of 1% per year, matures in 2019. The term loan currently bears interest at LIBOR plus 3.25% per annum (subject to a LIBOR floor of 1.25%). This transaction is expected to produce annual interest savings of approximately $25 million.

Subsequently, in February 2013, we repriced approximately $2.5 billion of our first lien term loans, including the aforementioned $835 million term loan. This repricing lowers the term loans’ LIBOR floor by 0.25% to 1.0% and lowers their applicable margin by 0.25% to 3.0%. We estimate that this repricing will produce additional annual interest savings of approximately $12 million. We expect this transaction to close in the second half of February.

Adjusted Free Cash Flow was $564 million in 2012, compared to $489 million in 2011. Adjusted Free Cash Flow increased during the period primarily due to lower interest expense associated with our refinancing efforts, as well as a $23 million increase in Adjusted EBITDA, as previously discussed. Lower major maintenance expenditures related to our plant outage schedule further contributed to the improvement in Adjusted Free Cash Flow.

CAPITAL ALLOCATION

Portfolio Optimization

During the fourth quarter of 2012, we completed the following transactions that allowed us to strategically redeploy capital:

the purchase of our Bosque Energy Center, an 800 MW modern, natural gas-fired combined-cycle power plant in Central Texas, for approximately $432 million, or $540/kW
the sale of our Broad River Energy Center, an 847 MW natural gas-fired peaking power plant in South Carolina, for approximately $427 million⁵, or $504/kW and
the sale of our Riverside Energy Center, a 603 MW combined-cycle power plant in Wisconsin, for approximately $402 million, or $667/kW.

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. In early 2013, we completed this $600 million share repurchase program, having repurchased a total of approximately 35.6 million shares of our outstanding common stock at an average price paid of $16.87 per share. In February 2013, our Board of Directors authorized the repurchase of up to an additional $400 million in shares of our common stock, bringing the cumulative authorization total to $1.0 billion.

PLANT DEVELOPMENT

West:

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

Los Esteros Critical Energy Facility: 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. Construction is ongoing and COD is expected in the summer of 2013.

Texas:

Channel and Deer Park Expansions: In September and November 2011, we filed air permit applications with the Texas Commission on Environmental Quality (“TCEQ”) and the EPA to expand the baseload capacity of the Deer Park and Channel Energy Centers by approximately 260 MW⁸ each. We received air permit approvals from the TCEQ for our Deer Park and Channel expansion projects in September and October 2012, respectively, and from the EPA in November 2012. Construction on these expansion projects commenced in the fourth quarter of 2012. We expect COD during the summer of 2014 for these expansions and are currently evaluating funding sources including, but not limited to, nonrecourse financing, corporate financing or internally generated funds.

North:

Garrison Energy Center: We are actively permitting 618 MW of new combined-cycle capacity at a development site secured by a long-term lease with the City of Dover. For the first phase (309 MW), we have executed the Interconnection Services Agreement and the Interconnection Construction Services Agreement with PJM. For the second phase (309 MW), we have completed a feasibility study and are currently conducting a system impact study. Environmental permitting, site development planning and development engineering are underway, and the first phase’s capacity cleared PJM’s 2015/2016 base residual auction. We received the air permit and executed a preliminary notice to proceed with the engineering, procurement and construction agreement during the first quarter of 2013. We expect COD for the first phase by the summer of 2015 and are currently evaluating funding sources including, but not limited to, nonrecourse financing, corporate financing or internally generated funds.

All Segments:

Turbine Modernization: We continue to move forward with our turbine modernization program. Through December 31, 2012, we have completed the upgrade of eleven Siemens and eight GE turbines totaling over 200 MW and have committed to upgrade approximately three additional turbines.

___________

^{8 Represents incremental baseload capacity at annual average
conditions. Incremental summer peaking capacity is approximately 200 MW
per unit, supplemented by incremental efficiencies across the balance of
plant.}

OPERATIONS UPDATE

2012 Power Operations Achievements:

Safety Performance:
— Maintained stellar safety metrics
— Recognized for 10 years with no lost time incidents: Westbrook Energy Center, Pine Bluff Energy Center, Baytown Energy Center, Zion Energy Center, Tasley Energy Center, Missouri Avenue Energy Center, Crisfield Energy Center, Bayview Energy Center, Geysers plants – Aidlin, Sonoma, Cobb Creek, Quicksilver, Socrates

Availability Performance:
— Delivered lowest annual fleetwide forced outage factor on record: 1.6%
— Achieved an impressive full year fleetwide starting reliability: 98.3%

Cost Performance:
— Held normal, recurring plant operating expense⁴essentially flat, despite a 23% increase in generation³, after accounting for prior period insurance reimbursements in 2011

Geothermal Generation:
— Provided more than 6 million MWh of renewable baseload generation with a remarkable 0.26% forced outage factor during 2012

Natural Gas-fired Generation:
— Increased combined-cycle capacity factor in 2012 to 52.3% compared to 42.6% in 2011
— Deer Park Energy Center: Produced 6.2 million MWh in 2012, the most by any individual plant in fleet history

2012 Commercial Operations Achievements:

Customer-oriented Growth:
— Entered into a 10-year PPA with Tennessee Valley Authority to provide the full output of power from our Decatur Energy Center, a natural gas-fired, combined-cycle power plant that can generate up to 795 MW, commencing in January 2013
— Entered into a 15-year PPA with Public Service Company of Oklahoma to provide 260 MW of capacity, energy and ancillary services from our Oneta Energy Center commencing in June 2016
— Entered into a five-year PPA with Southwestern Public Service Company to provide an additional 200 MW of capacity and energy from our Oneta Energy Center beginning June 2014
— Executed a new five-year resource adequacy contract with PG&E for approximately 280 MW of combined heat and power capacity from our Los Medanos Energy Center commencing in summer 2013
— Entered into a new seven-year resource adequacy contract with Southern California Edison Company ("SCE") for approximately 280 MW of combined heat and power capacity from our Los Medanos Energy Center commencing in January 2014
— Executed a new five-year resource adequacy contract with SCE for approximately 120 MW of combined heat and power capacity from our Gilroy Cogeneration Plant commencing in January 2014
— Amended an existing PPA with Dow Chemical Company for an incremental energy sale of up to approximately 158,000 MWh per year of energy from our Los Medanos Energy Center that runs through February 2025
— 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 through 2035.

FINANCIAL OUTLOOK

(in millions, except per share amounts)

		Full Year 2013

Adjusted EBITDA	$	1,760 - 1,960
Less:
Operating lease payments		35
Major maintenance expense and maintenance capital expenditures⁽¹⁾		370
Cash interest, net⁽²⁾		755
Cash taxes		15
Other		10
Adjusted Free Cash Flow	$	575 - 775
Per Share Midpoint (diluted)	$	1.50

Growth capital expenditures (net of debt funding)	$	(250	)
Debt amortization	$	(140	)

________

^{(1) Includes projected major maintenance expense of $210 million
and maintenance capital expenditures of $160 million. Capital
expenditures exclude major construction and development projects. 2013
figures exclude non-recurring IT system upgrade.}

^{(2) Includes commitment, letter of credit and other bank fees from
both consolidated and unconsolidated investments, net of capitalized
interest and interest income.}

As detailed above, today we are reaffirming our 2013 guidance. We project Adjusted EBITDA of $1,760 million to $1,960 million and Adjusted Free Cash Flow of $575 million to $775 million. Our guidance reflects all previously announced acquisition and divestiture activity, including the sales of Broad River and Riverside Energy Centers, and the purchase of Bosque Energy Center, each of which closed during the fourth quarter of 2012. We also expect to invest $250 million, net of debt funding, in growth-related projects during the year, including our Garrison Energy Center development project and the expansion of our Deer Park and Channel Energy Centers. (Though our construction projects at Russell City and Los Esteros continue into 2013, we met our equity contribution requirements on these projects in 2011, such that all costs incurred in 2013 will be funded from the project debt we have secured for these projects.)

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results for the fourth quarter and full year 2012 on Wednesday, February 13, 2013, 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 U.S. or (847) 413-3238 outside the U.S. The confirmation code is 34044836. 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 U.S. or (630) 652-3042 outside the U.S. and providing confirmation code 34044836. Presentation materials to accompany the conference call will be available on our website on February 13, 2013.

INVESTOR DAY

Calpine will be hosting an investor and analyst meeting on Wednesday, April 10, 2013, from 1 p.m. to 5 p.m. CT in Houston, Texas. Members of the Calpine management team will present their views on the company and its markets and provide updates on financial, regulatory and strategic initiatives. More information about the event, including online registration and a link to the live webcast, can be found on the Investor Relations section of our website at www.calpine.com.

ABOUT CALPINE

Calpine Corporation generates more electricity than any other independent power producer in America, with a fleet of 92 power plants in operation or under construction, representing more than 27,000 megawatts of generation capacity in operation. Serving customers in 20 states and Canada, we specialize in developing, constructing, owning and operating natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our clean, efficient, modern and flexible fleet is uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. We focus on wholesale competitive power markets and advocate for market-driven solutions that result in nondiscriminatory forward price signals for investors. Please visit www.calpine.com to learn more about why Calpine is a generation ahead - today.

Calpine’s Annual Report on Form 10-K for the year ended December 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;
Laws, regulation and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate;
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 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;
The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated thereunder;
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 2012 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 STATEMENTS OF OPERATIONS (in millions, except share and per share amounts)

	(Unaudited)
	Three Months Ended December 31,						Year Ended December 31,
	2012			2011			2012			2011
Operating revenues:
Commodity revenue	$	1,339		$	1,477		$	5,417		$	6,753
Unrealized mark-to-market gain (loss)	24			(21		)	48			35
Other revenue	4			3			13			12
Operating revenues	1,367			1,459			5,478			6,800
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	821			924			2,894			4,299
Unrealized mark-to-market (gain) loss	57			(43		)	130			60
Fuel and purchased energy expense	878			881			3,024			4,359
Plant operating expense	223			193			922			904
Depreciation and amortization expense	144			145			562			550
Sales, general and other administrative expense	36			32			140			131
Other operating expenses	20			21			78			77
Total operating expenses	1,301			1,272			4,726			6,021
(Gain) on sale of assets, net	(222		)	—			(222		)	—
(Income) from unconsolidated investments in power plants	(7		)	(9		)	(28		)	(21		)
Income from operations	295			196			1,002			800
Interest expense	184			185			736			760
(Gain) loss on interest rate derivatives	—			(4		)	14			145
Interest (income)	(4		)	(2		)	(11		)	(9		)
Debt extinguishment costs	18			—			30			94
Other (income) expense, net	1			7			15			21
Income (loss) before income taxes	96			10			218			(211		)
Income tax expense (benefit)	(4		)	23			19			(22		)
Net income (loss)	100			(13		)	199			(189		)
Net income attributable to the noncontrolling interest	—			—			—			(1		)
Net income (loss) attributable to Calpine	$	100		$	(13	)	$	199		$	(190	)

Basic earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)	459,304			482,468			467,752			485,381
Net income (loss) per common share attributable to Calpine — basic	$	0.22		$	(0.03	)	$	0.43		$	(0.39	)

Diluted earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)	463,291			482,468			471,343			485,381
Net income (loss) per common share attributable to Calpine — diluted	$	0.22		$	(0.03	)	$	0.42		$	(0.39	)


CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS December 31, 2012 and 2011 (in millions, except share and per share amounts)

	2012			2011
ASSETS
Current assets:
Cash and cash equivalents	$	1,284		$	1,252
Accounts receivable, net of allowance of $6 and $13	437			598
Margin deposits and other prepaid expense	244			193
Restricted cash, current	193			139
Derivative assets, current	339			1,051
Inventory and other current assets	335			329
Total current assets	2,832			3,562
Property, plant and equipment, net	13,005			13,019
Restricted cash, net of current portion	60			55
Investments	81			80
Long-term derivative assets	98			113
Other assets	473			542
Total assets	$	16,549		$	17,371
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	382		$	435
Accrued interest payable	180			200
Debt, current portion	115			104
Derivative liabilities, current	357			1,144
Income taxes payable	11			3
Other current liabilities	273			276
Total current liabilities	1,318			2,162
Debt, net of current portion	10,635			10,321
Long-term derivative liabilities	293			279
Other long-term liabilities	247			245
Total liabilities	12,493			13,007

Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding at December 31, 2012 and 2011	—			—
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 492,495,100 shares issued and 457,048,970 shares outstanding at December 31, 2012, and 490,468,815 shares issued and 481,743,738 shares outstanding at December 31, 2011	1			1
Treasury stock, at cost, 35,446,130 and 8,725,077 shares, respectively	(594		)	(125		)
Additional paid-in capital	12,335			12,305
Accumulated deficit	(7,500		)	(7,699		)
Accumulated other comprehensive loss	(248		)	(178		)
Total Calpine stockholders’ equity	3,994			4,304
Noncontrolling interest	62			60
Total stockholders’ equity	4,056			4,364
Total liabilities and stockholders’ equity	$	16,549		$	17,371


CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2012 and 2011 (in millions)

	2012			2011
Cash flows from operating activities:
Net income (loss)	$	199		$	(189	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense⁽¹⁾	605			587
Debt extinguishment costs	—			82
Deferred income taxes	1			(21		)
(Gain) loss on sale of power plants and other, net	(212		)	13
Unrealized mark-to-market (gain) loss	(72		)	(30		)
(Income) from unconsolidated investments in power plants	(28		)	(21		)
Return on unconsolidated investments in power plants	24			6
Stock-based compensation expense	25			24
Other	1			6
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable	159			74
Derivative instruments, net	(52		)	15
Other assets	(57		)	1
Accounts payable and accrued expenses	(86		)	28
Settlement of non-hedging interest rate swaps	156			189
Other liabilities	(10		)	11
Net cash provided by operating activities	653			775
Cash flows from investing activities:
Purchases of property, plant and equipment	(637		)	(683		)
Proceeds from sale of power plants, interests and other	825			13
Purchase of Bosque Energy Center, net of cash	(432		)	—
Return of investment from unconsolidated investments	5			—
Settlement of non-hedging interest rate swaps	(156		)	(189		)
(Increase) decrease in restricted cash	(59		)	54
Purchases of deferred transmission credits	(12		)	(31		)
Other	(4		)	—
Net cash used in investing activities		(470	)		(836	)
Cash flows from financing activities:
Borrowings under First Lien Term Loans	835			1,657
Repayments of First Lien Term Loans	(19		)	—
Repayments on NDH Project Debt	—			(1,283		)
Issuance of First Lien Notes	—			1,200
Repayments of First Lien Notes	(590		)	—
Repayments on First Lien Credit Facility	—			(1,195		)
Borrowings from project financing, notes payable and other	389			327
Repayments of project financing, notes payable and other	(289		)	(550		)
Capital contributions from noncontrolling interest holder	—			33
Financing costs	(20		)	(81		)
Stock repurchases	(463		)	(119		)
Other	6			(3		)
Net cash used in financing activities	(151		)	(14		)
Net increase (decrease) in cash and cash equivalents	32			(75		)
Cash and cash equivalents, beginning of period	1,252			1,327
Cash and cash equivalents, end of period	$	1,284		$	1,252

Cash paid during the period for:
Interest, net of amounts capitalized	$	719		$	656
Income taxes	$	16		$	18

Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable	$	19		$	(24	)
Other non-cash additions to property, plant and equipment	$	13		$	—

__________

^{(1) Includes depreciation and amortization included in fuel and
purchased energy expense and interest expense on our Consolidated
Statements of Operations.}

REGULATION G RECONCILIATIONS

Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance.

Net Income (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 debt extinguishment costs, unrealized mark-to-market (gain) loss on derivatives, and other adjustments. Net Income (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 Income (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 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 net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, 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 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 and other adjustments, including non-recurring items. Adjusted Free Cash Flow is a performance measure and is not intended to represent net income (loss), the most directly comparable U.S. GAAP measure, or liquidity 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 December 31, 2012 and 2011 (in millions):

	Three Months Ended December 31, 2012
												Consolidation
												And
	West			Texas		North			Southeast			Elimination			Total
Commodity Margin⁽¹⁾⁽²⁾	$	246		$	98	$	138		$	33		$	—		$	515
Add: Unrealized mark-to-market commodity activity, net and other⁽³⁾	(13		)	21		3			(28		)	(9		)	(26		)
Less:
Plant operating expense	87			58		52			33			(7		)	223
Depreciation and amortization expense	52			38		34			19			1			144
Sales, general and other administrative expense	13			11		6			6			—			36
Other operating expenses	12			1		8			3			(4		)	20
(Gain) on sale of assets, net	—			—		(7		)	(215		)	—			(222		)
(Income) from unconsolidated investments in power plants	—			—		(7		)	—			—			(7		)
Income from operations	$	69		$	11	$	55		$	159		$	1		$	295

	Three Months Ended December 31, 2011
												Consolidation
												And
	West		Texas			North			Southeast			Elimination			Total
Commodity Margin⁽¹⁾⁽²⁾	$	263	$	112		$	126		$	52		$	—		$	553
Add: Unrealized mark-to-market commodity activity, net and other⁽³⁾	77		(48		)	(1		)	5			(9		)	24
Less:
Plant operating expense	83		42			41			34			(7		)	193
Depreciation and amortization expense	52		36			36			23			(2		)	145
Sales, general and other administrative expense	14		10			5			4			(1		)	32
Other operating expenses	11		1			7			2			(1		)	20
(Income) from unconsolidated investments in power plants	—		—			(9		)	—			—			(9		)
Income (loss) from operations	$	180	$	(25	)	$	45		$	(6	)	$	2		$	196

The following table reconciles our Commodity Margin to its U.S. GAAP results for the years ended December 31, 2012 and 2011 (in millions):

	Year Ended December 31, 2012
												Consolidation
												And
	West			Texas		North			Southeast			Elimination			Total
Commodity Margin⁽¹⁾⁽²⁾	$	994		$	570	$	729		$	245		$	—		$	2,538
Add: Unrealized mark-to-market commodity activity, net and other⁽⁴⁾	(93		)	87		(14		)	(33		)	(31		)	(84		)
Less:
Plant operating expense	368			247		206			131			(30		)	922
Depreciation and amortization expense	203			142		134			85			(2		)	562
Sales, general and other administrative expense	36			47		28			29			—			140
Other operating expenses	42			5		29			5			(3		)	78
(Gain) on sale of assets, net	—			—		(7		)	(215		)	—			(222		)
(Income) from unconsolidated investments in power plants	—			—		(28		)	—			—			(28		)
Income from operations	$	252		$	216	$	353		$	177		$	4		$	1,002

	Year Ended December 31, 2011
												Consolidation
												And
	West		Texas			North			Southeast			Elimination			Total
Commodity Margin⁽¹⁾⁽²⁾	$	1,061	$	469		$	704		$	240		$	—		$	2,474
Add: Unrealized mark-to-market commodity activity, net and other⁽⁴⁾	113		(102		)	(13		)	1			(32		)	(33		)
Less:
Plant operating expense	380		235			177			141			(29		)	904
Depreciation and amortization expense	192		135			138			90			(5		)	550
Sales, general and other administrative expense	43		43			24			22			(1		)	131
Other operating expenses	41		3			30			5			(2		)	77
(Income) from unconsolidated investments in power plants	—		—			(21		)	—			—			(21		)
Income (loss) from operations	$	518	$	(49	)	$	343		$	(17	)	$	5		$	800

__________

^{(1) Our North segment includes Commodity Margin related to
Riverside Energy Center, LLC, of $9 million and $8 million for the three
months ended December 31, 2012 and 2011, respectively, and $73 million
and $70 million for the years ended December 31, 2012 and 2011,
respectively.}

^{(2) Our Southeast segment includes Commodity Margin related to
Broad River of $8 million and $9 million for the three months ended
December 31, 2012 and 2011, respectively, and $52 million and $51
million for the years ended December 31, 2012 and 2011, respectively.}

^{(3) Includes $(6) million and $(3) million of lease levelization
for the three months ended December 31, 2012 and 2011, respectively, and
$3 million of amortization expense for each of the three months ended
December 31, 2012 and 2011.}

^{(4) Includes $1 million and $12 million of lease levelization and
$14 million and $8 million of amortization expense for the years ended
December 31, 2012 and 2011, respectively.}

Consolidated Adjusted EBITDA Reconciliation

In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our net income (loss) attributable to Calpine for the three months and years ended December 31, 2012 and 2011, as reported under U.S. GAAP.

	Three Months Ended December 31,						Year Ended December 31,
	2012			2011			2012			2011
	(in millions)
Net income (loss) attributable to Calpine	$	100		$	(13	)	$	199		$	(190	)
Net income attributable to the noncontrolling interest	—			—			—			1
Income tax expense (benefit)	(4		)	23			19			(22		)
Debt extinguishment costs and other (income) expense, net	19			7			45			115
(Gain) loss on interest rate derivatives	—			(4		)	14			145
Interest expense, net of interest income	180			183			725			751
Income from operations	$	295		$	196		$	1,002		$	800
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs⁽¹⁾	145			146			564			552
Major maintenance expense	42			36			200			205
Operating lease expense	8			9			34			35
Unrealized (gain) loss on commodity derivative mark-to-market activity	33			(23		)	82			25
(Gain) on sale of assets, net	(222		)	—			(222		)	—
Adjustments to reflect Adjusted EBITDA from unconsolidated investments⁽²⁾⁽³⁾	8			6			31			36
Stock-based compensation expense	6			6			25			24
(Gain) loss on dispositions of assets	3			(1		)	12			16
Acquired contract amortization	3			3			14			8
Other	(6		)	1			7			25
Total Adjusted EBITDA	$	315		$	379		$	1,749		$	1,726
Less:
Operating lease payments	8			9			34			35
Major maintenance expense and capital expenditures⁽⁴⁾	77			62			375			397
Cash interest, net⁽⁵⁾	186			194			757			781
Cash taxes	1			2			11			13
Other	2			4			8			11
Adjusted Free Cash Flow⁽⁶⁾	$	41		$	108		$	564		$	489

Weighted average shares of common stock outstanding (diluted, in thousands)	463,291			482,468			471,343			485,381
Adjusted Free Cash Flow
Per Share (diluted)	$	0.09		$	0.22		$	1.20		$	1.01

_________

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

^{(2) Included on our Consolidated 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 each of the three months ended December 31, 2012 and 2011,
respectively, and nil and $1 million for the years ended December 31,
2012 and 2011, respectively.}

^{(4) Includes $42 million and $192 million in major maintenance
expense for the three months and year ended December 31, 2012,
respectively, and $35 million and $183 million in maintenance capital
expenditures for the three months and year ended December 31, 2012,
respectively. Includes $27 million and $201 million in major maintenance
expense for the three months and year end December 31, 2011,
respectively, and $35 million and $196 million in maintenance capital
expenditures for the three months and year ended December 31, 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 a decrease in working capital of $91 million and $107
million for the three months and year ended December 31, 2012,
respectively, and a decrease in working capital of $8 million and
increase in working capital of $13 million for the three months and year
ended December 31, 2011, respectively. Adjusted 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 and years ended December 31, 2012 and 2011. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above.

	Three Months Ended December 31,						Year Ended December 31,
	2012			2011			2012			2011
	(in millions)
Commodity Margin	$	515		$	553		$	2,538		$	2,474
Other revenue	3			2			12			13
Plant operating expense⁽¹⁾	(174		)	(154		)	(692		)	(666		)
Sales, general and administrative expense⁽²⁾	(33		)	(28		)	(127		)	(113		)
Other operating expenses⁽³⁾	(11		)	(10		)	(41		)	(40		)
Adjusted EBITDA from unconsolidated investments in power plants⁽⁴⁾	14			15			58			57
Other	1			1			1			1
Adjusted EBITDA	$	315		$	379		$	1,749		$	1,726

_________

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

^{(2) Shown net of stock-based compensation expense and other costs.}

^{(3) Shown net of operating lease expense, amortization and other
costs.}

^{(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 Free Cash Flow Reconciliation for Guidance

Full Year 2013 Range:		Low		High
		(in millions)
GAAP Net Income ⁽¹⁾	$	135	$	335
Plus:
Interest expense, net of interest income		745		745
Depreciation and amortization expense		575		575
Major maintenance expense		205		205
Operating lease expense		35		35
Other⁽²⁾		65		65
Adjusted EBITDA	$	1,760	$	1,960
Less:
Operating lease payments		35		35
Major maintenance expense and maintenance capital expenditures⁽³⁾		370		370
Cash interest, net⁽⁴⁾		755		755
Cash taxes		15		15
Other		10		10
Adjusted Free Cash Flow	$	575	$	775

_________

^{(1) For purposes of Net Income 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 $210 million
and maintenance capital expenditures of $160 million. Capital
expenditures exclude major construction and development projects. 2013
figures exclude non-recurring IT system upgrade.}

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

OPERATING PERFORMANCE METRICS

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

	Three Months Ended December 31,				Year Ended December 31,
	2012		2011		2012		2011
Total MWh generated (in thousands)⁽¹⁾	25,189		24,954		112,216		90,875
West	9,179		7,634		33,390		23,823
Texas	7,689		8,533		35,946		32,552
Southeast	3,404		4,494		21,148		18,983
North	4,917		4,293		21,732		15,517

Average availability	90.9	%	91.4	%	91.3	%	90.1	%
West	93.9	%	95.8	%	91.9	%	88.2	%
Texas	93.1	%	89.4	%	91.1	%	89.0	%
Southeast	90.6	%	91.5	%	93.4	%	91.9	%
North	86.0	%	89.4	%	89.3	%	91.6	%

Average capacity factor, excluding peakers⁽¹⁾	48.0	%	48.7	%	53.7	%	44.3	%
West	66.2	%	55.3	%	60.6	%	43.6	%
Texas	46.6	%	55.2	%	57.4	%	53.2	%
Southeast	29.5	%	39.2	%	44.6	%	40.6	%
North	46.2	%	40.3	%	48.8	%	35.9	%

Steam adjusted heat rate (Btu/kWh)	7,378		7,358		7,361		7,412
West	7,306		7,287		7,278		7,418
Texas	7,139		7,203		7,147		7,243
Southeast	7,345		7,279		7,309		7,312
North	7,900		7,867		7,914		7,919

________

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

Contacts

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

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