Calpine Reports Second Quarter 2012 Results, Tightens 2012 Guidance Range by Raising Lower End

 

Tightens 2012 Guidance Range by Raising Lower End

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

			Three Months Ended June 30,														Six Months Ended June 30,
			2012					2011					% Change				2012					2011					% Change
Operating Revenues1			$	879				$	1,633				(46.2	)%			$	2,115				$	3,132				(32.5	)%
Commodity Margin			$	609				$	607				0.3	%			$	1,126				$	1,096				2.7	%
Adjusted EBITDA			$	403				$	406				(0.7	)%			$	728				$	709				2.7	%
Adjusted Recurring Free Cash Flow			$	87				$	41				112.2	%			$	60				$	20				200.0	%
Per Share			$	0.19				$	0.08				137.5	%			$	0.13				$	0.04				225.0	%
Net Loss2			$	(329	)			$	(70	)							$	(338	)			$	(367	)
Net Income (Loss), As Adjusted3			$	14				$	(55	)							$	(51	)			$	(165	)

Tightening 2012 Full Year Guidance:

			Prior Guidance (as of April 2012)			Current Guidance
			(in millions)
Adjusted EBITDA			$1,675 – 1,800			$1,700 – 1,800
Adjusted Recurring Free Cash Flow			$470 – 595			$500 – 600

Recent Achievements:

Operations:

• Generated 27 million MWh4 of electricity in the second quarter of 2012, a record for the period and a 37% increase compared to the second quarter of 2011
• Held year-to-date plant operating expense5 essentially flat, despite a 44% increase in generation
• Delivered lowest year-to-date fleetwide forced outage factor on record: 2.0%
• Produced highest year-to-date fleetwide starting reliability on record: 98%
• Achieved best year-to-date safety performance on record

Commercial:

• Cleared approximately 4,200 MW of PJM capacity in 2015/2016 auction
• Signed approximately 900 MW of long-term capacity and energy contracts
• Achieved constructive near-term resolution for Sutter Energy Center, providing a capacity contract for balance of 2012 while engaging broader market reform discussion in California

Capital Structure:

• Repurchased approximately $284 million of our common stock during the second quarter, bringing our cumulative repurchases to $409 million of the $600 million authorized under our program

Calpine Corporation (NYSE: CPN) today reported second quarter 2012 Adjusted EBITDA of $403 million, compared to $406 million in the prior year period, and Adjusted Recurring Free Cash Flow of $87 million, compared to $41 million in the prior year period. Net Loss2 for the second quarter was $329 million, or $0.69 per diluted share, compared to $70 million, or $0.14 per diluted share, in the prior year period. Net Income, As Adjusted3, for the second quarter of 2012 was $14 million compared to Net Loss, As Adjusted3, of $55 million in the prior year period.

The key driver of the increase in Net Loss2 was non-cash, unrealized mark-to-market losses on forward commodity hedges, which also contributed to a year-over-year decline in revenue. The unrealized losses were largely associated with a temporary spike in near-term forward power prices in Texas during the last week of the quarter, which has since subsided, thus substantially mitigating the impact. Meanwhile, these unrealized losses do not account for the potential increase in the economic value of the underlying physical generation, for which offsetting realized gains are expected primarily during the third quarter. Regardless, unrealized mark-to-market gains and losses have always been excluded from Adjusted EBITDA and Net Income (Loss), as Adjusted3, in order to provide a clearer view of realized results, which better represent the operating performance of our company.

Year-to-date 2012 Adjusted EBITDA was $728 million, compared to $709 million in the prior year period, and Adjusted Recurring Free Cash Flow was $60 million, compared to $20 million in the prior year period. Net Loss2 for the first half of 2012 was $338 million, or $0.71 per diluted share, compared to $367 million, or $0.75 per diluted share, in the prior year period. Net Loss, As Adjusted3, for the first half of 2012 was $51 million compared to $165 million in the prior year period.

“Calpine continues to capitalize on the secular shift toward greater utilization of combined-cycle gas turbines in the power generation industry,” said Jack Fusco, Calpine’s President and Chief Executive Officer. “Our versatile fleet generated 56 million MWhs during the first half of 2012, 44% more than last year, as natural gas-fired generation continued to take market share from coal. This increased productivity, coupled with our focus on operational excellence, drove a 30% reduction in our plant operating expenses per MWh for the first half of 2012 and yielded the best year-to-date forced outage factor and starting reliability on record. Similarly, our plant personnel achieved the best year-to-date safety performance on record.

“Natural gas is becoming the power production fuel of choice. According to the Energy Information Administration, during April of 2012, natural gas-fired power generation equaled coal-fired generation in America for the first time ever. Natural gas-fired generation is cheaper, more efficient, more flexible and environmentally cleaner than coal. As the largest operator of combined-cycle gas turbines in the U.S., Calpine stands to benefit as the fundamentals of each of our core wholesale competitive power markets increase the demand and margins for natural gas-fired generation, whether driven by coal retirements in the Eastern U.S., increasing electric demand in Texas or the need for flexible generation to backstop intermittent renewables in California.”

“In addition to the fundamentals of our business driving value, Calpine employs a disciplined capital allocation philosophy to maximize total shareholder return,” said Zamir Rauf, Calpine’s Chief Financial Officer. “Our ability to maintain strong Adjusted Recurring Free Cash Flow, substantial liquidity and a strong balance sheet enables us to evaluate organic growth, M&A and potential divestitures, while retaining the flexibility to return capital to shareholders. All investments must be free cash flow accretive and are measured against repurchasing our own shares. So far in 2012, we have announced $1.3 billion of capital allocation activities, including doubling our share repurchase program to $600 million. During the second quarter, we repurchased approximately 16 million shares of our common stock, bringing our cumulative repurchases to 24.5 million shares. As we decrease the number of shares outstanding, viewing our financial performance on a per-share basis will more accurately reflect our total shareholder return.”

SUMMARY OF FINANCIAL PERFORMANCE

Second Quarter Results

Adjusted EBITDA for the second quarter of 2012 was $403 million compared to $406 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily due to relatively consistent Commodity Margin, offset by a modest increase in plant operating expense5 associated with a favorable property tax settlement recognized in the second quarter of 2011 that did not benefit the current year period. Though comparable year-over-year, Commodity Margin was impacted primarily by:

+ higher generation as a result of increased market opportunities primarily driven by lower natural gas prices and higher spark spreads in the second quarter of 2012 compared to the prior year period, offset by
- lower contribution from hedges and
- lower revenue due to lower regulatory capacity payments and the expiration of contracts subsequent to the second quarter of 2011.

Net Loss2 was $329 million for the second quarter of 2012, compared to $70 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted3, was $14 million in the second quarter of 2012 compared to Net Loss, As Adjusted3, of $55 million in the prior year period. The year-over-year improvement was driven largely by:

+ a decrease in income tax expense as a result of lower state and foreign jurisdiction income taxes due to the increase in pre-tax losses in the current period, and
+ an increase in income from unconsolidated investments, partially offset by
- a modest increase in plant operating expense5, as previously discussed.

Year-to-Date Results

Adjusted EBITDA for the six months ended June 30, 2012, was $728 million compared to $709 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily due to a $30 million increase in Commodity Margin, partially offset by modest increases in plant operating expense5 and sales, general and administrative expenses6. The increase in Commodity Margin was primarily due to:

+ an increase in generation volumes driven primarily by lower natural gas prices and higher spark spreads in the first half of 2012 compared to the prior year period and
+ an extreme cold weather event in Texas in February 2011 that negatively impacted our revenues for the first half of the year, which did not recur in the current year, partially offset by
- lower contribution from hedges and
- lower revenue resulting from lower regulatory capacity payments and contracts that expired subsequent to the first half of 2011.

Net Loss2 decreased to $338 million for the six months ended June 30, 2012, compared to $367 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted3, was $51 million in the six months ended June 30, 2012, compared to $165 million in the prior year period. The year-over-year improvement in Net Loss, As Adjusted3, was driven largely by:

+ higher Commodity Margin, as previously discussed, and
+ lower income tax benefit resulting from a decrease in various state and foreign jurisdiction income taxes in the first half of 2012 compared to the prior year period, due to the decrease in pre-tax losses in the current period.
___________

1 The decline in operating revenues was affected by $(302) million and $(280) million of unrealized mark-to-market losses in the three and six months ended June 30, 2012, respectively, and $60 million and $35 million of unrealized mark-to-market gains in the three and six months ended June 30, 2011, respectively.

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

3 Refer to Table 1 for further detail of Net Income (Loss), As Adjusted.

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

5 Increase 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 and six months ended June 30, 2012 and 2011.

6 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 six months ended June 30, 2012 and 2011.

Table 1: Net Income (Loss), As Adjusted

			Three Months Ended June 30,										Six Months Ended June 30,
			2012					2011					2012					2011
			(in millions)
Net loss attributable to Calpine			$	(329	)			$	(70	)			$	(338	)			$	(367	)
Debt extinguishment costs(1)			-					5					12					98
Unrealized MtM (gain) loss on derivatives(1) (2)			343					(50		)			119					77
Other items (1) (3)			-					60					156					27
Net Income (Loss), As Adjusted(4)			$	14				$	(55	)			$	(51	)			$	(165	)

__________

(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 and six months ended June 30, 2012, respectively, and $60 million and $103 million for the three and six months ended June 30, 2011, respectively. Other items for the six months ended June 30, 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 Income (Loss), As Adjusted.

REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin by Segment (in millions)

			Three Months Ended June 30,														Six Months Ended June 30,
			2012					2011					Variance				2012					2011					Variance
West			$	210				$	236				(26	)			$	418				$	469				(51	)
Texas			145					128					17					254					195				59
North			181					184					(3	)				325					319				6
Southeast			73					59					14					129					113				16
Total			$	609				$	607				2				$	1,126				$	1,096				30

West Region

Second Quarter: Commodity Margin in our West segment decreased by $26 million in the second 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
+ increased generation due to lower hydroelectric generation and a nuclear power plant outage in California, which resulted in higher spark spreads in the second quarter of 2012 compared to the prior year period.

Year-to-Date: Commodity Margin in our West segment decreased by $51 million for the six months ended June 30, 2012, compared to the prior year period. Primary drivers were:

- lower contribution from hedges
- lower revenue due to the expiration of contracts and
- lower Commodity Margin associated with our Sutter Energy Center, which did not run in the first half of 2012, partially offset by
+ increased generation due to lower hydroelectric generation and a nuclear power plant outage in California, which resulted in higher spark spreads in the first half of 2012 compared to the prior year period.

Texas Region

Second Quarter: Commodity Margin in our Texas segment increased by $17 million in the second quarter of 2012 compared to the prior year period. The primary driver was:

+ increased generation driven by increased market opportunities for our combined-cycle natural gas-fired power plants driven by lower natural gas prices and higher spark spreads.

Year-to-Date: Commodity Margin in our Texas segment increased by $59 million for the six months ended June 30, 2012, compared to the prior year period. Primary drivers were:

+ higher generation driven by increased market opportunities primarily due to lower natural gas prices and higher spark spreads
+ increase in Commodity Margin earned during overnight periods related to the must-run obligations of certain of our cogeneration power plants and
+ an extreme cold weather event in Texas in February 2011 that negatively impacted our revenues for the first half of the prior year, which did not recur in the current year, partially offset by
- lower super-peak power prices resulting from milder weather conditions during much of the first half of 2012 compared to the prior year period.

North Region

Second Quarter: Commodity Margin in our North segment decreased by $3 million in the second quarter of 2012 compared to the prior year period. Primary drivers were:

- lower regulatory capacity revenues, partially offset by
+ higher generation driven by increased market opportunities due to higher off-peak spark spreads in the second quarter of 2012 compared to the prior year period and
+ a PPA associated with our York Energy Center that became effective in June 2011.

Year-to-Date: Commodity Margin in our North segment increased by $6 million in the six months ended June 30, 2012, compared to the prior year period. Primary drivers were:

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

Southeast Region

Second Quarter: Commodity Margin in our Southeast segment increased by $14 million in the second quarter of 2012 compared to the prior year period. Primary drivers were:

+ higher generation driven by increased market opportunities primarily due to lower natural gas prices and higher spark spreads, partially offset by
- lower revenues resulting from the expiration of a PPA subsequent to the second quarter of 2011.

Year-to-Date: Commodity Margin in our Southeast segment increased by $16 million in the six months ended June 30, 2012, compared to the prior year period. The year-to-date results were largely impacted by the same factors that drove comparative performance for the second quarter, as previously discussed.

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Liquidity

			June 30,					December 31,
			2012					2011
			(in millions)
Cash and cash equivalents, corporate(1)			$	409				$	946
Cash and cash equivalents, non-corporate			178					306
Total cash and cash equivalents(2)			587					1,252
Restricted cash			175					194
Corporate Revolving Facility availability			615					560
Letter of credit availability(3)			44					7
Total current liquidity availability			$	1,421				$	2,013

__________

(1) Includes $45 million and $34 million of margin deposits held by us posted by our counterparties at June 30, 2012, and December 31, 2011, respectively.

(2) Cash and cash equivalents decreased primarily resulting from $290 million in share repurchases, $156 million in payments to terminate our legacy interest rate swaps formerly hedging our First Lien Credit Facility and a $111 million increase in margin deposits in support of derivative contracts driven by the impact of a near term increase in forward power prices and corresponding market heat rate expansion in the ERCOT region.

(3) 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 at the end of the second quarter of 2012 was $1.4 billion. The decrease experienced during the first half of the year was largely due to $290 million in share repurchases, $156 million in payments to terminate our legacy interest rate swaps and a $111 million temporary increase in margin deposits in support of derivative contracts utilized in hedging our asset portfolio. Capital expenditures totaling $369 million were primarily funded by borrowings under our construction project financings, which did not impact liquidity, and cash flows from operations.

Cash flows from operating activities for the six months ended June 30, 2012, resulted in net outflows of $32 million compared to net inflows of $239 million in the prior year period. The decrease in cash provided by operating activities was primarily the result of an increase in working capital employed due to increased margin deposits required as a result of a near term increase in forward power prices and corresponding market heat rate expansion in the ERCOT region during the last several days of June 2012.

Cash flows used in investing activities were $513 million for the six months ended June 30, 2012, compared to $421 million in the prior year period, 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 used in financing activities were $120 million for the six months ended June 30, 2012, and were primarily related to the payments we made under our share repurchase program, offset by the receipt of proceeds from project financings related to our Russell City and Los Esteros construction projects. In addition, we incurred lower financing costs and lower repayments on project debt due in part to the refinancing activities we completed in the first half of 2011.

Adjusted Recurring Free Cash Flow was $60 million for the six months ended June 30, 2012, compared to $20 million for the prior year period. Adjusted Recurring Free Cash Flow increased during the period primarily due to a $19 million increase in Adjusted EBITDA. Lower maintenance capital expenditures related to our plant outage schedule and lower interest payments further contributed to the increase compared to the prior year period.

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 24.5 million shares of our outstanding common stock have been repurchased under this program for approximately $409 million at an average price of $16.65 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: 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. Upon completion, the Russell City Energy Center is contracted to deliver its full output to PG&E under a 10-year PPA. Construction is ongoing and COD is expected during the summer of 2013.

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 during the summer 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 as well as equipment and construction commitments and expect COD in summer 2014 for these expansions. We 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 lease option with the City of Dover. For the first phase (309 MW), PJM has completed a feasibility study and a system impact study and is currently conducting a facility study. For the second phase (309 MW), a feasibility study has been completed and a system impact study is ongoing. 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 expect to receive the air permit in the fourth quarter of 2012 and expect COD for the first phase by the summer of 2015. We are currently evaluating funding sources including but not limited to nonrecourse financing, corporate financing or internally generated funds.

All Segments:

Turbine Upgrades: We continue to move forward with our turbine upgrade program. Through June 30, 2012, we have completed the upgrade of eleven Siemens and eight GE turbines totaling over 200 MW and have agreed to upgrade approximately three additional turbines (and may upgrade additional turbines in the future).

OPERATIONS UPDATE

Second Quarter 2012 Power Operations Achievements:

Safety Performance:
- Maintained stellar safety metrics, recording only one lost-time incident year to date
Availability Performance:
- Delivered lowest first half fleetwide forced outage factor on record: 2.0%
- Maintained impressive second quarter fleetwide starting reliability: 98%
Cost Performance:
- Held year-to-date plant operating expense7 essentially flat, despite a 44% increase in generation, resulting in a 30% improvement on a per-MWh basis
Geothermal Generation:
- Provided approximately 1.5 million MWh of renewable baseload generation with a record 0.14% forced outage factor during the second quarter of 2012
Natural Gas-fired Generation:
- Increased combined-cycle capacity factor in the first six months of 2012 to 52% compared to 35% in the prior year period
- Magic Valley Generation Station: 91% capacity factor for the entire second quarter of 2012
- Decatur Energy Center: 100% starting reliability, 0.00% forced outage factor
Second Quarter 2012 Commercial Operations Achievements:

Customer-oriented Growth:
- 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 (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
__________

7 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 six months ended June 30, 2012 and 2011.

FINANCIAL OUTLOOK

			Full Year 2012
			(in millions)
Adjusted EBITDA			$	1,700 – 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				5
Adjusted Recurring Free Cash Flow			$	500 – 600
Non-recurring interest rate swap payments(4)			$	(156	)
Growth capital expenditures (net of debt funding)			$	(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.

As detailed above, today we are tightening our 2012 guidance. We now project Adjusted EBITDA of $1,700 million to $1,800 million and Adjusted Recurring Free Cash Flow of $500 million to $600 million. We also expect to invest $100 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, as well as our ongoing turbine upgrade program. (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.) 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 purchase of our Riverside Energy Center.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results for the second quarter of 2012 on Friday, July 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 U.S. or (847) 413-3238 outside the U.S. The confirmation code is 32797758. 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 32797758. Presentation materials to accompany the conference call will be available on our website on July 27, 2012.

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 June 30, 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, regulations 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;
• 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 June 30,										Six Months Ended June 30,
			2012					2011					2012					2011
			(in millions, except share and per share amounts)
Operating revenues			$	879				$	1,633				$	2,115				$	3,132
Operating expenses:
Fuel and purchased energy expense			612					1,000						1,244					2,069
Plant operating expense			271					261						492					499
Depreciation and amortization expense			138					131						278					262
Sales, general and other administrative expense			35					34						68					66
Other operating expenses			21					22						45					42
Total operating expenses			1,077					1,448						2,127					2,938
(Income) loss from unconsolidated investments in power plants			(5		)			2						(14	)				(7	)
Income (loss) from operations			(193		)			183						2					201
Interest expense			184					192						369					383
Loss on interest rate derivatives			-					37						14					146
Interest (income)			(2		)			(2		)				(5	)				(5	)
Debt extinguishment costs			-					5						12					98
Other (income) expense, net			6					3						8					10
Loss before income taxes			(381		)			(52		)				(396	)				(431	)
Income tax expense (benefit)			(52		)			18						(58	)				(65	)
Net loss			(329		)			(70		)				(338	)				(366	)
Net income attributable to the noncontrolling interest			-					-						-					(1	)
Net loss attributable to Calpine			$	(329	)			$	(70	)			$	(338	)			$	(367	)
Basic and diluted loss per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)			471,444					486,411					474,775					486,334
Net loss per common share attributable to Calpine – basic and diluted			$	(0.69	)			$	(0.14	)			$	(0.71	)			$	(0.75	)

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)
			June 30,					December 31,
			2012					2011
			(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents			$	587				$	1,252
Accounts receivable, net of allowance of $14 and $13			532					598
Margin deposits and other prepaid expense			305					193
Restricted cash, current			124					139
Derivative assets, current			1,049					1,051
Inventory and other current assets			337					329
Total current assets			2,934					3,562
Property, plant and equipment, net			13,109					13,019
Restricted cash, net of current portion			51					55
Investments			76					80
Long-term derivative assets			158					113
Other assets			559					542
Total assets			$	16,887				$	17,371
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable			$	353				$	435
Accrued interest payable			200					200
Debt, current portion			103					104
Derivative liabilities, current			1,243					1,144
Other current liabilities			274					279
Total current liabilities			2,173					2,162
Debt, net of current portion			10,488					10,321
Long-term derivative liabilities			276					279
Other long-term liabilities			247					245
Total liabilities			13,184					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, 492,024,794 and 490,468,815 shares issued, respectively, and 466,615,007 and 481,743,738 shares outstanding, respectively			1					1
Treasury stock, at cost, 25,409,787 and 8,725,077 shares, respectively			(420		)			(125		)
Additional paid-in capital			12,320					12,305
Accumulated deficit			(8,037		)			(7,699		)
Accumulated other comprehensive loss			(223		)			(178		)
Total Calpine stockholders’ equity			3,641					4,304
Noncontrolling interest			62					60
Total stockholders’ equity			3,703					4,364
Total liabilities and stockholders’ equity			$	16,887				$	17,371

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
			Six Months Ended June 30,
			2012					2011
			(in millions)
Cash flows from operating activities:
Net loss			$	(338	)			$	(366	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization expense(1)			299					279
Debt extinguishment costs			-					85
Deferred income taxes			(31		)			(90		)
Loss on disposition of assets			4					9
Unrealized mark-to-market activities, net			119					77
(Income) from unconsolidated investments in power plants			(14		)			(7		)
Return on unconsolidated investments in power plants			16					6
Stock-based compensation expense			13					12
Other			1					5
Change in operating assets and liabilities:
Accounts receivable			63					(68		)
Derivative instruments, net			(111		)			(29		)
Other assets			(122		)			58
Accounts payable and accrued expenses			(86		)			166
Settlement of non-hedging interest rate swaps			156					103
Other liabilities			(1		)			(1		)
Net cash provided by (used in) operating activities			(32		)			239
Cash flows from investing activities:
Purchases of property, plant and equipment			(369		)			(341		)
Settlement of non-hedging interest rate swaps			(156		)			(103		)
Decrease in restricted cash			19					30
Purchases of deferred transmission credits			(12		)			(8		)
Other			5					1
Net cash used in investing activities				(513	)				(421	)
Cash flows from financing activities:
Repayment of Term Loans				(8	)				-
Borrowings under First Lien Term Loans			-					1,657
Repayments on NDH Project Debt			-					(1,283		)
Issuance of 2023 First Lien Notes			-					1,200
Repayments on First Lien Credit Facility			-					(1,187		)
Borrowings from project financing, notes payable and other			226					69
Repayments of project financing, notes payable and other			(46		)			(419		)
Capital contributions from noncontrolling interest holder			-					34
Financing costs			(5		)			(67		)
Stock repurchases			(290		)			-
Other			3					(2		)
Net cash provided by (used in) financing activities			(120		)			2
Net decrease in cash and cash equivalents			(665		)			(180		)
Cash and cash equivalents, beginning of period			1,252					1,327
Cash and cash equivalents, end of period			$	587				$	1,147
Cash paid during the period for:
Interest, net of amounts capitalized			$	352				$	292
Income taxes			$	13				$	12
Supplemental disclosure of non-cash investing activities:
Change in capital expenditures included in accounts payable			$	3				$	21

__________

^{(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 Income (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 Income (Loss), As Adjusted, represents net income (loss) attributable toCalpine, 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 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 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 endedJune 30, 2012and 2011 (in millions):

			Three Months Ended June 30, 2012
																									Consolidation
																									And
			West					Texas							North					Southeast					Elimination					Total
Commodity Margin(1)			$	210				$	145						$	181				$	73				$	-				$	609
Add: Mark-to-market commodity activity, net and other(2)(3)			(76		)			(217			)				(3		)			(42		)			(6		)			(344		)
Less:
Plant operating expense			112					72							58					36					(7		)			271
Depreciation and amortization expense			49					34							34					22					(1		)			138
Sales, general and other administrative expense			6					13							8					7					1					35
Other operating expenses(4)			9					1							6					2					1					19
(Income) from unconsolidated investments in power plants			-					-							(5		)			-					-					(5		)
Income (loss) from operations			$	(42	)			$	(192		)				$	77				$	(36	)			$	-				$	(193	)
			Three Months Ended June 30, 2011
																									Consolidation
																									And
			West						Texas						North					Southeast					Elimination					Total
Commodity Margin(1)			$	236					$	128					$	184				$	59				$	-				$	607
Add: Mark-to-market commodity activity, net and other(2)(3)			11						27						(5		)			-					(9		)			24
Less:
Plant operating expense			116						63						47					41					(6		)			261
Depreciation and amortization expense			42						35						33					22					(1		)			131
Sales, general and other administrative expense			8						13						6					6					1					34
Other operating expenses(4)			11						3						9					2					(5		)			20
Loss from unconsolidated investments in power plants			-						-						2					-					-					2
Income (loss) from operations			$	70					$	41					$	82				$	(12	)			$	2				$	183

The following table reconciles our Commodity Margin to its U.S. GAAP results for the six months endedJune 30, 2012and 2011 (in millions):

			Six Months Ended June 30, 2012
																							Consolidation
																							And
			West					Texas					North					Southeast					Elimination					Total
Commodity Margin(1)			$	418				$	254				$	325				$	129				$	-				$	1,126
Add: Mark-to-market commodity activity, net and other(2)(5)			(40		)			(183		)			9					(32		)			(14		)			(260		)
Less:
Plant operating expense			193					140					103					69					(13		)			492
Depreciation and amortization expense			99					69					67					45					(2		)			278
Sales, general and other administrative expense			14					24					14					15					1					68
Other operating expenses(4)			20					3					15					3					(1		)			40
(Income) from unconsolidated investments in power plants			-					-					(14		)			-					-					(14		)
Income (loss) from operations			$	52				$	(165	)			$	149				$	(35	)			$	1				$	2
			Six Months Ended June 30, 2011
																							Consolidation
																							And
			West					Texas					North					Southeast					Elimination					Total
Commodity Margin(1)			$	469				$	195				$	319				$	113				$	-				$	1,096
Add: Mark-to-market commodity activity, net and other(2)(5)			16					(33		)			(1		)			(4		)			(15		)			(37		)
Less:
Plant operating expense			203					143					92					74					(13		)			499
Depreciation and amortization expense			88					65					66					45					(2		)			262
Sales, general and other administrative expense			19					23					12					11					1					66
Other operating expenses(4)			19					3					16					3					(3		)			38
(Income) from unconsolidated investments in power plants			-					-					(7		)			-					-					(7		)
Income (loss) from operations			$	156				$	(72	)			$	139				$	(24	)			$	2				$	201

__________

^{(1) Our North segment includes Commodity Margin related to Riverside Energy Center, LLC of $24 million and $22 million for three months ended June 30, 2012 and 2011, respectively, and $32 million and $31 million for the six months ended June 30, 2012 and 2011, respectively.}

^{(2) Mark-to-market commodity activity represents the change in 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. The increase in unrealized mark-to-market losses for the three and six months ended June 30, 2012, was primarily driven by the impact of a near term increase in forward power prices and corresponding Market Heat Rate expansion in the ERCOT region during the last several days of June 2012.}

^{(3) Includes $(1) million and $4 million of lease levelization and $3 million and $1 million of amortization expense for the three months ended June 30, 2012 and 2011, respectively.}

^{(4) Excludes $2 million of RGGI compliance and other environmental costs for both the three months ended June 30, 2012 and 2011, and $5 million and $4 million for the six months ended June 30, 2012 and 2011, respectively, which are components of Commodity Margin.}

^{(5) Includes $(9) million and $4 million of lease levelization and $7 million and $1 million of amortization expense for the six months ended June 30, 2012 and 2011, respectively.}

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 toCalpinefor the three and six months endedJune 30, 2012and 2011, as reported under U.S. GAAP.

			Three Months Ended June 30,										Six Months Ended June 30,
			2012					2011					2012					2011
			(in millions)
Net loss attributable to Calpine			$	(329	)			$	(70	)			$	(338	)			$	(367	)
Net income attributable to the noncontrolling interest			-					-					-					1
Income tax expense (benefit)			(52		)			18					(58		)			(65		)
Debt extinguishment costs and other (income) expense, net			6					8					20					108
Loss on interest rate derivatives			-					37					14					146
Interest expense, net			182					190					364					378
Income from operations			$	(193	)			$	183				$	2				$	201
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)			138					131					279					263
Major maintenance expense			81					76					127					136
Operating lease expense			8					9					17					17
Unrealized (gain) loss on commodity derivative mark-to-market activity			346					(26		)			268					39
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3)			9					13					16					21
Stock-based compensation expense			7					7					13					12
Loss on dispositions of assets			2					4					4					9
Acquired contract amortization			3					1					7					1
Other			2					8					(5		)			10
Total Adjusted EBITDA			$	403				$	406				$	728				$	709
Less:
Lease payments			8					9					17					17
Major maintenance expense and capital expenditures(4)			109					152					255					263
Cash interest, net(5)			190					195					381					393
Cash taxes			7					6					11					10
Other			2					3					4					6
Adjusted Recurring Free Cash Flow(6)			$	87				$	41				$	60				$	20
Weighted average shares of common stock outstanding (diluted, in thousands)			471,444					486,411					474,775					486,334
Adjusted Recurring Free Cash Flow Per Share			$	0.19				$	0.08				$	0.13				$	0.04

_________

^{(1) Depreciation and amortization expense in the income (loss) 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) loss 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 and six months ended June 30, 2012 and 2011.}

^{(4) Includes $84 million and $131 million in major maintenance expense for the three months and six months ended June 30, 2012, respectively, and $25 million and $124 million in maintenance capital expenditures for the three months and six months ended June 30, 2012, respectively. Includes $80 million and $138 million in major maintenance expense for the three months and six months ended June 30, 2011, respectively, and $72 million and $125 million in maintenance capital expenditures for the three months and six months ended June 30, 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 increase in working capital of $56 million and decrease in working capital of $20 million for the three months and six months ended June 30, 2012, respectively, and a decrease in working capital of $45 million and $145 million for the three months and six months ended June 30, 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 and six months endedJune 30, 2012and 2011. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above.

			Three Months Ended June 30,										Six Months Ended June 30,
			2012					2011					2012					2011
			(in millions)
Commodity Margin			$	609				$	607				$	1,126				$	1,096
Other revenue			3					3					6					7
Plant operating expense(1)			(181		)			(176		)			(351		)			(346		)
Sales, general and administrative expense(2)			(30		)			(27		)			(60		)			(55		)
Other operating expense(3)			(10		)			(10		)			(21		)			(19		)
Adjusted EBITDA from unconsolidated investments in power plants(4)			14					10					30					27
Other			(2		)			(1		)				(2	)			(1		)
Adjusted EBITDA			$	403				$	406				$	728				$	709

_________

^{(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) Shown net of operating lease expense, amortization and RGGI compliance and other environmental 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 Recurring Free Cash Flow Reconciliation for Guidance

Full Year 2012 Range:			Low					High
			(in millions)
GAAP Net Income (Loss)(1)			$	-				$	100
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)			104					104
Adjusted EBITDA			$	1,700				$	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			5					5
Adjusted Recurring Free Cash Flow			$	500				$	600
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 June 30,								Six Months Ended June 30,
			2012				2011				2012				2011
Total MWh generated (in thousands)(1)			26,681				19,394				54,736				37,521
West			6,191				3,454				14,394				9,649
Texas			9,089				7,867				18,232				13,186
Southeast			6,201				4,286				11,923				8,571
North			5,200				3,787				10,187				6,115
Average availability			86.4	%			84.8	%			88.4	%			86.8	%
West			81.6	%			75.9	%			87.6	%			83.9	%
Texas			88.3	%			89.1	%			87.0	%			84.3	%
Southeast			90.8	%			85.3	%			92.5	%			89.8	%
North			85.4	%			88.4	%			87.3	%			89.7	%
Average capacity factor, excluding peakers			51.0	%			37.6	%			53.0	%			37.2	%
West			45.0	%			25.3	%			52.7	%			35.7	%
Texas			59.3	%			51.6	%			59.6	%			43.5	%
Southeast			51.8	%			36.0	%			50.3	%			37.0	%
North			45.6	%			34.6	%			46.4	%			29.6	%
Steam adjusted heat rate (mmbtu/kWh)			7,391				7,451				7,329				7,411
West			7,366				7,755				7,233				7,495
Texas			7,150				7,204				7,115				7,224
Southeast			7,309				7,322				7,291				7,310
North			7,991				7,985				7,903				7,888

________

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

Source: Calpine

For more information on: Calpine