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 October 30, 2015 - 6:00 AM EDT
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Calpine Reports Third Quarter Results, Narrows 2015 Guidance and Provides 2016 Guidance

Calpine Corporation (NYSE: CPN):

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

   
Three Months Ended September 30, Nine Months Ended September 30,
2015   2014   % Change 2015   2014   % Change
 
Operating Revenues $ 1,948 $ 2,187 (10.9

)

%

$ 5,036 $ 6,091 (17.3

)

%

Commodity Margin $ 974 $ 944 3.2 % $ 2,166 $ 2,221 (2.5

)

%

Adjusted EBITDA $ 791 $ 745 6.2 % $ 1,586 $ 1,604 (1.1

)

%

Adjusted Free Cash Flow $ 576 $ 506 13.8 % $ 745 $ 735 1.4 %
Per Share (diluted) $ 1.61 $ 1.26 27.8 % $ 2.02 $ 1.77 14.1 %
Net Income1 $ 273 $ 614 $ 282 $ 736
Per Share (diluted) $ 0.76 $ 1.52 $ 0.77 $ 1.77
Net Income, As Adjusted2 $ 347 $ 306 $ 318 $ 359
 

Narrowing 2015 and Providing 2016 Full Year Guidance (in millions, except per share amounts):

   
2015 2016
 
Adjusted EBITDA $1,965 - 2,000 $1,800 - 1,950
Adjusted Free Cash Flow $825 - 860 $710 - 860
Per Share Estimate (diluted) $2.25 - 2.35 $2.00 - 2.40
 

Recent Achievements:

  • Power Operations:
    — Generated a third quarter record of more than 33 million MWh3
    — Achieved low third quarter fleetwide forced outage factor: 1.8%
    — Delivered strong fleetwide starting reliability: 98.6%
  • Customer-Oriented Origination Efforts:
    — Completed acquisition of leading retail provider Champion Energy for $240 million4
    — Executed a 238 MW one-year resource adequacy contract with Southern California Edison for our Pastoria Energy Center
  • Capital Allocation Progress:
    — Announced acquisition of Granite Ridge Energy Center, a combined-cycle power plant in New Hampshire with a nameplate capacity of 745 MW, for $500 million4, or approximately $671/kW
    — Completed approximately $529 million of share repurchases year-to-date, reducing our share count by approximately 7%; an incremental $54 million since last call
    — Issued notice of intent to redeem 10% of our 2023 First Lien Notes

Calpine Corporation (NYSE: CPN) today reported third quarter 2015 Adjusted EBITDA of $791 million, compared to $745 million in the prior year period, and Adjusted Free Cash Flow of $576 million, or $1.61 per diluted share, compared to $506 million, or $1.26 per diluted share, in the prior year period. Net Income1 for the third quarter of 2015 was $273 million, or $0.76 per diluted share, compared to $614 million, or $1.52 per diluted share, in the prior year period. Net Income, As Adjusted2, for the third quarter of 2015 was $347 million compared to $306 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 by the acquisition of our Fore River Energy Center in November 2014 and the commencement of operations at our Garrison Energy Center in June 2015, as well as higher regulatory capacity revenue in PJM.

Year-to-date 2015 Adjusted EBITDA was $1,586 million, compared to $1,604 million in the prior year period, and Adjusted Free Cash Flow was $745 million, or $2.02 per diluted share, compared to $735 million, or $1.77 per diluted share, in the prior year period. Net Income1 for the first nine months of 2015 was $282 million, or $0.77 per diluted share, compared to $736 million, or $1.77 per diluted share, in the prior year period. Net Income, As Adjusted2, for the first nine months of 2015 was $318 million compared to $359 million in the prior year period. The decreases in Adjusted EBITDA 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. The increase in Adjusted Free Cash Flow was due to lower interest expense compared to the prior year period, which more than offset the decline in Adjusted EBITDA.

“I am pleased to report another solid quarter, with record generation volume of 33 million MWh, top quartile safety performance and continued commercial success,” said Thad Hill, Calpine’s President and Chief Executive Officer. “As a result, we are narrowing our 2015 Adjusted EBITDA guidance to a range of $1.965 billion to $2.0 billion. This is within our prior guidance range and reflects an adjustment for the projected impact of the Valley wildfire in Northern California on The Geysers geothermal facilities, which we previously announced. I would like to recognize our team at The Geysers whose extraordinary efforts have resulted in production already reaching approximately 575 net MW, or nearly 80% of full capacity.

“With respect to capital allocation, during the past quarter we completed the acquisition of retailer Champion Energy, announced the acquisition of the Granite Ridge Energy Center in New England, and continued to return capital to shareholders through share repurchases. These are further examples of our ability to source and execute accretive transactions.

“Looking to next year, we are pleased to introduce 2016 Adjusted EBITDA of $1.8 billion to $1.95 billion. Despite a decrease in year-over-year hedge value and lower capacity prices, through diligent cost control and operational excellence, we expect to deliver $2.00 to $2.40 of Adjusted Free Cash Flow Per Share. Based on the midpoint of our 2016 guidance range, our Free Cash Flow yield of approximately 15% at the current share price is attractive by comparison to the past three years’ average of 9%. While the Free Cash Flow yield is ultimately subject to market forces outside of our control, we believe that as macro commodity concerns ease and investors differentiate between companies, our currently high yield should return to the norm, making today an attractive entry point.

“I believe that the Calpine value proposition is even more compelling when taking into account our outlook over the next several years and the evolution of our business. First, there is as much as $250 million of known favorable drivers on the horizon between 2016 and 2018, without taking into account changes in natural gas and power markets – including a recovery in the Texas market – or new hedges. Secondly, our increased production this quarter affirms a clear trend over the near- to mid-term toward greater need for and utilization of our flexible and reliable natural gas-fired fleet. This trend is supported by abundant natural gas and penetration of renewables putting pressure on coal and nuclear baseload generation, increasingly stringent environmental regulation further challenging coal generation, the need to maintain reliability of supply to support the integration of intermittent renewables, and the emergence of pay-for-performance initiatives like the PJM Capacity Performance reform. In conclusion, as I look at the opportunities before us, I am excited about the outlook for Calpine and its shareholders as we continue to create value.”

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, As Adjusted.

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

4 Excluding working capital adjustments.

SUMMARY OF FINANCIAL PERFORMANCE

Third Quarter Results

Adjusted EBITDA for the third quarter of 2015 was $791 million compared to $745 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily related to a $30 million increase in Commodity Margin, as well as an $11 million decrease in plant operating expense5. The increase in Commodity Margin was primarily due to:

            +   the acquisition of our 731 MW Fore River Energy Center in November 2014 and the commencement of commercial operations at our 309 MW Garrison Energy Center in June 2015
+ higher regulatory capacity revenue, and
+ higher settled spark spreads in Texas in July and August 2015 compared to the same months in 2014, partially offset by
lower contribution from hedges and
lower spark spreads in the West due to lower natural gas prices during the third quarter of 2015 compared to the third quarter of 2014.

Net Income1 was $273 million for the third quarter of 2015, compared to $614 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $347 million in the third quarter of 2015 compared to $306 million in the prior year period. The year-over-year improvement in Net Income, As Adjusted, was driven largely by higher Commodity Margin and lower plant operating expense, as previously discussed.

Adjusted Free Cash Flow was $576 million in the third quarter of 2015 compared to $506 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 nine months ended September 30, 2015, was $1,586 million compared to $1,604 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to a $55 million decrease in Commodity Margin, partially offset by a $29 million decrease in plant operating expense5 as a result of net portfolio changes as well as lower equipment failure costs related to outages. 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 nine months ended September 30, 2015.

Net Income1 was $282 million for the nine months ended September 30, 2015, compared to $736 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $318 million in the nine months ended September 30, 2015, compared to $359 million in the prior year period. The year-over-year decline was driven largely by:

              lower Commodity Margin, as previously discussed, and

higher depreciation and amortization expense driven primarily by portfolio changes, partially offset by

+

lower plant operating expense as a result of portfolio changes, as well as a decrease in equipment failure costs related to outages and

+ lower interest expense due to a decrease in our annual effective interest rate.

Adjusted Free Cash Flow was $745 million for the nine months ended September 30, 2015, compared to $735 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to lower interest expense, which more than offset the decrease in Adjusted EBITDA.

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 nine months ended September 30, 2015 and 2014.

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

  Three Months Ended September 30,   Nine Months Ended September 30,
2015   2014 2015   2014
Net income attributable to Calpine $ 273 $ 614 $ 282 $ 736
Impairment losses(1) 123 123
(Gain) on sale of assets, net(1) (753 ) (753 )
Debt modification and extinguishment costs(1) 340 32 341
Mark-to-market (gain) loss on derivatives(1)(2) 74   (18 ) 4   (88 )
Net Income, As Adjusted(3) $ 347   $ 306   $ 318   $ 359  

__________

(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, As Adjusted.

REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin by Segment (in millions)

  Three Months Ended September 30,   Nine Months Ended September 30,
2015   2014   Variance 2015   2014   Variance
West $ 385 $ 361 $ 24 $ 843 $ 791 $ 52
Texas 264 346 (82 ) 583 644 (61 )
East 325   237   88   740   786   (46 )
Total $ 974   $ 944   $ 30   $ 2,166   $ 2,221   $ (55 )

West Region

Third Quarter: Commodity Margin in our West segment increased by $24 million in the third quarter of 2015 compared to the prior year period. Primary drivers were:

            +   higher contribution from hedges and
+ increased generation resulting from a decrease in hydroelectric generation in the Pacific Northwest, partially offset by
lower power prices and spark spreads resulting from lower natural gas prices
the expiration of the operating lease related to our Greenleaf power plants in June 2015, and
a wildfire in northern California in September 2015 that negatively impacted our Geysers assets.

Year-to-date: Commodity Margin in our West segment increased by $52 million for the nine months ended September 30, 2015, compared to the prior year period. Primary drivers were:

            +   higher contribution from hedges
+ increased generation resulting from 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, partially offset by
lower power prices and on-peak spark spreads resulting from lower natural gas prices
the expiration of the operating lease related to our Greenleaf power plants in June 2015, and
a wildfire in northern California in September 2015 that negatively impacted our Geysers assets.

Texas Region

Third Quarter: Commodity Margin in our Texas segment decreased by $82 million in the third quarter of 2015 compared to the prior year period. Primary drivers were:

              lower contribution from hedges, partially offset by
+ higher settled spark spreads in July and August 2015 compared to the same months in 2014 and
+ higher generation due to stronger market conditions and lower natural gas prices that drove lower systemwide coal-fired generation.

Year-to-date: Commodity Margin in our Texas segment decreased by $61 million for the nine months ended September 30, 2015, compared to the prior year period. Primary drivers were:

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

East Region

Third Quarter: Commodity Margin in our East segment increased by $88 million in the third quarter of 2015 compared to the prior year period. Primary drivers were:

            +   higher contribution from hedges
+ 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 regulatory capacity revenues, and
+ a new contract on our Osprey Energy Center, which became effective in the fourth quarter of 2014.

Year-to-date: Commodity Margin in our East segment increased by $35 million for the nine months ended September 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:

            +   higher contribution from hedges
+ 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 generation driven by lower natural gas prices, and
+ a new contract on our Osprey Energy Center, which became effective in the fourth quarter of 2014, partially offset by

a significant decrease in power and natural gas prices 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, and

lower regulatory capacity revenues in PJM.

LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES

Table 3: Liquidity (in millions)

  September 30, 2015   December 31, 2014
Cash and cash equivalents, corporate(1) $ 558 $ 460
Cash and cash equivalents, non-corporate 101   257
Total cash and cash equivalents 659 717
Restricted cash 275 244
Corporate Revolving Facility availability 1,330 1,277
CDHI letter of credit facility availability 62   86
Total current liquidity availability $ 2,326   $ 2,324

____________

(1) Includes $15 million and $47 million of margin deposits posted with us by our counterparties at September 30, 2015, and December 31, 2014, respectively.

Liquidity was approximately $2.3 billion as of September 30, 2015. Cash and cash equivalents decreased during the first nine months of 2015 primarily due to 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)

Nine Months Ended September 30,
2015   2014
Beginning cash and cash equivalents $ 717   $ 941  
Net cash provided by (used in):
Operating activities 548 504
Investing activities (450 ) 550
Financing activities (156 ) (466 )
Net increase (decrease) in cash and cash equivalents (58 ) 588  
Ending cash and cash equivalents $ 659   $ 1,529  
 

Cash provided by operating activities in the nine months ended September 30, 2015, was $548 million compared to $504 million in the prior year period. The increase in cash provided by operating activities was primarily due to a decrease in cash paid for debt modification and extinguishment due to a lower amount of refinancing and repayment activities in the first nine months of 2015. In addition, cash paid for interest decreased, primarily due to refinancing activity and the timing of interest payments. The increase in cash provided by operating activities was partially offset by an increase in working capital employed primarily due to net margin requirements and greater purchases of environmental allowances.

Cash used in investing activities was $450 million during the nine months ended September 30, 2015, compared to cash provided by investing activities of $550 million provided in the prior year period. The decrease was primarily due to $1.57 billion of proceeds from the July 2014 sale of six of our power plants in the East segment, partially offset by the $656 million purchase of our Guadalupe Energy Center in February 2014, for which there were no corresponding activities in the first nine months of 2015.

Cash used in financing activities was $156 million during the nine months ended September 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 outflows were substantially 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 Granite Ridge Energy Center

In October 2015, we entered into an agreement to purchase Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW, for approximately $500 million, excluding working capital adjustments. The addition of this clean, modern, efficient, natural gas combined-cycle plant in Londonderry, New Hampshire, meaningfully increases our capacity in the tightening New England market. The power plant features two combustion turbines, two heat recovery steam generators and one steam turbine. We expect the transaction to close in the first quarter of 2016, with our guidance reflecting a February 1, 2016, close date. We expect to fund the purchase with a combination of cash on hand and financing.

Acquisition of Champion Energy

In October 2015, we completed the acquisition of 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, PJM 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.

2023 First Lien Notes

In October 2015, we issued notice to the holders of our 2023 First Lien Notes of our intent to redeem 10% of the original aggregate principal amount, plus accrued and unpaid interest. We intend to use cash on hand to fund the redemption.

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 29% of shares outstanding.6

In 2015, through the issuance of this release, we have repurchased a total of 26.6 million shares of our common stock for approximately $529 million at an average price of $19.87 per share.

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

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 and 2018/2019 base residual auctions. The project is now under construction, and we expect commercial operations to commence during the second quarter of 2017. PJM has completed the interconnection study process for an additional 70 MW of planned capacity at the York 2 Energy Center. This incremental 70 MW of planned capacity cleared the 2018/2019 base residual auction.

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 2019, 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: During the first quarter of 2014, we executed an asset sale agreement 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. 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 September 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.

OPERATIONS UPDATE

Third Quarter 2015 Power Operations Achievements

  • Safety Performance:
    — Maintained top quartile7 safety metrics: 0.54 total recordable incident rate
  • Availability Performance:
    — Achieved low fleetwide forced outage factor: 1.8%
    — Delivered exceptional fleetwide starting reliability: 98.6%
  • Power Generation:
    — Seven gas-fired plants with third quarter capacity factors greater than 80%: Bosque, Hermiston, Morgan, Otay Mesa, Pasadena, Pastoria, Stony Brook
    — Hermiston: 0% forced outage factor, 0 starts, 93% capacity factor

Geysers Wildfire Impact

  • In September 2015, a wildfire spread to our Geysers assets in Lake and Sonoma Counties, California, affecting five of our 14 power plants in the region which sustained damage to ancillary structures such as cooling towers and communication/electric deliverability infrastructure. The wildfire has since been contained, and our Geysers assets are generating renewable power for our customers at approximately three-quarters of the normal operating capacity. We expect our insurance program to cover the repair and replacement costs as well as our net revenue losses after deductibles are met. As a result, we do not anticipate that the wildfire will have a material impact on our financial condition, results of operations or cash flows.

Third Quarter 2015 Commercial Operations Achievements:

  • Customer-oriented Growth:
    — Closed accretive acquisition of retail electric provider Champion Energy for $240 million4, consistent with our stated goal of getting closer to our end-use customers
    — Entered into a new one-year resource adequacy contract with Southern California Edison for 238 MW from our Pastoria Energy Center commencing in January 2018

7 According to EEI Safety Survey (2014).

 

2015 & 2016 FINANCIAL OUTLOOK

(in millions, except per share amounts)

 
Full Year 2015     Full Year 2016
Adjusted EBITDA $ 1,965 - 2,000 $ 1,800 - 1,950
Less:
Operating lease payments 30 25
Major maintenance expense and maintenance capital expenditures(1) 460 410
Cash interest, net(2) 625 635
Cash taxes 20 15
Other 5   5  
Adjusted Free Cash Flow $ 825 - 860 $ 710 - 860
Per Share Estimate (diluted) $ 2.25 - 2.35 $ 2.00 - 2.40
 
Debt amortization and repayment (3) $ (460 ) $ (210 )
Growth capital expenditures (net of debt funding) $ (355 ) $ (285 )
Acquisition of Champion Energy(4) $ (240 ) $ -
Acquisition of Granite Ridge Energy Center(4) $ - $ (500 )

(1) Includes projected major maintenance expense of $280 million and maintenance capital expenditures of $180 million in 2015 and major maintenance expense of $270 million and maintenance capital expenditures of $140 million in 2016. 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) 2015 amount 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. Acquisition of Granite Ridge assumed to close on February 1, 2016, for purposes of guidance.

As detailed above, today we are narrowing our 2015 guidance. After incorporating the impacts of the wildfire in Northern California that affected our Geysers assets, we now expect Adjusted EBITDA of $1.965 billion to $2.0 billion and Adjusted Free Cash Flow of $825 million to $860 million, or $2.25 to $2.35 per share. 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.

We are also initiating guidance for 2016. We expected Adjusted EBITDA of $1.8 billion to $1.95 billion and Adjusted Free Cash Flow of $710 million to $860 million, or $2.00 to $2.40 per share. We expect to invest $285 million in our ongoing growth-related projects throughout 2016, primarily the 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 third quarter of 2015 on Friday, October 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 (800) 446-1671 in the U.S. or (847) 413-3362 outside the U.S. The confirmation code is 40715785. 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 40715785. Presentation materials to accompany the conference call will be available on our website on October 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 nearly 27,000 megawatts of generation capacity. Through wholesale power operations and our retail business, Champion Energy, we serve customers in 19 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. Please visit www.calpine.com to learn more about why Calpine is a generation ahead - today, or visit www.championenergyservices.com for details on Champion's award-winning retail electric services.

Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 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, wildfires and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants or retail operations 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, our Quarterly Report on Form 10Q for the quarter ended September 30, 2015, 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 September 30, Nine Months Ended September 30,
2015   2014 2015   2014
(in millions, except share and per share amounts)
Operating revenues:
Commodity revenue $ 1,888 $ 2,186 $ 4,933 $ 6,000
Mark-to-market gain (loss) 55 (2 ) 89 81
Other revenue 5   3   14   10  
Operating revenues 1,948   2,187   5,036   6,091  
Operating expenses:
Fuel and purchased energy expense:
Commodity expense 943 1,281 2,754 3,757
Mark-to-market (gain) loss 130   (13 ) 95   2  
Fuel and purchased energy expense 1,073   1,268   2,849   3,759  
Plant operating expense 200 215 732 754
Depreciation and amortization expense 166 153 484 453
Sales, general and other administrative expense 33 37 100 108
Other operating expenses 16   23   56   66  
Total operating expenses 1,488   1,696   4,221   5,140  
Impairment losses 123 123
(Gain) on sale of assets, net (753 ) (753 )
(Income) from unconsolidated investments in power plants (6 ) (5 ) (18 ) (18 )
Income from operations 466 1,126 833 1,599
Interest expense 159 156 471 491
Interest (income) (1 ) (2 ) (3 ) (5 )
Debt modification and extinguishment costs 340 32 341
Other (income) expense, net 1   4   8   20  
Income before income taxes 307 628 325 752
Income tax expense 28   9   32   5  
Net income 279 619 293 747
Net income attributable to the noncontrolling interest (6 ) (5 ) (11 ) (11 )
Net income attributable to Calpine $ 273   $ 614   $ 282   $ 736  
 
Basic earnings per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 355,443   398,232   365,053   411,534  
Net income per common share attributable to Calpine — basic $ 0.77   $ 1.54   $ 0.77   $ 1.79  
 
Diluted earnings per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 357,676   402,962   368,219   416,056  
Net income per common share attributable to Calpine — diluted $ 0.76   $ 1.52   $ 0.77   $ 1.77  
 
 

CALPINE CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

   
September 30, December 31,
2015 2014
(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 659 $ 717
Accounts receivable, net of allowance of $2 and $4 581 648
Inventories 470 447
Margin deposits and other prepaid expense 204 148
Restricted cash, current 246 195
Derivative assets, current 1,429 2,058
Other current assets 9   7  
Total current assets 3,598 4,220
Property, plant and equipment, net 12,984 13,190
Restricted cash, net of current portion 29 49
Investments in power plants 77 95
Long-term derivative assets 718 439
Long-term assets held for sale 130
Other assets 362   385  
Total assets $ 17,898   $ 18,378  
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable $ 446 $ 580
Accrued interest payable 137 165
Debt, current portion 199 199
Derivative liabilities, current 1,334 1,782
Other current liabilities 307   473  
Total current liabilities 2,423 3,199
Debt, net of current portion 11,465 11,083
Long-term derivative liabilities 501 444
Other long-term liabilities 298   221  
Total liabilities 14,687 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, 504,629,876 and 502,287,022 shares issued, respectively, and 357,831,952 and 381,921,264 shares outstanding, respectively 1 1
Treasury stock, at cost, 146,797,924 and 120,365,758 shares, respectively (2,867 ) (2,345 )
Additional paid-in capital 12,470 12,440
Accumulated deficit (6,258 ) (6,540 )
Accumulated other comprehensive loss (193 ) (178 )
Total Calpine stockholders’ equity 3,153 3,378
Noncontrolling interest 58   53  
Total stockholders’ equity 3,211   3,431  
Total liabilities and stockholders’ equity $ 17,898   $ 18,378  
 
 

CALPINE CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

 
Nine Months Ended September 30,
2015   2014
(in millions)
Cash flows from operating activities:
Net income $ 293 $ 747
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense(1) 519 486
Debt extinguishment costs 35
Deferred income taxes 12 (9 )
Impairment losses 123
(Gain) on sale of assets, net (753 )
Mark-to-market activity, net 4 (88 )
(Income) from unconsolidated investments in power plants (18 ) (18 )
Return on unconsolidated investments in power plants 23 13
Stock-based compensation expense 19 30
Change in operating assets and liabilities:
Accounts receivable 42 (120 )
Derivative instruments, net (44 ) (69 )
Other assets (199 ) 54
Accounts payable and accrued expenses (211 ) 127
Other liabilities 108   (54 )
Net cash provided by operating activities 548   504  
Cash flows from investing activities:
Purchases of property, plant and equipment (411 ) (354 )
Proceeds from sale of power plants, interests and other 1,573
Purchase of Guadalupe Energy Center (656 )
Increase in restricted cash (31 ) (15 )
Other (8 ) 2  
Net cash provided by (used in) investing activities $ (450 ) $ 550  
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 (1,622 ) (34 )
Borrowings under Senior Unsecured Notes 650 2,800
Repurchase of First Lien Notes (147 ) (2,800 )
Borrowings from project financing, notes payable and other 79
Repayments of project financing, notes payable and other (102 ) (116 )
Distribution to noncontrolling interest holder (6 ) (12 )
Financing costs (17 ) (55 )
Stock repurchases (510 ) (767 )
Proceeds from exercises of stock options 6   19  
Net cash used in financing activities (156 ) (466 )
Net increase (decrease) in cash and cash equivalents (58 ) 588
Cash and cash equivalents, beginning of period 717   941  
Cash and cash equivalents, end of period $ 659   $ 1,529  
 
Cash paid during the period for:
Interest, net of amounts capitalized $ 465 $ 534
Income taxes $ 19 $ 19
 
Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable $ (17 ) $ 8
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 September 30, 2015 and 2014 (in millions):

 
Three Months Ended September 30, 2015
  Consolidation  
And
West Texas East Elimination Total
Commodity Margin $ 385 $ 264 $ 325 $ $ 974
Add: Mark-to-market commodity activity, net and other(1) 68 (98 ) (62 ) (7 ) (99 )
Less:
Plant operating expense 87 62 57 (6 ) 200
Depreciation and amortization expense 61 58 48 (1 ) 166
Sales, general and other administrative expense 7 15 10 1 33
Other operating expenses 8 2 8 (2 ) 16
(Income) from unconsolidated investments in power plants     (6 )   (6 )
Income from operations $ 290   $ 29   $ 146   $ 1   $ 466  
 
Three Months Ended September 30, 2014
Consolidation
And
West Texas East Elimination Total
Commodity Margin(2) $ 361 $ 346 $ 237 $ $ 944
Add: Mark-to-market commodity activity, net and other(1) 41 (64 ) 4 (6 ) (25 )
Less:
Plant operating expense 91 77 55 (8 ) 215
Depreciation and amortization expense 65 51 38 (1 ) 153
Sales, general and other administrative expense 11 18 8 37
Other operating expenses 12 1 6 4 23
Impairment losses 123 123
(Gain) on sale of assets, net (753 ) (753 )
(Income) from unconsolidated investments in power plants     (5 )   (5 )
Income from operations $ 223   $ 135   $ 769   $ (1 ) $ 1,126  
 

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

 
Nine Months Ended September 30, 2015
  Consolidation  
And
West Texas East Elimination Total
Commodity Margin $ 843 $ 583 $ 740 $ $ 2,166
Add: Mark-to-market commodity activity, net and other(3) 173 (47 ) (84 ) (21 ) 21
Less:
Plant operating expense 313 233 206 (20 ) 732
Depreciation and amortization expense 193 157 135 (1 ) 484
Sales, general and other administrative expense 23 47 29 1 100
Other operating expenses 28 6 24 (2 ) 56
(Income) from unconsolidated investments in power plants     (18 )   (18 )
Income from operations $ 459   $ 93   $ 280   $ 1   $ 833  
 
Nine Months Ended September 30, 2014
Consolidation
And
West Texas East Elimination Total
Commodity Margin(2) $ 791 $ 644 $ 786 $ $ 2,221
Add: Mark-to-market commodity activity, net and other(3) 91 74 (31 ) (23 ) 111
Less:
Plant operating expense 291 250 237 (24 ) 754
Depreciation and amortization expense 183 141 129 453
Sales, general and other administrative expense 28 48 32 108
Other operating expenses 39 4 22 1 66
Impairment losses 123 123
(Gain) on sale of assets, net (753 ) (753 )
(Income) from unconsolidated investments in power plants     (18 )   (18 )
Income from operations $ 341   $ 275   $ 983   $   $ 1,599  

_________

(1) Includes $41 million and $49 million of lease levelization and $4 million and $4 million of amortization expense for the three months ended September 30, 2015 and 2014, respectively.

(2) Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was not significant for the three months ended September 30, 2014. The Commodity Margin related to those power plants was $81 million for the nine months ended September 30, 2014.

(3) Includes $(1) million and $(7) million of lease levelization and $11 million and $11 million of amortization expense for the nine months ended September 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 attributable to Calpine for the three and nine months ended September 30, 2015 and 2014, as reported under U.S. GAAP (in millions):

   
Three Months Ended September 30, Nine Months Ended September 30,
2015   2014(6) 2015   2014(6)
Net income attributable to Calpine $ 273 $ 614 $ 282 $ 736
Net income attributable to the noncontrolling interest 6 5 11 11
Income tax expense 28 9 32 5
Debt modification and extinguishment costs and other (income) expense, net 1 344 40 361
Interest expense, net of interest income 158   154   468   486  
Income from operations $ 466 $ 1,126 $ 833 $ 1,599
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1) 164 152 480 449
Major maintenance expense 27 36 195 189
Operating lease expense 6 9 23 26
Mark-to-market (gain) loss on commodity derivative activity 75 (11 ) 6 (79 )
Impairment losses 123 123
(Gain) on sale of assets (753 ) (753 )
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest(2) (3 ) (3 ) 6 6
Stock-based compensation expense 7 8 19 30
Loss on dispositions of assets 5 8 1
Acquired contract amortization 4 4 11 11
Other 40   54   5   2  
Total Adjusted EBITDA $ 791   $ 745   $ 1,586   $ 1,604  
Less:
Operating lease payments 6 9 23 26
Major maintenance expense and capital expenditures(3) 51 67 330 326
Cash interest, net(4) 156 160 468 497
Cash taxes 1 2 18 16
Other 1   1   2   4  
Adjusted Free Cash Flow(5) $ 576   $ 506   $ 745   $ 735  
 
Weighted average shares of common stock outstanding (diluted, in thousands) 357,676   402,962   368,219   416,056  
Adjusted Free Cash Flow Per Share (diluted) $ 1.61   $ 1.26   $ 2.02   $ 1.77  

_________

(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 nine months ended September 30, 2015 and 2014.

(3) Includes $29 million and $198 million in major maintenance expense for the three and nine months ended September 30, 2015, respectively, and $22 million and $132 million in maintenance capital expenditure for the three and nine months ended September 30, 2015, respectively. Includes $39 million and $195 million in major maintenance expense for the three and nine months ended September 30, 2014, respectively, and $28 million and $131 million in maintenance capital expenditure for the three and nine months ended September 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 a decrease in working capital of $7 million and an increase of $244 million for the three and nine months ended September 30, 2015, respectively, and an decrease in working capital of $24 million and an increase of $18 million for the three and nine months ended September 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 nil and $43 million for the three and nine months ended September 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 nine months ended September 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 September 30, Nine Months Ended September 30,
2015   2014 2015   2014
Commodity Margin $ 974 $ 944 $ 2,166 $ 2,221
Other revenue 4 3 13 10
Plant operating expense(1) (160 ) (171 ) (510 ) (539 )
Sales, general and administrative expense(2) (31 ) (33 ) (93 ) (93 )
Other operating expenses(3) (12 ) (12 ) (33 ) (36 )
Adjusted EBITDA from unconsolidated investments in power plants 15 13 43 41
Other 1   1      
Adjusted EBITDA $ 791   $ 745   $ 1,586   $ 1,604  

_________

(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) $

165

$

315

Plus:
Debt modification and extinguishment costs 32 32
Interest expense, net of interest income 630 630
Depreciation and amortization expense 645 645
Major maintenance expense

265

265

Operating lease expense 30 30
Other(2) 75   75
Adjusted EBITDA $ 1,965 $ 2,000
Less:
Operating lease payments 30 30
Major maintenance expense and maintenance capital expenditures(3) 460 460
Cash interest, net(4) 625 625
Cash taxes 20 20
Other 5   5
Adjusted Free Cash Flow $ 825 $ 860

_________

(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 $280 million and maintenance capital expenditures of $180 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.

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

   
Full Year 2016 Range: Low High
GAAP Net Income (1) $ 180 $ 330
Plus:
Debt modification and extinguishment costs
Interest expense, net of interest income 640 640
Depreciation and amortization expense 610 610
Major maintenance expense 250 250
Operating lease expense 25 25
Other(2) 95   95
Adjusted EBITDA $ 1,800 $ 1,950
Less:
Operating lease payments 25 25
Major maintenance expense and maintenance capital expenditures(3) 410 410
Cash interest, net(4) 635 635
Cash taxes 15 15
Other 5   5
Adjusted Free Cash Flow $ 710 $ 860

_________

(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 $270 million and maintenance capital expenditures of $140 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 September 30, Nine Months Ended September 30,
2015   2014 2015   2014
Total MWh generated (in thousands)(1) 32,583 28,449 85,104 74,511
West 10,117 9,634 25,800 25,235
Texas 13,576 11,924 36,314 28,290
East 8,890 6,891 22,990 20,986
 
Average availability 97.0 % 96.6 % 90.8 % 90.9 %
West 97.6 % 98.6 % 89.6 % 93.1 %
Texas 97.2 % 96.3 % 90.9 % 90.2 %
East 96.2 % 95.1 % 91.6 % 89.8 %
 
Average capacity factor, excluding peakers 63.3 % 57.7 % 56.3 % 47.1 %
West 66.0 % 61.9 % 56.1 % 54.7 %
Texas 66.9 % 58.8 % 60.3 % 49.4 %
East 55.8 % 50.8 % 50.9 % 38.0 %
 
Steam adjusted heat rate (Btu/kWh) 7,336 7,402 7,312 7,396
West 7,333 7,325 7,322 7,310
Texas 7,111 7,215 7,096 7,222
East 7,710 7,848 7,660 7,733

________

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

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


Source: Business Wire (October 30, 2015 - 6:00 AM EDT)

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