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Calpine Reports Strong Second Quarter Results; Narrows 2015 Guidance Ranges While Reaffirming Midpoints

07/30/2015

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

Summary of Second Quarter 2015 Financial Results (in millions, except per share amounts):

  Three Months Ended June 30,   Six Months Ended June 30,
2015   2014   % Change 2015   2014   % Change
 
Operating Revenues $ 1,442 $ 1,939 (25.6 )% $ 3,088 $ 3,904 (20.9 )%
Commodity Margin $ 657 $ 632 4.0 % $ 1,192 $ 1,277 (6.7 )%
Adjusted EBITDA $ 457 $ 413 10.7 % $ 795 $ 859 (7.5 )%
Adjusted Free Cash Flow $ 144 $ 99 45.5 % $ 169 $ 229 (26.2 )%
Per Share (diluted) $ 0.39 $ 0.23 69.6

%

$ 0.45 $ 0.54 (16.7 )%
Net Income1 $ 19 $ 139 $ 9 $ 122
Per Share (diluted) $ 0.05 $ 0.33 $ 0.02 $ 0.29
Net Income (Loss), As Adjusted2 $ 33 $ (3 ) $ (29 ) $ 53
 

Narrowing 2015 Full Year Guidance (in millions, except per share amounts):

  2015
 
Adjusted EBITDA $1,950 - 2,050
Adjusted Free Cash Flow $840 - 940
Per Share Estimate (diluted) $2.20 - 2.50

Recent Achievements:

  • Power and Commercial Operations:
    — Generated a second quarter record of approximately 28 million MWh3
    — Achieved low second quarter fleetwide forced outage factor: 1.9%
    — Delivered strong fleetwide starting reliability: 98%
    — Executed 50 MW ten-year PPA with Southern California Edison from our Geysers assets
  • Capital Allocation:
    — Announced accretive acquisition of leading retail provider Champion Energy for $240 million4
    — Completed approximately $475 million of share repurchases year-to-date, an incremental $239 million since last call
    — Refinanced approximately $1.6 billion of First Lien Term Loans, reducing interest expense and extending maturity
  • Portfolio Management:
    — Commenced commercial operation of 309 MW Garrison Energy Center in June 2015
    — Commenced construction of York 2 Energy Center; commercial operations expected during second quarter of 2017
    — Received FERC approval for January 2017 sale of Osprey Energy Center

Calpine Corporation (NYSE: CPN) today reported second quarter 2015 Adjusted EBITDA of $457 million, compared to $413 million in the prior year period, and Adjusted Free Cash Flow of $144 million, or $0.39 per diluted share, compared to $99 million, or $0.23 per diluted share, in the prior year period. Net Income1 for the second quarter of 2015 was $19 million, or $0.05 per diluted share, compared to $139 million, or $0.33 per diluted share, in the prior year period. Net Income, As Adjusted2, for the second quarter of 2015 was $33 million compared to Net Loss, As Adjusted2, of $3 million in the prior year period. The increases in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted2, were primarily due to higher Commodity Margin driven largely by increased generation across all segments resulting from lower natural gas prices in the East and Texas and stronger market conditions in the West during June, as well as higher contribution from hedges across all of our regions.

Year-to-date 2015 Adjusted EBITDA was $795 million, compared to $859 million in the prior year period, and Adjusted Free Cash Flow was $169 million, or $0.45 per diluted share, compared to $229 million, or $0.54 per diluted share, in the prior year period. Net Income1 for the first half of 2015 was $9 million, or $0.02 per diluted share, compared to $122 million, or $0.29 per diluted share, in the prior year period. Net Loss, As Adjusted2, for the first half of 2015 was $29 million compared to Net Income, As Adjusted2, of $53 million in the prior year period. The decreases in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted2, were primarily due to lower Commodity Margin driven largely by a significant decrease in power and natural gas prices in our East region in the first quarter of 2015, given the unusually high price levels experienced during the polar vortex events in the prior year period, as well as net portfolio changes and lower regulatory capacity revenue in PJM.

“We are proud to report solid operational and financial results, driven by strong execution by the Calpine team on all fronts,” said Thad Hill, Calpine’s President and Chief Executive Officer. “For the second consecutive quarter, we achieved record high generation volume, reflecting the ability of our fleet to thrive in a low natural gas price environment while more broadly highlighting the industry shift away from traditional baseload resources and the increasing need for our flexible natural gas fleet to help integrate growing renewable capacity. Specifically, our Texas and East fleets displaced uneconomic coal-fired generation, while our California fleet demonstrated the value of dispatchable electricity by helping maintain grid reliability during the historic drought.

“On the strategic front, last week we announced the acquisition of Champion Energy, the nation’s largest independent retail electric provider, primarily concentrated in Texas and the Mid-Atlantic. Champion represents an ideal platform to expand our customer channels given its significant geographic overlap with Calpine’s wholesale fleet. Champion’s award-winning customer service mirrors Calpine’s focus on operational excellence. We expect to close this highly accretive transaction by the fourth quarter.

“I am also pleased to report that we remain on track to deliver on our 2015 financial commitments to our shareholders and today are tightening our Adjusted EBITDA and Free Cash Flow Per Share guidance ranges while maintaining the midpoints,” added Hill. “While commodity markets have sold off, including the Texas power market, we remain optimistic about the next several years, given structural improvement in capacity markets and the continuation of the trend toward more reliance on gas-fired generation. We also plan to continue adding value through disciplined and balanced capital allocation and active management of our portfolio. As the industry evolves, we are confident that the benefits of our strategically aligned fleet will continue to generate significant free cash flow for the foreseeable future.”

1 Reported as Net Income 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 Subject to working capital adjustments.

SUMMARY OF FINANCIAL PERFORMANCE

Second Quarter Results

Adjusted EBITDA for the second quarter of 2015 was $457 million compared to $413 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily related to a $25 million increase in Commodity Margin, as well as a $14 million decrease in plant operating expense5. The lower plant operating expense largely resulted from net portfolio changes. The increase in Commodity Margin was primarily due to:

            +   higher generation across all segments driven by lower natural gas prices in the East and Texas and stronger market conditions in June 2015 in the West resulting from warmer weather and a decrease in hydroelectric generation in the Pacific Northwest and
+ higher contribution from hedges across all of our regions, partially offset by
the net impact of our portfolio management activities, including the sale of six power plants with a total capacity of 3,498 MW in our East region in July 2014, the acquisition of our Fore River Energy Center in November 2014, the commencement of commercial operations at our Garrison Energy Center in June 2015 and the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014, and
lower regulatory capacity revenue in PJM.

Net Income1 was $19 million for the second quarter of 2015, compared to $139 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $33 million in the second quarter of 2015 compared to Net Loss, As Adjusted2, of $3 million in the prior year period. The year-over-year improvement in Net Income, As Adjusted was driven largely by higher Commodity Margin, as previously discussed.

Adjusted Free Cash Flow was $144 million in the second quarter of 2015 compared to $99 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to the increase in Adjusted EBITDA, as previously discussed.

Year-to-Date Results

Adjusted EBITDA for the six months ended June 30, 2015, was $795 million compared to $859 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to an $85 million decrease in Commodity Margin, partially offset by an $18 million decrease in plant operating expense5. The plant operating expense decline was largely the result of net portfolio changes. The decrease in Commodity Margin was primarily due to:

              a significant decrease in power and natural gas prices in our East region in the first quarter of 2015 compared to the prior year period, given the unusually high price levels experienced during the polar vortex events in the first quarter of 2014
the net impact of our portfolio management activities, including the sale of six power plants with a total capacity of 3,498 MW in our East region in July 2014, the acquisition of our Guadalupe and Fore River Energy Centers in February and November 2014, respectively, the commencement of commercial operations at our Garrison Energy Center in June 2015 and the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014, and
lower regulatory capacity revenue in PJM, partially offset by
+ higher contribution from hedges that more than offset lower on-peak spark spreads across all of our regions, excluding the impact of the polar vortex events experienced during the first quarter of 2014, and
+ higher generation in Texas resulting from lower natural gas prices, which drove lower systemwide coal-fired generation during the first half of 2015.

Net Income1 was $9 million for the six months ended June 30, 2015, compared to $122 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted2, was $29 million in the six months ended June 30, 2015, compared to Net Income, As Adjusted2, of $53 million in the prior year period. The year-over-year decline was driven largely by lower Commodity Margin, as previously discussed.

Adjusted Free Cash Flow was $169 million for the six months ended June 30, 2015, compared to $229 million in the prior year period. Adjusted Free Cash Flow decreased during the period primarily due to the decrease in Adjusted EBITDA, as previously discussed.

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 months and six months ended June 30, 2015 and 2014.

Table 1: Net Income (Loss), As Adjusted (in millions)

  Three Months Ended June 30,   Six Months Ended June 30,
2015   2014 2015   2014
Net income attributable to Calpine $ 19 $ 139 $ 9 $ 122
Debt modification and extinguishment costs(1) 13 32 1
Mark-to-market (gain) loss on derivatives(1)(2) 1   (142 ) (70 ) (70 )
Net Income (Loss), As Adjusted(3) $ 33   $ (3 ) $ (29 ) $ 53  

__________

(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 mark-to-market (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) Non-GAAP financial measure, 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,
2015   2014   Variance 2015   2014   Variance
West $ 240 $ 228 $ 12 $ 458 $ 430 $ 28
Texas 170 177 (7 ) 319 298 21
East 247   227   20   415   549   (134 )
Total $ 657   $ 632   $ 25   $ 1,192   $ 1,277   $ (85 )

West Region

Second Quarter: Commodity Margin in our West segment increased by $12 million in the second quarter of 2015 compared to the prior year period. Primary drivers were:

            +   higher contribution from hedges
+ increased generation due to stronger market conditions in June 2015 driven by warmer weather and a decrease in hydroelectric generation in the Pacific Northwest and
+ higher renewable energy credit revenue associated with our Geysers assets resulting from more favorable pricing in 2015.

Year-to-date: Commodity Margin in our West segment increased by $28 million for the six months ended June 30, 2015, compared to the prior year period. Primary drivers were:

            +   higher contribution from hedges and
+ higher renewable energy credit revenue associated with our Geysers assets resulting from more favorable pricing in 2015, partially offset by
lower on-peak spark spreads resulting from lower natural gas prices.

Texas Region

Second Quarter: Commodity Margin in our Texas segment decreased by $7 million in the second quarter of 2015 compared to the prior year period. Primary drivers were:

              lower on-peak spark spreads resulting from lower natural gas prices, partially offset by
+ higher generation driven by lower natural gas prices that drove lower systemwide coal-fired generation
+ higher contribution from hedges and
+ the expansions of our Deer Park and Channel Energy Centers, which were completed in June 2014.

Year-to-date: Commodity Margin in our Texas segment increased by $21 million for the six months ended June 30, 2015, compared to the prior year period. Primary drivers were:

            +   the acquisition of Guadalupe Energy Center in February 2014 and the expansions of our Deer Park and Channel Energy Centers in June 2014
+ higher contribution from hedges and
+ higher generation driven by lower natural gas prices and lower systemwide coal-fired generation, partially offset by
lower on-peak spark spreads resulting from lower natural gas prices.

East Region

Second Quarter: Commodity Margin in our East segment increased by $62 million in the second quarter of 2015 compared to the prior year period, after excluding a decrease of $42 million resulting from the sale of six power plants with a total capacity of 3,498 MW on July 3, 2014. Primary drivers were:

            +   the acquisition of Fore River Energy Center in November 2014 and the commencement of commercial operations at our Garrison Energy Center in June 2015
+ higher spark spreads on our open position driven by lower natural gas prices, which also drove higher generation, and
+ higher contribution from hedges, partially offset by
lower regulatory capacity revenues in PJM and
the retirements of Cedar, Missouri Avenue and Middle Energy Centers in May 2015.

Year-to-date: Commodity Margin in our East segment decreased by $53 million for the six months ended June 30, 2015, compared to the prior year period, after excluding a decrease of $81 million resulting from the sale of six power plants with a total capacity of 3,498 MW on July 3, 2014. Primary drivers were:

              a significant decrease in power and natural gas prices in our East region in the first quarter of 2015 compared to the prior year period, given the unusually high price levels experienced during the polar vortex events in the first quarter of 2014
lower regulatory capacity revenues in PJM and
the retirements of Cedar, Missouri Avenue and Middle Energy Centers in May 2015, partially offset by
+ the acquisition of Fore River Energy Center in November 2014 and the commencement of commercial operations at our Garrison Energy Center in June 2015 and
+ higher contribution from hedges.
 

LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES

Table 3: Liquidity (in millions)

  June 30, 2015   December 31, 2014
Cash and cash equivalents, corporate(1) $ 345 $ 460
Cash and cash equivalents, non-corporate 77   257
Total cash and cash equivalents 422 717
Restricted cash 210 244
Corporate Revolving Facility availability 1,321 1,277
CDHI letter of credit facility availability 56   86
Total current liquidity availability $ 2,009   $ 2,324

____________

(1) Includes $53 million and $47 million of margin deposits posted with us by our counterparties at June 30, 2015, and December 31, 2014, respectively.

Liquidity was approximately $2 billion as of June 30, 2015. Cash and cash equivalents decreased during the first half of 2015 primarily due to the repurchases of our common stock, ongoing investments in announced growth projects and the repurchase of a portion of our outstanding 2023 First Lien Notes, partially offset by the receipt of proceeds related to the issuance of our 5.5% Senior Unsecured Notes due 2024 in February 2015.

Table 4: Cash Flow Activities (in millions)

  Six Months Ended June 30,
2015   2014
Beginning cash and cash equivalents $ 717   $ 941  
Net cash provided by (used in):
Operating activities 19 349
Investing activities (246 ) (900 )
Financing activities (68 ) 52  
Net decrease in cash and cash equivalents (295 ) (499 )
Ending cash and cash equivalents $ 422   $ 442  

Cash flows provided by operating activities in the six months ended June 30, 2015, were $19 million compared to $349 million in the prior year period. The decrease in cash provided by operating activities was primarily due to lower income from operations (adjusted for non-cash items) primarily as a result of lower Commodity Margin in our East region in the first quarter of 2015, as previously discussed. In addition, working capital employed related to cash used in operating activities increased during the period primarily due to net margin requirements and greater purchases of environmental allowances. Lastly, cash paid for interest increased, primarily due to our refinancing activity and the related timing of interest payments.

Cash flows used in investing activities were $246 million during the six months ended June 30, 2015, compared to $900 million in the prior year period. The decrease was primarily due to the $656 million purchase of our Guadalupe Energy Center in February 2014, for which there was no corresponding activity in the first half of 2015.

Cash flows used in financing activities were $68 million during the six months ended June 30, 2015, and were primarily related to payments associated with the execution of our share repurchase program, the repurchase of a portion of our 2023 First Lien Notes and the repayment of our 2018 First Lien Term Loan. These were partially offset by proceeds from the issuance of our 2024 Senior Unsecured Notes and the issuance of our 2022 First Lien Term Loan.

CAPITAL ALLOCATION

Acquisition of Champion Energy

In July 2015, we entered into an agreement to purchase Champion Energy for approximately $240 million, excluding working capital adjustments. Champion Energy, a leading retail electric provider, is expected to serve approximately 22 million MWh of commercial, industrial and residential customer load in 2015, concentrated in Texas, the Mid-Atlantic and the Northeast U.S. where Calpine has a substantial power generation presence. The addition of this well-established retail sales organization is expected to provide us an important outlet for directly reaching a much greater portion of the load we serve.

Share Repurchase Program

Returning capital to our shareholders by repurchasing shares of our common stock is an integral component of our capital allocation program. We view our stock as an attractive investment opportunity, and we use the projected returns from share repurchases as the benchmark against which all other investment decisions are measured. Since 2011, we have repurchased approximately $2.8 billion of our common stock, representing approximately 28% of shares outstanding.6

In 2015, through the issuance of this release, we have repurchased a total of 23.3 million shares of our common stock for approximately $475 million at an average price of $20.42 per share.

2022 First Lien Term Loan

In May 2015, we repaid our 2018 First Lien Term Loans with the proceeds from a newly issued 2022 First Lien Term Loan which extended the maturity and reduced the interest rate on approximately $1.6 billion of corporate debt.

Growth and Portfolio Management

Texas:

Guadalupe Peaking Energy Center: In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) that will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center. Under the terms of the agreement, construction of the Guadalupe Peaking Energy Center (“GPEC”) may commence at our discretion, so long as the power plant reaches commercial operation between the dates of June 1, 2017, and June 1, 2019. When the power plant begins commercial operation, GVEC will purchase a 50% ownership interest in GPEC. Once built, GPEC will feature two fast-ramping combustion turbines capable of responding to peaks in power demand. This project represents a mutually beneficial response to our customer’s desire to have direct access to peaking generation resources, as it leverages the benefits of our existing site and development rights and our construction and operating expertise, as well as our customer’s ability to fund its investment at attractive rates, all while affording us the flexibility of timing the plant’s construction in response to market pricing signals.

East:

Garrison Energy Center: Garrison Energy Center commenced commercial operations in June 2015, bringing online approximately 309 MW of combined-cycle, natural gas-fired capacity. The power plant features one combustion turbine, one heat recovery steam generator and one steam turbine and is expected to be dual fuel capable by this winter. We are in the early stages of development of a second phase of the Garrison Energy Center.

York 2 Energy Center: York 2 Energy Center is a 760 MW dual fuel combined-cycle project that will be co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. The project’s capacity cleared PJM’s 2017/2018 base residual auction. The project is now under construction, and we expect commercial operations to commence during the second quarter of 2017. PJM has completed the feasibility study for increasing York 2 Energy Center’s planned capacity by 70 MW, and the queue position has entered the system impact study stage.

Mankato Power Plant Expansion: By order dated February 5, 2015, the Minnesota Public Utilities Commission concluded a competitive resource acquisition proceeding and selected a 345 MW expansion of our Mankato Power Plant, authorizing execution of a 20-year PPA between Calpine and Xcel Energy. The PPA was executed in April 2015 and remains subject to approval by the North Dakota Public Service Commission. Commercial operation of the expanded capacity may commence as early as the summer of 2018, subject to requisite regulatory approvals and applicable contract conditions.

PJM and ISO-NE Development Opportunities: We are currently evaluating opportunities to develop additional projects in the PJM and ISO-NE market areas that feature cost advantages such as existing infrastructure and favorable transmission queue positions. These projects are continuing to advance entitlements (such as permits, zoning and transmission) for their potential future development when economical.

Osprey Energy Center: We executed an asset sale agreement during the fourth quarter of 2014 for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. In accordance with the asset sale agreement, the sale will be consummated in January 2017 upon the conclusion of a 27-month PPA. In July 2015, the transaction was approved by the FERC, and the Florida Public Service Commission voted to approve the Florida Commission Hearing Officer’s Recommended Order approving the transaction. This sale represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities.

All Segments:

Turbine Modernization: We continue to move forward with our turbine modernization program. Through June 30, 2015, we have completed the upgrade of thirteen Siemens and eight GE turbines totaling approximately 210 MW and have committed to upgrade three additional turbines. In addition, we have begun a program to update our dual-fueled turbines at certain of our power plants in our East region.

6 Based upon 490.6 million shares outstanding as of June 30, 2011, immediately prior to announcement of our repurchase program.

OPERATIONS UPDATE

Second Quarter 2015 Power Operations Achievements

  • Safety Performance:
    — Maintained top quartile7 safety metrics: 0.64 total recordable incident rate
  • Availability Performance:
    — Achieved low fleetwide forced outage factor: 1.9%
    — Delivered exceptional fleetwide starting reliability: 98%
  • Power Generation:
    — Seven gas-fired plants with capacity factors greater than 70%: Channel, Hermiston, Kennedy, Morgan, Pasadena, Pine Bluff, Russell City
    — Pine Bluff Energy Center: 100% starting reliability and 0% forced outage factor

Second Quarter 2015 Commercial Operations Achievements:

  • Customer-oriented Growth:
    — Announced accretive acquisition of retail electric provider Champion Energy for $240 million,4 consistent with our stated goal of getting closer to our end-use customers
    — Entered into a new ten-year PPA with Southern California Edison for 50 MW of capacity and renewable energy from our Geysers assets commencing in January 2018. The PPA remains subject to approval by the CPUC.

7 According to EEI Safety Survey (2014).

2015 FINANCIAL OUTLOOK

(in millions, except per share amounts)

 
Full Year 2015
Adjusted EBITDA $ 1,950 - 2,050
Less:
Operating lease payments 35
Major maintenance expense and maintenance capital expenditures(1) 415
Cash interest, net(2) 630
Cash taxes 25
Other 5  
Adjusted Free Cash Flow $ 840 - 940
Per Share Estimate (diluted) $ 2.20 - 2.50
 
Debt amortization and repayment (3) $ (460 )
Growth capital expenditures (net of debt funding) $ (355 )
Acquisition of Champion Energy(4) $ (240 )

(1) Includes projected major maintenance expense of $250 million and maintenance capital expenditures of $165 million in 2015. Capital expenditures exclude major construction and development projects.

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

(3) Includes scheduled amortization of approximately $193 million, the repurchase of approximately $147 million of our 2023 First Lien Notes in February 2015 and expected exercise of 10% call feature on 2023 First Lien Notes of approximately $120 million

(4) Subject to working capital adjustments.

As detailed above, today we are narrowing our 2015 guidance. We expect Adjusted EBITDA of $1.95 billion to $2.05 billion, Adjusted Free Cash Flow of $840 million to $940 million and Adjusted Free Cash Flow Per Share of $2.20 to $2.50. We also expect to invest $355 million in our ongoing growth-related projects during the year, having now completed construction of our Garrison Energy Center and commenced construction of our York 2 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 2015 on Thursday, July 30, 2015, at 10 a.m. Eastern time / 9 a.m. Central time. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing (888) 895-5271 in the U.S. or (847) 619-6547 outside the U.S. The confirmation code is 40141927. 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 40141927. Presentation materials to accompany the conference call will be available on our website on July 30, 2015.

ABOUT CALPINE

Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources. Our fleet of 83 power plants in operation or under construction represents approximately 27,000 megawatts of generation capacity. Serving customers in 18 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, 2015, 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, 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 and extent to which we 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;
  • Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our First Lien Notes, Senior Unsecured 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 water 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;
  • Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies);
  • 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, droughts 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 that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and
  • Other risks identified in this press release, in our 2014 Form 10-K and in other reports filed by us with the SEC.

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,
2015   2014 2015   2014

 

(in millions, except share and per share amounts)

Operating revenues:
Commodity revenue $ 1,407 $ 1,766 $ 3,045 $ 3,814
Mark-to-market gain 31 169 34 83
Other revenue 4   4   9   7  
Operating revenues 1,442   1,939   3,088   3,904  
Operating expenses:
Fuel and purchased energy expense:
Commodity expense 734 1,106 1,811 2,476
Mark-to-market (gain) loss 32   28   (35 ) 15  
Fuel and purchased energy expense 766   1,134   1,776   2,491  
Plant operating expense 272 274 532 539
Depreciation and amortization expense 160 147 318 300
Sales, general and other administrative expense 30 38 67 71
Other operating expenses 20   21   40   43  
Total operating expenses 1,248   1,614   2,733   3,444  
(Income) from unconsolidated investments in power plants (7 ) (4 ) (12 ) (13 )
Income from operations 201 329 367 473
Interest expense 158 169 312 335
Interest (income) (1 ) (2 ) (2 ) (3 )
Debt modification and extinguishment costs 13 32 1
Other (income) expense, net 5   6   7   16  
Income before income taxes 26 156 18 124
Income tax expense (benefit) 5   15   4   (4 )
Net income 21 141 14 128
Net income attributable to the noncontrolling interest (2 ) (2 ) (5 ) (6 )
Net income attributable to Calpine $ 19   $ 139   $ 9   $ 122  
 
Basic earnings per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 366,975   416,507   369,938   418,296  
Net income per common share attributable to Calpine — basic $ 0.05   $ 0.33   $ 0.02   $ 0.29  
 
Diluted earnings per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 369,946   421,348   373,404   422,697  
Net income per common share attributable to Calpine — diluted $ 0.05   $ 0.33   $ 0.02   $ 0.29  
 
 
CALPINE CORPORATION AND SUBSIDIARIES
 
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)
   
June 30, December 31,
2015 2014
(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 422 $ 717
Accounts receivable, net of allowance of $3 and $4 595 648
Inventories 477 447
Margin deposits and other prepaid expense 152 148
Restricted cash, current 162 195
Derivative assets, current 1,607 2,058
Other current assets 32   7  
Total current assets 3,447 4,220
Property, plant and equipment, net 13,147 13,190
Restricted cash, net of current portion 48 49
Investments in power plants 87 95
Long-term derivative assets 637 439
Other assets 391   385  
Total assets $ 17,757   $ 18,378  
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable $ 443 $ 580
Accrued interest payable 133 165
Debt, current portion 198 199
Derivative liabilities, current 1,407 1,782
Other current liabilities 355   473  
Total current liabilities 2,536 3,199
Debt, net of current portion 11,493 11,083
Long-term derivative liabilities 453 444
Other long-term liabilities 274   221  
Total liabilities 14,756 14,947
 
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, 504,252,268 and 502,287,022 shares issued, respectively, and 361,150,393 and 381,921,264 shares outstanding, respectively 1 1
Treasury stock, at cost, 143,101,875 and 120,365,758 shares, respectively (2,810 ) (2,345 )
Additional paid-in capital 12,463 12,440
Accumulated deficit (6,531 ) (6,540 )
Accumulated other comprehensive loss (179 ) (178 )
Total Calpine stockholders’ equity 2,944 3,378
Noncontrolling interest 57   53  
Total stockholders’ equity 3,001   3,431  
Total liabilities and stockholders’ equity $ 17,757   $ 18,378  
 
 
CALPINE CORPORATION AND SUBSIDIARIES
 
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six Months Ended June 30,
  2015       2014  
(in millions)
Cash flows from operating activities:
Net income $ 14 $ 128
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense(1) 342 322
Deferred income taxes 3 (12 )
Mark-to-market activity, net (70 ) (70 )
(Income) from unconsolidated investments in power plants (12 ) (13 )
Return on unconsolidated investments in power plants 13 13
Stock-based compensation expense 12 22
Other 2 2
Change in operating assets and liabilities:
Accounts receivable 29 (212 )
Derivative instruments, net (36 ) (109 )
Other assets (118 ) (40 )
Accounts payable and accrued expenses (205 ) 378
Other liabilities   45     (60 )
Net cash provided by operating activities   19     349  
Cash flows from investing activities:
Purchases of property, plant and equipment (279 ) (258 )
Purchase of Guadalupe Energy Center (656 )
Decrease in restricted cash 34 14
Other   (1 )    
Net cash used in investing activities   (246 )   (900 )
Cash flows from financing activities:
Borrowings under CCFC Term Loans and First Lien Term Loans

 

1,592

 

420
Repayment of CCFC Term Loans and First Lien Term Loans (1,613 ) (23 )
Borrowings under Senior Unsecured Notes 650
Repurchase of First Lien Notes (147 )
Borrowings from project financing, notes payable and other 2
Repayments of project financing, notes payable and other (85 ) (55 )
Financing costs (17 ) (10 )
Stock repurchases (454 ) (297 )
Proceeds from exercises of stock options   6     15  

Net cash provided by (used in) financing activities

  (68 )   52  
Net decrease in cash and cash equivalents (295 ) (499 )
Cash and cash equivalents, beginning of period   717     941  
Cash and cash equivalents, end of period $ 422   $ 442  
 
Cash paid during the period for:
Interest, net of amounts capitalized $ 322 $ 288
Income taxes $ 17 $ 16
 
Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable $ (20 ) $ 13

Additions to property, plant and equipment through capital lease

$ 9 $
 

__________

(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

In addition to disclosing financial results in accordance with U.S. GAAP, the accompanying second quarter 2015 earnings release contains non-GAAP financial measures. Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These non-GAAP measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance and the financial results calculated in accordance with U.S. GAAP and reconciliations from these results should be carefully evaluated.

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 mark-to-market (gain) loss on derivatives, debt modification and extinguishment costs 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, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes 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 is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

Adjusted EBITDA represents 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 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 mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, 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, modification or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any extraordinary, unusual or non-recurring items plus 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 tables reconcile our Commodity Margin to its U.S. GAAP results for the three months ended June 30, 2015 and 2014 (in millions):

 
Three Months Ended June 30, 2015
  Consolidation  
And
West Texas East Elimination Total
Commodity Margin $ 240 $ 170 $ 247 $ $ 657
Add: Mark-to-market commodity activity, net and other(1) (14 ) 10 30 (7 ) 19
Less:
Plant operating expense 120 82 77 (7 ) 272
Depreciation and amortization expense 65 50 45 160
Sales, general and other administrative expense 6 15 9 30
Other operating expenses 10 2 8 20
(Income) from unconsolidated investments in power plants     (7 )   (7 )
Income from operations $ 25   $ 31   $ 145   $   $ 201  
 
Three Months Ended June 30, 2014
Consolidation
And
West Texas East Elimination Total
Commodity Margin(2) $ 228 $ 177 $ 227 $ $ 632
Add: Mark-to-market commodity activity, net and other(1) 21 184 (24 ) (8 ) 173
Less:
Plant operating expense 95 83 103 (7 ) 274
Depreciation and amortization expense 58 48 40 1 147
Sales, general and other administrative expense 7 18 12 1 38
Other operating expenses 15 1 9 (4 ) 21
(Income) from unconsolidated investments in power plants     (4 )   (4 )
Income from operations $ 74   $ 211   $ 43   $ 1   $ 329  
 

The following tables reconcile our Commodity Margin to its U.S. GAAP results for the six months ended June 30, 2015 and 2014 (in millions):

 
Six Months Ended June 30, 2015
  Consolidation  
And
West Texas East Elimination Total
Commodity Margin $ 458 $ 319 $ 415 $ $ 1,192
Add: Mark-to-market commodity activity, net and other(3) 105 51 (22 ) (14 ) 120
Less:
Plant operating expense 226 171 149 (14 ) 532
Depreciation and amortization expense 132 99 87 318
Sales, general and other administrative expense 16 32 19 67
Other operating expenses 20 4 16 40
(Income) from unconsolidated investments in power plants     (12 )   (12 )
Income from operations $ 169   $ 64   $ 134   $   $ 367  
 
Six Months Ended June 30, 2014
Consolidation
And
West Texas East Elimination Total
Commodity Margin(2) $ 430 $ 298 $ 549 $ $ 1,277
Add: Mark-to-market commodity activity, net and other(3) 50 138 (35 ) (17 ) 136
Less:
Plant operating expense 200 173 182 (16 ) 539
Depreciation and amortization expense 118 90 91 1 300
Sales, general and other administrative expense 17 30 24 71
Other operating expenses 27 3 16 (3 ) 43
(Income) from unconsolidated investments in power plants     (13 )   (13 )
Income from operations $ 118   $ 140   $ 214   $ 1   $ 473  

_________

(1) Includes $(18) million and $(27) million of lease levelization and $3 million and $3 million of amortization expense for the three months ended June 30, 2015 and 2014, respectively.

(2) Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was $42 million and $81 million for the three and six months ended June 30, 2014, respectively.

(3) Includes $(42) million and $(56) million of lease levelization and $7 million and $7 million of amortization expense for the six months ended June 30, 2015 and 2014, respectively.

Consolidated Adjusted EBITDA Reconciliation

In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our net income (loss) attributable to Calpine for the three and six months ended June 30, 2015 and 2014, as reported under U.S. GAAP (in millions):

   
Three Months Ended June 30, Six Months Ended June 30,
2015   2014(6) 2015   2014(6)
Net income attributable to Calpine $ 19 $ 139 $ 9 $ 122
Net income attributable to the noncontrolling interest 2 2 5 6
Income tax expense (benefit) 5 15 4 (4 )
Debt modification and extinguishment costs and other (income) expense, net 18 6 39 17
Interest expense, net of interest income 157   167   310   332  
Income from operations $ 201 $ 329 $ 367 $ 473
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1) 159 146 316 297
Major maintenance expense 90 72 168 153
Operating lease expense 8 8 17 17
Mark-to-market (gain) loss on commodity derivative activity 1 (141 ) (69 ) (68 )
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest(2) 4 6 9 9
Stock-based compensation expense 1 12 12 22
Loss on dispositions of assets 2 1 3 1
Acquired contract amortization 3 3 7 7
Other (12 ) (23 ) (35 ) (52 )
Total Adjusted EBITDA $ 457   $ 413   $ 795   $ 859  
Less:
Operating lease payments 8 8 17 17
Major maintenance expense and capital expenditures(3) 136 126 279 259
Cash interest, net(4) 157 169 312 337
Cash taxes 11 8 17 14
Other 1   3   1   3  
Adjusted Free Cash Flow(5) $ 144   $ 99   $ 169   $ 229  
 
Weighted average shares of common stock outstanding (diluted, in thousands) 369,946   421,348   373,404   422,697  
Adjusted Free Cash Flow Per Share (diluted) $ 0.39   $ 0.23   $ 0.45   $ 0.54  

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

(2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for the three and six months ended June 30, 2015 and 2014.

(3) Includes $90 million and $169 million in major maintenance expense for the three and six months ended June 30, 2015, respectively, and $46 million and $110 million in maintenance capital expenditure for the three and six months ended June 30, 2015, respectively. Includes $73 million and $156 million in major maintenance expense for the three and six months ended June 30, 2014, respectively, and $53 million and $103 million in maintenance capital expenditure for the three and six months ended June 30, 2014, respectively.

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

(5) Excludes an increase in working capital of $165 million and $251 million for the three and six months ended June 30, 2015, respectively, and an increase in working capital of $36 million and $42 million for the three and six months ended June 30, 2014, respectively. Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance.

(6) Adjusted EBITDA related to the six power plants sold in our East segment on July 3, 2014, was $23 million and $43 million for the three and six months ended June 30, 2014, respectively.

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, 2015 and 2014. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. Amounts below are shown exclusive of the noncontrolling interest (in millions):

  Three Months Ended June 30,   Six Months Ended June 30,
2015   2014 2015   2014
Commodity Margin $ 657 $ 632 $ 1,192 $ 1,277
Other revenue 5 4 9 7
Plant operating expense(1) (177 ) (191 ) (350 ) (368 )
Sales, general and administrative expense(2) (32 ) (31 ) (62 ) (60 )
Other operating expenses(3) (11 ) (12 ) (21 ) (24 )
Adjusted EBITDA from unconsolidated investments in power plants 14 12 28 28
Other 1   (1 ) (1 ) (1 )
Adjusted EBITDA $ 457   $ 413   $ 795   $ 859  

_________

(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.

Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance (in millions)

Full Year 2015 Range:   Low High
GAAP Net Income (1) $

298

$

398

Plus:
Debt modification and extinguishment costs 32 32
Interest expense, net of interest income 630 630
Depreciation and amortization expense 630 630
Major maintenance expense 245 245
Operating lease expense 35 35
Other(2) 80   80
Adjusted EBITDA $ 1,950 $ 2,050
Less:
Operating lease payments 35 35
Major maintenance expense and maintenance capital expenditures(3) 415 415
Cash interest, net(4) 630 630
Cash taxes 25 25
Other 5   5
Adjusted Free Cash Flow $ 840 $ 940

_________

(1) For purposes of Net Income guidance reconciliation, 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 $250 million and maintenance capital expenditures of $165 million. Capital expenditures exclude major construction and development projects.

(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 the periods presented:

  Three Months Ended June 30,   Six Months Ended June 30,
2015   2014 2015   2014
Total MWh generated (in thousands)(1) 26,954 23,085 52,521 46,062
West 8,430 6,770 15,683 15,601
Texas 11,194 9,489 22,738 16,366
East 7,330 6,826 14,100 14,095
 
Average availability 86.0 % 88.1 % 87.7 % 88.3 %
West 82.8 % 91.6 % 85.6 % 90.3 %
Texas 87.7 % 90.8 % 87.9 % 86.9 %
East 87.0 % 83.6 % 89.3 % 88.0 %
 
Average capacity factor, excluding peakers 53.4 % 41.7 % 52.7 % 42.4 %
West 54.7 % 44.0 % 51.2 % 51.1 %
Texas 55.8 % 48.9 % 57.0 % 44.2 %
East 48.7 % 32.9 % 48.3 % 34.1 %
 
Steam adjusted heat rate (Btu/kWh) 7,329 7,433 7,296 7,393
West 7,325 7,377 7,314 7,301
Texas 7,078 7,282 7,087 7,227
East 7,738 7,694 7,629 7,678

________

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

Source: Calpine Corporation

Calpine Corporation

Media Relations:

Brett Kerr, 713-830-8809

brett.kerr@calpine.com

or

Investor Relations:

Bryan Kimzey, 713-830-8777

bryan.kimzey@calpine.com