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Calpine Reports Second Quarter 2013 Results,
Reaffirms 2013 Adjusted Free Cash Flow Per Share Guidance,
Tightens 2013 Adjusted EBITDA and Free Cash Flow Guidance Ranges

07/25/2013

Summary of Second Quarter 2013 Financial Results (in millions, except per share amounts):

Three Months Ended June 30, Six Months Ended June 30,
2013 2012 % Change 2013 2012 % Change
Operating Revenues $ 1,572 $ 879 78.8 % $ 2,813 $ 2,115 33.0 %
Commodity Margin $ 533 $ 609 (12.5 )% $ 994 $ 1,126 (11.7 )%
Adjusted EBITDA $ 343 $ 403 (14.9 )% $ 629 $ 728 (13.6 )%
Adjusted Free Cash Flow $ 38 $ 87 (56.3 )% $ (5 ) $ 60 (108.3 )%
Per Share (diluted) $ 0.08 $ 0.19 (57.9 )% $ (0.01 ) $ 0.13 (107.7 )%
Net Loss1 $ (70 ) $ (329 ) $ (195 ) $ (338 )
Per Share (diluted) $ (0.16 ) $ (0.69 ) $ (0.43 ) $ (0.71 )
Net Income (Loss), As Adjusted2 $ (33 ) $ 14 $ (103 ) $ (51 )

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

Prior Guidance (as of May 2, 2013) Current Guidance
Adjusted EBITDA $1,800 - 1,960 $1,800 - 1,875
Adjusted Free Cash Flow $615 - 775 $640 - 715
Per Share Estimate (diluted) $1.50 $1.50

Recent Achievements:

  • Operations:
    — Generated approximately 23 million MWh3 of electricity in the second quarter of 2013
    — Achieved record-low second quarter fleetwide forced outage factor: 1.6%
    — Delivered exceptional second quarter fleetwide starting reliability: 99%
  • Commercial:
    — Entered into three-year PPA with South Carolina Electric and Gas to provide 200 MW of power from our Columbia Energy Center commencing in January 2014
    — Entered into two new resource adequacy contracts with Pacific Gas and Electric Company for our Delta and Sutter Energy Centers for the full capacity of each plant, commencing in January and June 2014, respectively
    — Entered into two new contracts with Marin Energy Authority to provide up to 10 MW of renewable power from our Geysers assets
  • Capital Management:
    — Completed $400 million share repurchase authorization, bringing the cumulative total of shares repurchased to $1 billion, or approximately 11% of our outstanding shares4
    — Refinanced our CCFC notes and Corporate Revolver, providing material interest savings and extending maturities

HOUSTON – (BUSINESS WIRE) – Jul. 25, 2013 – Calpine Corporation (NYSE: CPN) today reported second quarter 2013 Adjusted EBITDA of $343 million, compared to $403 million in the prior year period, and Adjusted Free Cash Flow of $38 million, or $0.08 per diluted share, compared to $87 million, or $0.19per diluted share, in the prior year period. Net Loss1 for the second quarter of 2013 was $70 million, or$0.16 per diluted share, compared to $329 million, or $0.69 per diluted share, in the prior year period. Net Loss, As Adjusted2, for the second quarter of 2013 was $33 million compared to Net Income, As Adjusted2, of $14 million in the prior year period. The declines in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted2, in the second quarter of 2013 compared to the prior year period were driven primarily by lower Commodity Margin, largely as a result of changes in our portfolio, milder weather and lower generation due to the reversal in 2013 of the coal-to-gas switching that we benefited from during the first half of 2012.

Year-to-date 2013 Adjusted EBITDA was $629 million, compared to $728 million in the prior year period, and Adjusted Free Cash Flow was $(5) million, or $(0.01) per diluted share, compared to $60 million, or$0.13 per diluted share, in the prior year period. Net Loss1 for the first half of 2013 was $195 million, or$0.43 per diluted share, compared to $338 million, or $0.71 per diluted share, in the prior year period. Net Loss, As Adjusted2, for the first half of 2013 was $103 million compared to $51 million in the prior year period. The declines in year-to-date 2013 Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted2, compared to the prior year period were primarily due to the same factors that drove comparative performance for the second quarter, as previously discussed.

“We remain steadfastly focused on positioning Calpine to take advantage of the secular shift in the U.S. power generation industry to clean, efficient and dispatchable combined-cycle gas turbines,” said Jack Fusco , Calpine’s Chief Executive Officer.

“Today, we are reaffirming our Adjusted Free Cash Flow Per Share guidance of $1.50 for 2013, despite challenging market conditions during the first half of this year. Our second quarter and year-to-date results reflect milder weather this year, as well as the sale of two contracted power plants late last year. We expect these headwinds to be offset during the balance of the year by higher regulatory capacity revenues in PJM, the commencement of operations at our two new contracted plants in California and the acquisition of Bosque Energy Center in Texas. Our hedge position in the second half of the year also allows us to benefit from any improved conditions in our markets.

“Meanwhile, we continue to proactively enhance shareholder value through commercial origination and capital allocation. We recently signed new multiyear capacity contracts for 1,645 MW in California and the Southeast as we continue to identify solutions for our customers. In addition, we expect to bring approximately 900 MW of contracted capacity on-line in California during the third quarter. Construction is also advancing on our two expansion projects in Texas with in-service expected next summer, and we recently broke ground on our new 309 MW plant in Delaware. Finally, we recently completed our $1 billionof share repurchase authorizations, demonstrating our commitment to returning capital to our shareholders.”

SUMMARY OF FINANCIAL PERFORMANCE

Second Quarter Results

Adjusted EBITDA for the second quarter of 2013 was $343 million, compared to $403 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily due to a $76 milliondecrease in Commodity Margin, partially offset by a $15 million decrease in plant operating expense5. The decrease in Commodity Margin was primarily due to:

the sale of Broad River and Riverside Energy Centers, partially offset by the acquisition of Bosque Energy Center in the fourth quarter of 2012
weaker market conditions due to milder weather, an increase in wind generation in Texas and higher natural gas prices primarily in our Texas, North and Southeast segments in the second quarter of 2013 compared to the prior year period and
lower contribution from hedges, partially offset by
+ higher regulatory capacity revenue in the North and
+ higher revenue from a tolling contract in our West segment that became effective in January 2013.

The offsetting decrease in plant operating expense5 was primarily due to lower equipment failure costs and other miscellaneous expenses.

Net Loss1 was $70 million for the second quarter of 2013, compared to a Net Loss1 of $329 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted2, was $33 million in the second quarter of 2013 compared to Net Income, As Adjusted2, of $14 million in the prior year period. The year-over-year decline was driven largely by:

lower Commodity Margin, as previously discussed, partially offset by
+ lower plant operating expense, as previously discussed, and
+ lower interest expense associated with a decrease in our annual effective interest rate as a result of the refinancing activities completed during the fourth quarter of 2012 and first half of 2013.

Adjusted Free Cash Flow was $38 million in the second quarter of 2013 compared to $87 million in the prior year period. Adjusted Free Cash Flow decreased during the period primarily due to a decrease in Adjusted EBITDA, as previously discussed. Partially offsetting this decline was lower interest expense, as previously discussed.

Year-to-Date Results

Adjusted EBITDA for the six months ended June 30, 2013, was $629 million compared to $728 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily due to a $132 million decrease in Commodity Margin, partially offset by a $31 million decrease in plant operating expense5. The decrease in Commodity Margin was primarily due to:

the sale of Broad River and Riverside Energy Centers, partially offset by the acquisition of Bosque Energy Center in the fourth quarter of 2012
weaker market conditions due to milder weather, an increase in wind generation in Texas and higher natural gas prices primarily in our Texas, North and Southeast segments in the first half of 2013 compared to the prior year period and
lower contribution from hedges, partially offset by
+ higher regulatory capacity revenue in the North and
+ higher revenue from a tolling contract in our West segment that became effective in January 2013.

The offsetting decrease in plant operating expense5 was primarily due to the reversal of previously recognized regulatory fees for which we determined that we have no obligation, as well as lower equipment failure costs.

Net Loss1 was $195 million for the six months ended June 30, 2013, compared to $338 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted2, was $103 million in the six months ended June 30, 2013, compared to $51 million in the prior year period. The year-over-year change in Net Loss, As Adjusted2, was driven largely by:

lower Commodity Margin, as previously discussed, and
higher depreciation and amortization expense primarily resulting from our acquisition of our Bosque Energy Center, partially offset by
+ an increase in various state and foreign jurisdiction income tax benefits and
+ lower interest expense associated with a decrease in our annual effective interest rate, as previously discussed.

Adjusted Free Cash Flow was $(5) million for the six months ended June 30, 2013, compared to $60 million in the prior year period. Adjusted Free Cash Flow decreased during the period primarily due to the same factors that drove comparative performance for the second quarter, as previously discussed.

__________

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

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

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

4 Based upon shares outstanding (including shares held in reserve) as of June 30, 2011, immediately prior to the initial announcement of the repurchase program.

5 Decrease 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 and six months ended June 30, 2013 and 2012.

Table 1: Net Income (Loss), As Adjusted

Three Months Ended June 30, Six Months Ended June 30,
2013 2012 2013 2012
(in millions) (in millions)
Net loss attributable to Calpine $ (70 ) $ (329 ) $ (195 ) $ (338 )
Debt extinguishment costs(1) 68 68 12
Unrealized MtM (gain) loss on derivatives(1) (2) (31 ) 343 24 119
Other items(1) (3) 156
Net Income (Loss), As Adjusted(4) $ (33 ) $ 14 $ (103 ) $ (51 )

__________

(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.

(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,
2013 2012 Variance 2013 2012 Variance
West $ 198 $ 210 $ (12 ) $ 400 $ 418 $ (18 )
Texas 133 145 (12 ) 209 254 (45 )
North 159 181 (22 ) 301 325 (24 )
Southeast 43 73 (30 ) 84 129 (45 )
Total $ 533 $ 609 $ (76 ) $ 994 $ 1,126 $ (132 )

West Region

Second Quarter: Commodity Margin in our West segment decreased by $12 million in the second quarter of 2013 compared to the prior year period. Primary drivers were:

lower contribution from hedges, partially offset by
+ higher revenue from a tolling contract and
+ higher spark spreads on increased generation driven by improved market conditions associated with lower hydroelectric generation, warmer weather and the implementation of the AB32 carbon market.

Year-to-Date: Commodity Margin in our West segment decreased by $18 million for the six months endedJune 30, 2013, 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.

Texas Region

Second Quarter: Commodity Margin in our Texas segment decreased by $12 million in the second quarter of 2013 compared to the prior year period. Primary drivers were:

lower spark spreads resulting from milder weather and an increase in wind generation and
lower generation output resulting from a reversal of coal-to-gas switching due to higher natural gas prices, partially offset by
+ higher contribution from hedges and
+ the acquisition of Bosque Energy Center in November 2012.

Year-to-Date: Commodity Margin in our Texas segment decreased by $45 million for the six months ended June 30, 2013, 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.

North Region

Second Quarter: Commodity Margin in our North segment decreased by $22 million in the second quarter of 2013 compared to the prior year period. Primary drivers were:

the sale of Riverside Energy Center in December 2012 and
lower spark spreads and lower generation output resulting from a reversal of coal-to-gas switching due to higher natural gas prices, partially offset by
+ higher regulatory capacity revenues.

Year-to-Date: Commodity Margin in our North segment decreased by $24 million for the six months endedJune 30, 2013, 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.

Southeast Region

Second Quarter: Commodity Margin in our Southeast segment decreased by $30 million in the second quarter of 2013 compared to the prior year period. Primary drivers were:

the sale of Broad River Energy Center in December 2012 and
lower spark spreads and lower generation output resulting from milder weather and a reversal of coal-to-gas switching due to higher natural gas prices.

Year-to-Date: Commodity Margin in our Southeast segment decreased by $45 million in the six months ended June 30, 2013, 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, CASH FLOW AND CAPITAL RESOURCES

Table 3: Liquidity

June 30,

December 31,

2013

2012
(in millions)
Cash and cash equivalents, corporate(1) $ 588 $ 1,153
Cash and cash equivalents, non-corporate 127 131
Total cash and cash equivalents 715 1,284
Restricted cash 198 253
Corporate Revolving Facility availability 760 757
CDHI letter of credit availability(2)
Total current liquidity availability $ 1,673 $ 2,294

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(1) Includes $3 million and $11 million of margin deposits posted with us by our counterparties at June 30, 2013, and December 31, 2012, respectively.

(2) As a result of the completion of the sale of Riverside Energy Center, LLC, a wholly owned subsidiary of CDHI, onDecember 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 June 30, 2013, we had $18 million in outstanding letters of credit issued in excess of $225 million under our CDHI letter of credit facility that were collateralized by cash. We do not believe that this change will have a material impact on our liquidity.

Liquidity was approximately $1.7 billion as of June 30, 2013. Cash and cash equivalents declined during the first half of the year due largely to our deployment of capital, including the repurchase of $362 million of our common stock, the funding of $143 million in construction payments related to our Garrison Energy Center and the expansion of our Deer Park and Channel Energy Centers, as well as other seasonal variations in working capital which cause fluctuations in our cash and cash equivalents.

Table 4: Cash Flow Activities

Six Months Ended June 30,
2013 2012
Beginning cash and cash equivalents $ 1,284 $ 1,252
Net cash used in:
Operating activities (175 ) (32 )
Investing activities (281 ) (513 )
Financing activities (113 ) (120 )
Net decrease in cash and cash equivalents (569 ) (665 )
Ending cash and cash equivalents $ 715 $ 587

Cash flows from operating activities in the six months ended June 30, 2013, resulted in net outflows of$175 million compared to $32 million in the prior year period. The increase in outflows was primarily due to a decrease in income from operations as well as an increase in working capital employed, primarily as a result of higher net accounts receivable balances related to relatively higher prices for both gas and power across all regions. Also contributing to the change in net outflows, debt extinguishment costs were higher in the first half of 2013 due to payments associated with the redemption of our CCFC notes. These decreases in cash flows from operating activities were partially offset by less cash paid for interest due to the refinancing activities of the fourth quarter of 2012 and first half of 2013.

Cash flows used in investing activities during the six months ended June 30, 2013, were $281 millioncompared to $513 million in the prior year period. The decrease in outflows was primarily due to $156 million in non-hedging interest rate swap settlements paid in the prior year period that did not recur this year, as well as a larger decrease in restricted cash in the first half of 2013 compared to the first half of 2012, primarily due to a release of cash collateral related to lower exposure on letter of credit facilities and reduced major maintenance reserve requirements resulting from our plant outage schedule.

Cash flows used in financing activities were $113 million and were primarily related to the execution of our share repurchase program, offset by net proceeds associated with the refinancing of our CCFC notes and the receipt of proceeds from project debt related to our Russell City and Los Esteros construction projects.

During the second quarter of 2013, we opportunistically refinanced the notes of CCFC, our indirect, wholly owned subsidiary. The $1.0 billion 8.0% notes, previously due in 2016, were replaced with a two-tranche term loan composed of (i) $900 million priced at LIBOR plus 2.25% due in 2020, and (ii) $300 million priced at LIBOR plus 2.50% due in 2022, each of which is subject to a LIBOR floor of 0.75%. During the second quarter, we also executed an amendment to our $1.0 billion Corporate Revolver, extending the maturity from 2015 to 2018 and reducing the LIBOR margin by 1.0% and the undrawn commitment fees by 0.25%. “These refinancings, which we estimate will save us more than $45 million in annual, run-rate interest expense, provide another example of our focus on growing Adjusted Free Cash Flow Per Share,” said Zamir Rauf , Calpine’s Chief Financial Officer.

CAPITAL ALLOCATION

Share Repurchase Program

In February 2013, our Board of Directors authorized the repurchase of an additional $400 million in shares of our common stock, bringing the cumulative authorization total to $1.0 billion. We completed the repurchase of the additional $400 million authorization in July 2013. Over the course of our $1.0 billionshare repurchase program, we have repurchased more than 55 million shares of our outstanding common stock at an average price paid of $18.18 per share.

PLANT DEVELOPMENT

West:

Russell City Energy Center: Construction at our Russell City Energy Center continues to move forward. Upon completion, this project will bring on line 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 third quarter 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 third quarter 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 our Deer Park and Channel Energy Centers by approximately 260 MW6 each. We received air permit approvals from the TCEQ for our Deer Park and Channel expansion projects in September andOctober 2012, respectively, and from the EPA in November 2012. Construction on both expansion projects commenced in the fourth quarter of 2012. We expect COD on the expansions of our Channel and Deer Park Energy Centers during the second quarter of 2014.

North:

Garrison Energy Center: Garrison Energy Center is a 309 MW combined-cycle project located inDelaware on a site secured by a long-term lease with the City of Dover. Construction commenced in April 2013, and we expect COD by the second quarter of 2015. The project’s capacity cleared PJM’s 2015/2016 and 2016/2017 base residual auctions. We are in the early stages of development of a second phase (309 MW) of this project. PJM has completed the feasibility and system impact studies for this phase and the facilities study is currently underway.

Deepwater Energy Center: We are currently evaluating our Deepwater facility since the existing 158 MW fossil fuel steam-based power plant is currently scheduled to be decommissioned by May 1, 2015. The Deepwater development opportunity would add approximately 350 MW of new combined-cycle capacity and leverage existing infrastructure; however, our Deepwater development proposal did not clear PJM’s 2016/2017 base residual auction. The project is continuing to advance entitlements (permits, zoning, transmission, etc.) for the potential development of Deepwater at a future date.

Mankato Power Plant Expansion: We are proposing a 345 MW expansion of the Mankato Power Plant in response to a competitive resource acquisition process established by the Minnesota Public Utilities Commission (MPUC). The process, which will be managed via a contested case hearing, is intended to address a capacity shortfall in the Northern States Power service territory of up to 500 MW over the 2017 to 2019 time frame. The MPUC will evaluate proposals for intermediate and/or peaking capacity to meet all or part of the 500 MW needed. We expect that winning bidders will be identified in the fourth quarter of 2013.

All Segments:

Turbine Modernization: We continue to move forward with our turbine modernization program. ThroughJune 30, 2013, we have completed the upgrade of twelve Siemens and eight GE turbines totaling approximately 200 MW and have committed to upgrade approximately four additional turbines. Similarly, we have the opportunity at several of our power plants in Texas to implement further modernizations to add as much as 300 MW of incremental capacity across the region at attractive prices. Our decision to invest in these modernizations depends upon, among other things, further clarity on market design reforms currently being considered by the Public Utility Commission of Texas.

___________

6 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

Second Quarter 2013 Power Operations Achievements:

  • Safety Performance:
    — Maintained top quartile7 safety metrics: 0.97 Total Recordable Incident Rate
  • Availability Performance:
    — Maintained impressive fleetwide forced outage factor: 1.6%
    — Delivered remarkable fleetwide starting reliability: 99%
  • Geothermal Generation:
    — Provided approximately 1.5 million MWh of renewable baseload generation during the quarter with a 0.70% forced outage factor year-to-date
  • Natural Gas-fired Generation:
    — Corpus Christi Energy Center: 100% starting reliability, 0% forced outage factor
    — Carville Energy Center: 100% starting reliability, 99.9% availability

Second Quarter 2013 Commercial Operations Achievements:

  • Customer-oriented Growth:
    — Entered into a three-year PPA with South Carolina Electric and Gas Company to provide 200 MW of power from our Columbia Energy Center beginning January 2014
    — Entered into two new resource adequacy contracts with Pacific Gas and Electric Company for our Delta and Sutter Energy Centers for the full capacity of each plant which commence in January andJune 2014, respectively, and extend through December 2015 and 2016, respectively
    — Entered into two new PPAs with Marin Energy Authority to provide 3 MW and 10 MW of renewable power in 2014 and 2017-2026, respectively, from our Geysers assets

___________

7 According to EEI Safety Survey (2012).

2013 FINANCIAL OUTLOOK

(in millions, except per share amounts)

Prior Guidance
(as of May 2, 2013) Current Guidance
Adjusted EBITDA $ 1,800 - 1,960 $ 1,800 - 1,875
Less:
Operating lease payments 35 35
Major maintenance expense and maintenance capital expenditures(1) 370 390
Cash interest, net(2) 755 710
Cash taxes 15 15
Other 10 10
Adjusted Free Cash Flow $ 615 - 775 $ 640 - 715
Per Share Estimate (diluted) $ 1.50 $ 1.50
Growth capital expenditures (net of debt funding) $ (250 ) $ (250 )
Debt amortization $ (140 ) $ (150 )

________

(1) Includes projected major maintenance expense of $230 million and maintenance capital expenditures of $160 million. Capital expenditures exclude major construction and development projects. 2013 figures exclude a 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 updating our 2013 guidance. In order to reflect the weaker market conditions during the first half of the year, we are lowering the top end of our Adjusted EBITDA and Adjusted Free Cash Flow guidance, while maintaining the bottom end of Adjusted EBITDA, and increasing the bottom end of Adjusted Free Cash Flow. We now project Adjusted EBITDA of $1,800 million to $1,875 million and Adjusted Free Cash Flow of $640 million to $715 million. Meanwhile, we are reaffirming our Adjusted Free Cash Flow Per Share guidance of $1.50, which would result in a 22% compound annual growth rate since 2011.

Finally, we 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 second quarter of 2013 on Thursday, July 25, 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 35088347. 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 35088347. Presentation materials to accompany the conference call will be available on our website on July 25, 2013.

ABOUT CALPINE

Calpine Corporation generates more electricity than any other independent power producer in America, with a fleet of 93 power plants in operation or under construction, representing more than 27,000 megawatts of generation capacity. 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 competitive wholesale 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 Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, has been filed with theSecurities 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, seasonality of demand, 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 Term Loans 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 CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

Three Months Ended June 30, Six Months Ended June 30,
2013 2012 2013 2012
(in millions, except share and per share amounts)
Operating revenues:
Commodity revenue $ 1,539 $ 1,177 $ 2,847 $ 2,389
Unrealized mark-to-market gain (loss) 31 (302 ) (40 ) (280 )
Other revenue 2 4 6 6
Operating revenues 1,572 879 2,813 2,115
Operating expenses:
Fuel and purchased energy expense:
Commodity expense 998 570 1,833 1,261
Unrealized mark-to-market (gain) loss 2 44 (12 ) (12 )
Fuel and purchased energy expense 1,000 614 1,821 1,249
Plant operating expense 257 271 484 492
Depreciation and amortization expense 145 138 291 278
Sales, general and other administrative expense 36 35 69 68
Other operating expenses 20 19 38 40
Total operating expenses 1,458 1,077 2,703 2,127
(Income) from unconsolidated investments in power plants (8 ) (5 ) (16 ) (14 )
Income (loss) from operations 122 (193 ) 126 2
Interest expense 170 184 346 369
Loss on interest rate derivatives 14
Interest (income) (1 ) (2 ) (3 ) (5 )
Debt extinguishment costs 68 68 12
Other (income) expense, net 3 6 8 8
Loss before income taxes (118 ) (381 ) (293 ) (396 )
Income tax benefit (48 ) (52 ) (98 ) (58 )
Net loss (70 ) (329 ) (195 ) (338 )
Net income attributable to the noncontrolling interest
Net loss attributable to Calpine $ (70 ) $ (329 ) $ (195 ) $ (338 )
Basic and diluted loss per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 447,558 471,444 449,620 474,775
Net loss per common share attributable to Calpine — basic and diluted $ (0.16 ) $ (0.69 ) $ (0.43 ) $ (0.71 )

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

June 30,

December 31,
2013 2012
(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 715 $ 1,284
Accounts receivable, net of allowance of $2 and $6 726 437
Margin deposits and other prepaid expense 310 244
Restricted cash, current 140 193
Derivative assets, current 601 339
Inventory and other current assets 447 335
Total current assets 2,939 2,832
Property, plant and equipment, net 13,057 13,005
Restricted cash, net of current portion 58 60
Investments in power plants 85 81
Long-term derivative assets 136 98
Other assets 483 473
Total assets $ 16,758 $ 16,549
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable $ 551 $ 382
Accrued interest payable 175 180
Debt, current portion 169 115
Derivative liabilities, current 630 357
Other current liabilities 206 284
Total current liabilities 1,731 1,318
Debt, net of current portion 10,851 10,635
Deferred income tax liability, non-current 3
Long-term derivative liabilities 291 293
Other long-term liabilities 298 247
Total liabilities 13,174 12,493
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, 495,214,960 and 492,495,100 shares issued, respectively, and 441,671,019 and 457,048,970 shares outstanding, respectively 1 1
Treasury stock, at cost, 53,543,941 and 35,446,130 shares, respectively (962 ) (594 )
Additional paid-in capital 12,370 12,335
Accumulated deficit (7,695 ) (7,500 )
Accumulated other comprehensive loss (191 ) (248 )
Total Calpine stockholders’ equity 3,523 3,994
Noncontrolling interest 61 62
Total stockholders’ equity 3,584 4,056
Total liabilities and stockholders’ equity $ 16,758 $ 16,549

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended June 30,
2013 2012
(in millions)
Cash flows from operating activities:
Net loss $ (195 ) $ (338 )
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization expense(1) 315 299
Debt extinguishment costs 28
Deferred income taxes (15 ) (31 )
Loss on disposition of assets 4 4
Unrealized mark-to-market activity, net 24 119
(Income) from unconsolidated investments in power plants (16 ) (14 )
Return on unconsolidated investments in power plants 16 16
Stock-based compensation expense 20 13
Other (4 ) 1
Change in operating assets and liabilities:
Accounts receivable (285 ) 63
Derivative instruments, net 1 (111 )
Other assets (182 ) (122 )
Accounts payable and accrued expenses 67 (86 )
Settlement of non-hedging interest rate swaps 156
Other liabilities 47 (1 )
Net cash used in operating activities (175 ) (32 )
Cash flows from investing activities:
Purchases of property, plant and equipment (335 ) (369 )
Settlement of non-hedging interest rate swaps (156 )
Decrease in restricted cash 55 19
Purchases of deferred transmission credits (12 )
Other (1 ) 5
Net cash used in investing activities

(281 )

(513 )
Cash flows from financing activities:
Repayment under First Lien Term Loans

(12 )

(8 )
Borrowings from CCFC Term Loans 1,197
Repayment of CCFC Notes (1,000 )
Borrowings from project financing, notes payable and other 116 226
Repayments of project financing, notes payable and other (43 ) (46 )
Financing costs (27 ) (5 )
Stock repurchases (362 ) (290 )
Proceeds from exercises of stock options 17 3
Other 1
Net cash used in financing activities (113 ) (120 )
Net decrease in cash and cash equivalents (569 ) (665 )
Cash and cash equivalents, beginning of period 1,284 1,252
Cash and cash equivalents, end of period $ 715 $ 587
Cash paid during the period for:
Interest, net of amounts capitalized $ 334 $ 352
Income taxes $ 21 $ 13
Supplemental disclosure of non-cash investing activities:
Change in capital expenditures included in accounts payable $ 17 $ 3

__________

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

REGULATION G RECONCILIATIONS

Net Loss, As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted 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 Loss, As Adjusted, is presented because we believe it is a useful tool for assessing the operating performance of our company in the current period. Net Loss, As Adjusted, is not intended to represent net income (loss), the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

Commodity Margin includes our power and steam revenues, sales of purchased power and 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, environmental compliance expense, and realized settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales, but excludes the unrealized portion of our mark-to-market activity and other revenues. We believe that Commodity Margin 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 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.

We believe Adjusted EBITDA is 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.

Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any unrealized gains or losses from accounting for derivatives, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase or extinguishment of debt, Conectiv Acquisition-related costs and any extraordinary, unusual or non-recurring items plus the Adjusted EBITDA from our discontinued operations and adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends.

In summary, 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.

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 presented because we believe it is a useful tool for assessing the financial performance of our company in the current period. 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 endedJune 30, 2013 and 2012 (in millions):

Three Months Ended June 30, 2013
Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin $ 198 $ 133 $ 159 $ 43 $ $ 533
Add: Unrealized mark-to-market commodity activity, net and other(1) 19 34 (12 ) 7 (9 ) 39
Less:
Plant operating expense 88 96 46 35 (8 ) 257
Depreciation and amortization expense 52 44 32 18 (1 ) 145
Sales, general and other administrative expense 3 21 6 7 (1 ) 36
Other operating expenses 11 1 7 (1 ) 2 20
(Income) from unconsolidated investments in power plants (8 ) (8 )
Income (loss) from operations $ 63 $ 5 $ 64 $ (9 ) $ (1 ) $ 122
Three Months Ended June 30, 2012
Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin(2)(3) $ 210 $ 145 $ 181 $ 73 $ $ 609
Add: Unrealized mark-to-market commodity activity, net and other(1) (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 9 1 6 2 1 19
(Income) from unconsolidated investments in power plants (5 ) (5 )
Income (loss) from operations $ (42 ) $ (192 ) $ 77 $ (36 ) $ $ (193 )

The following table reconciles our Commodity Margin to its U.S. GAAP results for the six months endedJune 30, 2013 and 2012 (in millions):

Six Months Ended June 30, 2013
Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin $ 400 $ 209 $ 301 $ 84 $ $ 994
Add: Unrealized mark-to-market commodity activity, net and other(4) (18 ) 23 (5 ) 14 (16 ) (2 )
Less:
Plant operating expense 181 164 90 65 (16 ) 484
Depreciation and amortization expense 103 87 65 37 (1 ) 291
Sales, general and other administrative expense 7 38 12 12 69
Other operating expenses 20 2 14 1 1 38
(Income) from unconsolidated investments in power plants (16 ) (16 )
Income (loss) from operations $ 71 $ (59 ) $ 131 $ (17 ) $ $ 126
Six Months Ended June 30, 2012
Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin(2)(3) $ 418 $ 254 $ 325 $ 129 $ $ 1,126
Add: Unrealized mark-to-market commodity activity, net and other(4) (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 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

_________

(1) Includes $(11) million and $(1) million of lease levelization and $3 million and $3 million of amortization expense for the three months ended June 30, 2013 and 2012, respectively.

(2) Our North segment includes Commodity Margin of $24 million and $32 million for the three and six months ended June 30, 2012, related to Riverside Energy Center, LLC, which was sold in December 2012.

(3) Our Southeast segment includes Commodity Margin of $13 million and $24 million for the three and six months endedJune 30, 2012, related to Broad River Energy Center, which was sold in December 2012.

(4) Includes $(27) million and $(9) million of lease levelization and $7 million and $7 million of amortization expense for the six months ended June 30, 2013 and 2012, respectively.

Consolidated Adjusted EBITDA Reconciliation

In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our net loss attributable to Calpine for the three and six months ended June 30, 2013 and 2012, as reported under U.S. GAAP.

Three Months Ended June 30, Six Months Ended June 30,
2013 2012 2013 2012
Net loss attributable to Calpine $ (70 ) $ (329 ) $ (195 ) $ (338 )
Income tax benefit (48 ) (52 ) (98 ) (58 )
Debt extinguishment costs and other (income) expense, net 71 6 76 20
Loss on interest rate derivatives 14
Interest expense, net of interest income 169 182 343 364
Income (loss) from operations $ 122 $ (193 ) $ 126 $ 2
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1) 146 138 292 279
Major maintenance expense 83 81 149 127
Operating lease expense 8 8 17 17
Unrealized (gain) loss on commodity derivative mark-to-market activity (29 ) 346 28 268
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3) 7 9 13 16
Stock-based compensation expense 12 7 20 13
Loss on dispositions of assets 2 2 4 4
Acquired contract amortization 3 3 7 7
Other (11 ) 2 (27 ) (5 )
Total Adjusted EBITDA $ 343 $ 403 $ 629 $ 728
Less:
Operating lease payments 8 8 17 17
Major maintenance expense and capital expenditures(4) 105 109 241 255
Cash interest, net(5) 175 190 355 381
Cash taxes 14 7 17 11
Other 3 2 4 4
Adjusted Free Cash Flow(6) $ 38 $ 87 $ (5 ) $ 60
Weighted average shares of common stock outstanding (diluted, in thousands) 447,558 471,444 449,620 474,775
Adjusted Free Cash Flow Per Share (diluted) $ 0.08 $ 0.19 $ (0.01 ) $ 0.13

_________

(1) Depreciation and amortization expense on our Consolidated Condensed Statements of Operations excludes amortization of other assets.

(2) Included on our Consolidated Condensed Statements of Operations in (income) from unconsolidated investments in power plants.

(3) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized (gain) loss on mark-to-market activity of nil for each of the three and six months ended June 30, 2013 and 2012.

(4) Includes $85 million and $151 million in major maintenance expense for the three months and six months ended June 30, 2013, respectively, and $20 million and $90 million in maintenance capital expenditure for the three and six months ended June 30, 2013, respectively. 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 expenditure for the three and six months ended June 30, 2012, 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 an increase in working capital of $121 million and $304 million for the three months and six months endedJune 30, 2013, respectively, and an increase in working capital of $56 million and a decrease in working capital of $20 million for the three months and six months ended June 30, 2012, 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 and six months ended June 30, 2013 and 2012. 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,
2013 2012 2013 2012
Commodity Margin $ 533 $ 609 $ 994 $ 1,126
Other revenue 3 3 6 6
Plant operating expense(1) (166 ) (181 ) (320 ) (351 )
Sales, general and administrative expense(2) (30 ) (30 ) (59 ) (60 )
Other operating expenses(3) (11 ) (10 ) (21 ) (21 )
Adjusted EBITDA from unconsolidated investments in power plants(4) 14 14 29 30
Other (2 ) (2 )
Adjusted EBITDA $ 343 $ 403 $ 629 $ 728

_________

(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 composed 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) $ 162 $ 237
Plus:

Debt extinguishment costs

68 68
Interest expense, net of interest income 700 700
Depreciation and amortization expense 595 595
Major maintenance expense 225 225
Operating lease expense 35 35
Other(2) 15 15
Adjusted EBITDA $ 1,800 $ 1,875
Less:
Operating lease payments 35 35
Major maintenance expense and maintenance capital expenditures(3) 390 390
Cash interest, net(4) 710 710
Cash taxes 15 15
Other 10 10
Adjusted Free Cash Flow $ 640 $ 715

_________

(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 $230 million and maintenance capital expenditures of $160 million. Capital expenditures exclude major construction and development projects. 2013 figures exclude a 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 June 30 Six Months Ended June 30,
2013 2012 2013 2012
Total MWh generated (in thousands)(1) 22,339 26,681 46,337 54,736
West 7,229 6,191 15,566 14,394
Texas 7,270 9,089 15,300 18,232
Southeast 3,773 6,201 7,495 11,923
North 4,067 5,200 7,976 10,187
Average availability 88.2 % 86.4 % 89.2 % 88.4 %
West 88.8 % 81.6 % 88.7 % 87.6 %
Texas 83.5 % 88.3 % 85.4 % 87.0 %
Southeast 95.2 % 90.8 % 94.7 % 92.5 %
North 88.2 % 85.4 % 90.2 % 87.3 %
Average capacity factor, excluding peakers(1) 43.4 % 51.0 % 45.5 % 53.0 %
West 52.5 % 45.0 % 57.0 % 52.7 %
Texas 42.8 % 59.3 % 45.3 % 59.6 %
Southeast 33.7 % 51.8 % 33.7 % 50.3 %
North 42.9 % 45.6 % 43.1 % 46.4 %
Steam adjusted heat rate (Btu/kWh) 7,447 7,391 7,394 7,329
West 7,414 7,366 7,345 7,233
Texas 7,184 7,150 7,173 7,115
Southeast 7,429 7,309 7,349 7,291
North 8,015 7,991 7,963 7,903

________

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

Source: Calpine Corporation

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