Calpine Reports Third Quarter Results, Narrows 2014 Guidance and Provides 2015 Guidance

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

“Calpine delivered another strong quarter both operationally and commercially, especially considering the mild summer weather in much of the country”

Summary of Third Quarter 2014 Financial Results (in millions, except per share amounts):

   
Three Months Ended September 30, Nine Months Ended September 30,
2014   2013   % Change 2014   2013   % Change
 
Operating Revenues $ 2,187 $ 2,050 6.7 % $ 6,091 $ 4,863 25.3 %
Commodity Margin $ 944 $ 985

(4.2)

%

$ 2,221 $ 1,979 12.2 %
Adjusted EBITDA $ 745 $ 802

(7.1)

%

$ 1,604 $ 1,431 12.1 %
Adjusted Free Cash Flow $ 506 $ 556 $ 735 $ 551
Per Share (diluted) $ 1.26 $ 1.27 $ 1.77 $ 1.23
Net Income1 $ 614 $ 306 $ 736 $ 111
Per Share (diluted) $ 1.52 $ 0.70 $ 1.77 $ 0.25
Net Income, As Adjusted2 $ 306 $ 268 $ 359 $ 165
 

Narrowing 2014 and Providing 2015 Full Year Guidance (in millions, except per share amounts):

     
2014 2015

Growth
Rate3

 
Adjusted EBITDA $1,915 - 1,965 $1,900 - 2,100 3.1%
Adjusted Free Cash Flow $800 - 850 $810 - 1,010 10.3%
Per Share Estimate (diluted) $1.90 - 2.05 $2.10 - 2.60 19.0%
 

Recent Achievements:

  • Power and Commercial Operations:
    — Generated approximately 29 million MWh4 of electricity in third quarter of 2014
    — Achieved low year-to-date fleetwide forced outage factor: 2.1%
    — Successfully originated several new contracts, including those related to our Geysers assets, Delta, Pastoria and Osprey power plants and our Texas power plant fleet
  • Portfolio Management:
    — Announced acquisition of Fore River Energy Center, a nameplate 809 MW combined-cycle and dual-fuel capable power plant in Massachusetts, for approximately $530 million, or $655/kW
  • Capital Allocation Progress:
    — Deployed approximately $3.1 billion of capital year-to-date toward share repurchase, balance sheet management, organic growth and acquisitions
    — Completed approximately $308 million of share repurchases since last earnings announcement, bringing total 2014 repurchases to approximately $949 million
    — Issued notice to call approximately $120 million of our 7.875% First Lien Notes due 2023 at a price of 103 during the fourth quarter

Calpine Corporation (NYSE: CPN) today reported third quarter 2014 Adjusted EBITDA of $745 million, compared to $802 million in the prior year period, and Adjusted Free Cash Flow of $506 million, or $1.26 per diluted share, compared to $556 million, or $1.27 per diluted share, in the prior year period. The decreases in Adjusted EBITDA and Adjusted Free Cash Flow were primarily due to lower Commodity Margin driven largely by the sale of six power plants in July 2014. Net Income1 for the third quarter of 2014 was $614 million, or $1.52 per diluted share, compared to $306 million, or $0.70 per diluted share, in the prior year period. The increase in Net Income1 was primarily due to a gain on the previously referenced asset sale, partially offset by higher debt extinguishment costs and impairment losses. Net Income, As Adjusted2, for the third quarter of 2014 was $306 million compared to $268 million in the prior year period. The increase in Net Income, As Adjusted2, was primarily due to a decrease in income tax expense associated with intraperiod tax allocations, which more than offset the previously discussed decrease in Adjusted EBITDA.

Year-to-date 2014 Adjusted EBITDA was $1,604 million, compared to $1,431 million in the prior year period, and Adjusted Free Cash Flow was $735 million, or $1.77 per diluted share, compared to $551 million, or $1.23 per diluted share, in the prior year period. Net Income1 for the first nine months of 2014 was $736 million, or $1.77 per diluted share, compared to $111 million, or $0.25 per diluted share, in the prior year period. The increase in Net Income1 was primarily due to higher Commodity Margin, as well as those factors that drove comparative performance for the third quarter, as described above. Net Income, As Adjusted2, for the first nine months of 2014 was $359 million compared to $165 million in the prior year period. The increases in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted2, compared to the prior year period were primarily due to higher Commodity Margin resulting from stronger market conditions, net portfolio changes and higher regulatory capacity revenue.

“Calpine delivered another strong quarter both operationally and commercially, especially considering the mild summer weather in much of the country,” said Thad Hill, Calpine’s President and Chief Executive Officer. “We benefited from timely hedging, new capacity and operational excellence throughout our fleet. Meanwhile, we also further positioned Calpine for the future, announcing the pending acquisition of Fore River Energy Center in New England, originating several new contracts in California and Texas, and advancing construction of Garrison Energy Center in Delaware and development of York 2 Energy Center in Pennsylvania.

“Our clean, modern, efficient and flexible fleet is poised to benefit from the secular trends playing out in the U.S. power generation industry. In the East, our reliable operations and dual-fuel capabilities position us to take advantage of tighter markets given the significant upcoming capacity retirements and provide us the confidence to be a meaningful participant in capacity markets that will command a premium for performance. Our Texas fleet is poised to benefit from strong demand growth, pending environmental regulations and increasing volatility from the addition of intermittent wind. Finally, we continue to position our California fleet for long-term stability through contracts to support the integration of intermittent resources.

“Calpine remains firmly committed to enhancing shareholder value through disciplined and accretive capital allocation. We are on track in 2014 to redeploy more than $3 billion of capital into attractive growth opportunities, debt repayment and share repurchases. Among these, we balance share repurchases with our ability to respond to other opportunities in the marketplace. Our foremost objective is to maximize levered cash-on-cash returns to equity, as measured by Adjusted Free Cash Flow Per Share, while being prudent with the balance sheet. We are pleased to provide 2015 guidance today, that, at the midpoint of the ranges, represents an increase in Adjusted Free Cash Flow Per Share of approximately 19% over 2014.”

__________

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 Assuming midpoints of 2014 and 2015 guidance ranges.

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

SUMMARY OF FINANCIAL PERFORMANCE

Third Quarter Results

Adjusted EBITDA for the third quarter of 2014 was $745 million compared to $802 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to a $41 million decrease in Commodity Margin, which was largely due to:

              the sale of six power plants with a total capacity of 3,498 MW in our East segment on July 3, 2014
lower regulatory capacity revenue in PJM and

the expiration of a tolling contract associated with our Delta Energy Center in December 2013 and a previously existing PPA associated with our Osprey Energy Center in May 2014, partially offset by

+ our Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013, the acquisition of Guadalupe Energy Center in February 2014 and the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014 and
+ stronger market conditions resulting in higher market spark spreads in the West and East segments.
 

Net Income1 was $614 million for the third quarter of 2014, compared to $306 million in the prior year period. The year-over-year improvement in Net Income1 was primarily due to a gain on the previously referenced asset sale, partially offset by higher debt extinguishment costs and impairment losses related to our Osprey Energy Center. As detailed in Table 1, Net Income, As Adjusted2, was $306 million in the third quarter of 2014 compared to $268 million in the prior year period. The year-over-year improvement was driven largely by:

            +   lower income tax expense due to differences in intraperiod tax allocations, partially offset by
lower Commodity Margin, as previously discussed and
higher plant operating expense driven primarily by an increase in equipment failure costs related to outages and other expenses.
 

Adjusted Free Cash Flow was $506 million in the third quarter of 2014 compared to $556 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.

Year-to-Date Results

Adjusted EBITDA for the nine months ended September 30, 2014, was $1,604 million compared to $1,431 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily due to a $242 million increase in Commodity Margin which was primarily related to:

            +   our Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013, the acquisition of Guadalupe Energy Center in February 2014 and the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014
+ higher contribution from our dual-fueled power plants in the East during the first quarter of 2014 when fuel oil prices were lower than natural gas prices
+

higher regulatory capacity revenue in PJM during the first half of the year and

+ stronger market conditions resulting in higher market spark spreads in the West, partially offset by
the sale of six power plants with a total capacity of 3,498 MW in our East segment on July 3, 2014
lower contribution from hedges and

the expiration of a tolling contract associated with our Delta Energy Center in December 2013 and a previously existing PPA associated with our Osprey Energy Center in May 2014.

 

Net Income1 was $736 million for the nine months ended September 30, 2014, compared to $111 million in the prior year period. In addition to the previously mentioned factors that drove similar improvements in Net Income1 for the third quarter, Net Income1 for the nine months ended September 30, 2014, also increased as a result of higher Commodity Margin, as previously discussed. As detailed in Table 1, Net Income, As Adjusted2, was $359 million in the nine months ended September 30, 2014, compared to $165 million in the prior year period. The year-over-year improvement was driven largely by:

            +   higher Commodity Margin and
+ lower interest expense associated with a decrease in our annual effective interest rate, partially offset by
higher plant operating expense driven primarily by portfolio changes, higher equipment failure expense related to outages and the reversal in 2013 of previously recognized regulatory fees that did not recur in 2014.
 

Adjusted Free Cash Flow was $735 million for the nine months ended September 30, 2014, compared to $551 million in the prior year period. The increase in Adjusted Free Cash Flow during the period was primarily due to an increase in Adjusted EBITDA, as previously discussed.

Table 1: Net Income, As Adjusted

   
Three Months Ended September 30, Nine Months Ended September 30,
2014   2013 2014   2013
(in millions) (in millions)
Net income attributable to Calpine $ 614 $ 306 $ 736 $ 111
Impairment losses(1) 123 123
(Gain) on sale of assets, net (753 ) (753 )
Debt extinguishment costs(1) 340 341 68
MtM gain on derivatives(1)(2) (18 ) (38 ) (88 ) (14 )
Net Income, As Adjusted(3) $ 306   $ 268   $ 359   $ 165  
 

__________

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

(2) In addition to changes in market value on derivatives not designated as hedges, changes in 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) 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,
2014   2013   Variance 2014   2013   Variance
West $ 361 $ 337 $ 24 $ 791 $ 737 $ 54
Texas 346 328 18 644 537 107
East 237   320   (83 ) 786   705   81
Total $ 944   $ 985   $ (41 ) $ 2,221   $ 1,979   $ 242
 

West Region

Third Quarter: Commodity Margin in our West segment increased by $24 million in the third quarter of 2014 compared to the prior year period. Primary drivers were:

            +   the commencement of commercial operations at our contracted Russell City and Los Esteros power plants in August 2013 and
+ higher spark spreads due to stronger market conditions resulting from warmer weather and lower hydroelectric generation, partially offset by
the expiration of a tolling contract associated with our Delta Energy Center in December 2013 and
lower contribution from hedges.
 

Year-to-Date: Commodity Margin in our West segment increased by $54 million for the nine months ended September 30, 2014, compared to the prior year period. The year-to-date results were largely impacted by the same factors that drove comparative performance for the third quarter, as previously discussed.

Texas Region

Third Quarter: Commodity Margin in our Texas segment increased by $18 million in the third quarter of 2014 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, which were completed in June 2014, partially offset by
lower spark spreads resulting from weaker market conditions.
 

Year-to-Date: Commodity Margin in our Texas segment increased by $107 million for the nine months ended September 30, 2014, 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, which were completed in June 2014
+ higher spark spreads resulting from stronger market conditions in the first quarter of 2014 and
+ higher contribution from hedges.
 

East Region

Third Quarter: Commodity Margin in our East segment decreased by $18 million in the third quarter of 2014 compared to the prior year period, after excluding a decrease of $65 million resulting from the sale of six power plants with a total capacity of 3,498 MW on July 3, 2014. Primary drivers were:

              lower regulatory capacity revenues in PJM and
the expiration of a previously existing PPA associated with our Osprey Energy Center in May 2014, partially offset by
+ higher contribution from hedges and
+ higher spark spreads realized by our Mid-Atlantic plants that benefit from their proximity to discounted Marcellus natural gas.
 

Year-to-Date: Commodity Margin in our East segment increased by $122 million for the nine months ended September 30, 2014, compared to the prior year period, after excluding a decrease of $41 million resulting from the previously discussed sale of six power plants. Primary drivers were:

            +  

higher margins resulting from stronger market conditions due to colder than normal weather during the first quarter of 2014

+ higher contribution from our dual-fueled plants during the first quarter of 2014 when fuel oil prices were lower than natural gas prices and
+ higher regulatory capacity revenue in PJM during first half of the year, partially offset by
lower contribution from hedges and
the expiration of a previously existing PPA associated with our Osprey Energy Center in May 2014.
 

LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES

Table 3: Liquidity

   
September 30, December 31,
2014 2013
(in millions)
Cash and cash equivalents, corporate(1) $ 1,300 $ 649
Cash and cash equivalents, non-corporate 229   292
Total cash and cash equivalents 1,529 941
Restricted cash 286 272
Corporate Revolving Facility availability(2) 1,294 758
CDHI letter of credit availability 101   7
Total current liquidity availability $ 3,210   $ 1,978
 

__________

(1) Includes $67 million and $5 million of margin deposits posted with us by our counterparties at September 30, 2014, and December 31, 2013, respectively.

(2) On July 30, 2014, we amended our Corporate Revolving Facility to increase the capacity by an additional $500 million to $1.5 billion.

Liquidity grew to approximately $3.2 billion as of September 30, 2014. Cash and cash equivalents increased during the nine months ended September 30, 2014, primarily due to the receipt of proceeds from the sale of six power plants in our East segment in July 2014. Availability under our Corporate Revolving Facility increased primarily as a result of an amendment that raised its capacity by $500 million during the third quarter of 2014.

Table 4: Cash Flow Activities

 
Nine Months Ended September 30,
2014   2013
(in millions)
Beginning cash and cash equivalents $ 941   $ 1,284  
Net cash provided by (used in):
Operating activities 504 415
Investing activities 550 (468 )
Financing activities (466 ) (207 )
Net increase (decrease) in cash and cash equivalents 588   (260 )
Ending cash and cash equivalents $ 1,529   $ 1,024  
 

Cash flows provided by operating activities in the nine months ended September 30, 2014, were $504 million compared to $415 million in the prior year period. The increase in cash provided by operating activities was primarily due to an increase in income from operations (adjusted for non-cash items). Also contributing to the increase was a decrease in working capital employed, largely due to lower net margin requirements partially offset by an increase in net accounts receivable/payable balances resulting from higher Commodity Margin. Partially offsetting these increases, debt extinguishment payments increased due to the refinancing of our First Lien Notes during the first nine months of 2014.

Cash flows provided by investing activities during the nine months ended September 30, 2014, were $550 million compared to cash flows used in investing activities of $468 million in the prior year period. The increase was primarily due to $1.57 billion of proceeds received in 2014 from the sale of six power plants in our East segment, partially offset by $656 million used to purchase our Guadalupe Energy Center.

Cash flows used in financing activities were $466 million and were primarily related to payments associated with execution of our share repurchase program, partially offset by the issuance of CCFC Term Loans used to fund a portion of the purchase price of our Guadalupe Energy Center.

CAPITAL ALLOCATION

Share Repurchase Program

During 2014, we repurchased a total of 42,754,300 shares of our common stock for approximately $949 million at an average price of $22.19 per share. Included in the total 2014 activity is the repurchase of 13,213,372 shares of our common stock from a shareholder for approximately $311 million in a private transaction completed in July 2014 that was approved by our Board of Directors.

Fore River Energy Center

On August 22, 2014, we entered into an agreement to purchase Fore River Energy Center, a power plant with a nameplate capacity of 809 MW, for approximately $530 million, excluding working capital adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant located in North Weymouth, Massachusetts, will increase capacity in our East segment, specifically the constrained New England market. The plant features two combustion turbines, two heat recovery steam generators and one steam turbine. We expect the transaction to close in the fourth quarter of 2014 and expect to fund the acquisition with cash on hand or financing.

Osprey Energy Center

In August 2014, we executed a term sheet with Duke Energy Florida, Inc. related to our Osprey Energy Center for a new PPA with a term of up to 27 months, after which Duke Energy Florida, Inc. would purchase our Osprey Energy Center. Although a definitive asset sale agreement is still being negotiated, and any such agreement would be subject to regulatory approval, the potential sale of our Osprey Energy Center represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities.

Sale of Six Southeast Power Plants

On July 3, 2014, we completed the sale of six of our power plants in the East segment for a purchase price of approximately $1.57 billion in cash, excluding working capital and other adjustments. The divestiture of these power plants has better aligned our asset base with our strategic focus on competitive wholesale markets.

Refinancing of First Lien Notes with Senior Unsecured Notes

On July 22, 2014, we refinanced $2.8 billion of senior secured notes with an equivalent amount of senior unsecured notes. We issued $1.25 billion in aggregate principal amount of 5.375% senior unsecured notes due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior unsecured notes due 2025 in a public offering, representing the inaugural issuance of unsecured debt within our capital structure. We used the net proceeds, together with cash on hand, to repurchase our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes, which carried interest rates of 7.50% - 8.00%. In connection with this refinancing, we incurred approximately $350 million in early retirement premiums and fees, and we expect to achieve annual interest savings of approximately $60 million.

2023 First Lien Notes

In November 2014, 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.

PLANT DEVELOPMENT

Texas:

Channel and Deer Park Expansions: In June of 2014, we completed construction to expand the baseload capacity of our Deer Park and Channel Energy Centers by approximately 260 MW5 each. Each power plant featured an oversized steam turbine that, along with existing plant infrastructure, allowed us to add capacity and improve the power plant’s overall efficiency at a meaningful discount to the market cost of building new capacity.

Guadalupe Energy Center: On February 26, 2014, we completed the purchase of a 1,050 MW nameplate capacity power plant for approximately $625 million, excluding working capital adjustments. We funded the acquisition with $425 million of incremental CCFC Term Loans and cash on hand. The addition of this modern, natural gas-fired, combined-cycle power plant increased capacity in our Texas segment, which is one of our core markets. We also paid $15 million to acquire the rights to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker. Development efforts are ongoing and we are continuing to advance entitlements (such as permits, zoning and transmission).

East:

Garrison Energy Center: Garrison Energy Center is a 309 MW combined-cycle project located in Delaware on a site secured by a long-term lease with the City of Dover. Once complete, the power plant will feature one combustion turbine, one heat recovery steam generator and one steam turbine. Construction commenced in April 2013, and we expect commercial operations to commence during the second quarter of 2015. The project’s capacity has cleared each of PJM’s three most recent base residual auctions. We are in the early stages of development of a second phase (309 MW) of this project. PJM has completed the feasibility and system impact studies for this phase, and the facilities study is currently underway.

Mankato Power Plant Expansion: We are proposing a 345 MW expansion of the Mankato Power Plant in response to a competitive resource acquisition process established by the Minnesota Public Utilities Commission (“MPUC”) to acquire up to approximately 500 MW of new capacity. The initial stage of the proceeding was managed via a contested case hearing. On March 27, 2014, the MPUC directed Xcel Energy (Northern States Power) to negotiate PPAs with Calpine and certain other entities. Xcel Energy filed the negotiated PPAs on September 23, 2014, but recommended that the MPUC delay approval. The MPUC is expected to decide whether to approve one or more PPAs or to delay the pending resource acquisition process during deliberations later this year.

York 2 Energy Center: York 2 Energy Center is a 760 MW dual-fueled 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. PJM has completed the project’s feasibility and system impact studies, and the facilities study is underway. The project’s capacity cleared PJM’s 2017/2018 base residual auction, and we expect commercial operations to commence during the second quarter of 2017. The project’s key permits and approvals are being actively pursued and major equipment purchase commitments were executed during the third quarter of 2014.

PJM Development Opportunities: We are currently evaluating opportunities to develop additional projects in the PJM market area 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.

All Segments:

Turbine Modernization: We continue to move forward with our turbine modernization program. Through September 30, 2014, we have completed the upgrade of thirteen Siemens and eight GE turbines totaling approximately 210 MW and have committed to upgrade approximately three additional turbines. Similarly, we have the opportunity at several of our power plants in Texas to implement further turbine modernizations to add as much as 500 MW of incremental capacity across the region at attractive prices. In addition, we have begun a program to update our dual-fueled turbines at certain of our power plants in our East segment. Our decision to invest in these turbine modernizations depends upon, among other things, further clarity on market design reforms currently being considered.

___________

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

OPERATIONS UPDATE

Third Quarter 2014 Power Operations Achievements

  • Safety Performance:
    — Maintained top quartile6 safety metrics: 0.70 Total Recordable Incident Rate year-to-date
  • Availability Performance:
    — Achieved low fleetwide forced outage factor: 2.3%
    — Delivered strong fleetwide starting reliability: 99%
  • Power Generation:
    — Provided approximately 1.5 million MWh of renewable baseload generation from our Geysers geothermal plants
    — Pastoria Energy Center: 94% capacity factor and 0% forced outage factor
    — King City Cogen: 100% availability factor, 100% starting reliability and 0% forced outage factor

Third Quarter 2014 Commercial Operations Achievements:

  • Customer-oriented Growth:
    — We entered into a new one-year PPA with Guadalupe Valley Electric Cooperative to provide approximately 270 MW of power from our Texas power plant fleet commencing in June 2016
    — We entered into a new ten-year PPA with the Sonoma Clean Power Authority to provide 15 MW of renewable power from our Geysers assets commencing in January 2017. The capacity under contract will vary by year, increasing up to a maximum of 50 MW for years 2024 through 2026
    — We entered into a new three-year resource adequacy contract with Southern California Edison (SCE) for our Pastoria Energy Facility commencing in January 2016. The capacity under contract will initially be 238 MW and will increase to 476 MW during the final year of the contract
    — We entered into a new two-year resource adequacy contract with SCE for our Delta Energy Center for 500 MW of capacity commencing in January 2017
    — We entered into a new PPA with a term of up to 27 months with Duke Energy Florida, Inc., subject to certain approvals, to provide 515 MW of power and capacity from our Osprey Energy Center which commenced in October 2014.

___________

6 According to EEI Safety Survey (2013).

2014 & 2015 FINANCIAL OUTLOOK

(in millions, except per share amounts)

   
Full Year 2014 Full Year 2015
Adjusted EBITDA $ 1,915 - 1,965 $ 1,900 - 2,100
Less:
Operating lease payments 35 35
Major maintenance expense and maintenance capital expenditures(1) 405 395
Cash interest, net(2) 650 630
Cash taxes 20 25
Other 5   5  
Adjusted Free Cash Flow $ 800 - 850   $ 810 - 1,010  
Per Share Estimate (diluted) $ 1.90 - 2.05 $ 2.10 - 2.60
 
Debt amortization(3) $ (320 ) $ (210 )
Growth capital expenditures (net of debt funding) $ (275 ) $ (355 )
 

________

(1) Includes projected major maintenance expense of $240 million and $235 million and maintenance capital expenditures of $165 million and $160 million in 2014 and 2015, respectively. 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 $120 million of 2023 First Lien Notes to be redeemed in the fourth quarter of 2014.

As detailed above, today we are narrowing our 2014 guidance. We now project Adjusted EBITDA of $1,915 million to $1,965 million, Adjusted Free Cash Flow of $800 million to $850 million and Adjusted Free Cash Flow Per Share of $1.90 to $2.05.

We are also initiating guidance for 2015. We expect Adjusted EBITDA of $1,900 million to $2,100 million, Adjusted Free Cash Flow of $810 million to $1,010 million and Adjusted Free Cash Flow Per Share of $2.10 to $2.60. We also expect to invest $355 million in our ongoing growth-related projects during the year, including the expected completion of our Garrison Energy Center and the start of 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 2014 on Thursday, November 6, 2014, 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) 447-0521 in the U.S. or (847) 413-3238 outside the U.S. The confirmation code is 38036868. 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 38036868. Presentation materials to accompany the conference call will be available on our website on November 6, 2014.

ABOUT CALPINE

Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources. Our fleet of 87 power plants in operation or under construction represents approximately 26,000 megawatts of generation capacity. Serving customers in 17 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 September 30, 2014, 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 to hedge risks;
  • Laws, regulations and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate;
  • Our ability to manage our liquidity needs and to 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;
  • The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated thereunder;
  • Competition, including risks associated with marketing and selling power in the evolving energy markets;
  • Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools;
  • The expiration or early termination of our PPAs and the related results on revenues;
  • Future capacity revenues may not occur at expected levels;
  • Natural disasters, such as hurricanes, earthquakes and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants serve and our corporate headquarters;
  • Disruptions in or limitations on the transportation of natural gas, fuel oil and transmission of power;
  • Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions;
  • Our ability to attract, motivate and retain key employees;
  • Present and possible future claims, litigation and enforcement actions; and
  • Other risks identified in this press release and in our 2013 Form 10-K.

Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.

 

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

   
Three Months Ended September 30, Nine Months Ended September 30,
2014   2013 2014   2013
(in millions, except share and per share amounts)
Operating revenues:
Commodity revenue $ 2,186 $ 2,020 $ 6,000 $ 4,867
Mark-to-market gain (loss) (2 ) 26 81 (14 )
Other revenue 3   4   10   10  
Operating revenues 2,187   2,050   6,091   4,863  
Operating expenses:
Fuel and purchased energy expense:
Commodity expense 1,281 1,076 3,757 2,909
Mark-to-market (gain) loss (13 ) (17 ) 2   (29 )
Fuel and purchased energy expense 1,268   1,059   3,759   2,880  
Plant operating expense 215 200 754 684
Depreciation and amortization expense 153 150 453 441
Sales, general and other administrative expense 37 33 108 102
Other operating expenses 23   20   66   58  
Total operating expenses 1,696   1,462   5,140   4,165  
Impairment losses 123 123
(Gain) on sale of assets, net (753 ) (753 )
(Income) from unconsolidated investments in power plants (5 ) (9 ) (18 ) (25 )
Income from operations 1,126 597 1,599 723
Interest expense 156 176 491 522
Interest (income) (2 ) (2 ) (5 ) (5 )
Debt extinguishment costs 340 341 68
Other (income) expense, net 4   7   20   15  
Income before income taxes 628 416 752 123
Income tax expense 9   110   5   12  
Net income 619 306 747 111
Net income attributable to the noncontrolling interest (5 )   (11 )  
Net income attributable to Calpine $ 614   $ 306   $ 736   $ 111  

Basic earnings per common share attributable to Calpine:

Weighted average shares of common stock outstanding (in thousands)

 

398,232

   

434,384

   

411,534

   

444,486

 

Net income per common share attributable to Calpine — basic

$

1.54

 

$

0.70

 

$

1.79

 

$

0.25

 

Diluted earnings per common share attributable to Calpine:

Weighted average shares of common stock outstanding (in thousands)

$

402,962

 

$

438,493

 

$

416,056

 

$

448,546

 

Net income per common share attributable to Calpine — diluted

$

1.52

 

$

0.70

 

$

1.77

 

$

0.25

 
 
 

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

 

 

 

September 30,

December 31,

2014

2013
(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 1,529 $ 941
Accounts receivable, net of allowance of $5 and $5 680 552
Inventories 353 364
Margin deposits and other prepaid expense 224 309
Restricted cash, current 244 203
Derivative assets, current 549 445
Other current assets 37   42  
Total current assets 3,616 2,856
Property, plant and equipment, net 12,665 12,995
Restricted cash, net of current portion 42 69
Investments in power plants 92 93
Long-term derivative assets 295 105
Other assets 462   441  
Total assets $ 17,172   $ 16,559  
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable $ 560 $ 462
Accrued interest payable 95 162
Debt, current portion 194 204
Derivative liabilities, current 534 451
Other current liabilities 377   252  

Total current liabilities

1,760 1,531
Debt, net of current portion 11,260 10,908
Long-term derivative liabilities 295 243
Other long-term liabilities 297   309  
Total liabilities 13,612 12,991
 
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, 502,233,764 and 497,841,056 shares issued, respectively, and 397,280,391 and 429,038,988 shares outstanding, respectively 1 1
Treasury stock, at cost, 104,953,373 and 68,802,068 shares, respectively (2,011 ) (1,230 )
Additional paid-in capital 12,432 12,389
Accumulated deficit (6,750 ) (7,486 )
Accumulated other comprehensive loss (164 ) (160 )
Total Calpine stockholders’ equity 3,508 3,514
Noncontrolling interest 52   54  
Total stockholders’ equity 3,560   3,568  
Total liabilities and stockholders’ equity $ 17,172   $ 16,559  
 
 

CALPINE CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

 
Nine Months Ended September 30,
2014   2013
(in millions)
Cash flows from operating activities:
Net income $ 747 $ 111
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense(1) 486 474
Debt extinguishment costs 35 28
Deferred income taxes (9 ) 18
Impairment losses 123
(Gain) on sale of assets, net (753 )
Mark-to-market activity, net (88 )

(14

)

(Income) from unconsolidated investments in power plants (18 )

(25

)

Return on unconsolidated investments in power plants 13 23
Stock-based compensation expense 30 28
Other 3
Change in operating assets and liabilities:
Accounts receivable (120 )

(219

)

Derivative instruments, net (69 ) 47
Other assets 54

(111

)

Accounts payable and accrued expenses 127

(11

)

Other liabilities (54 ) 63  
Net cash provided by operating activities 504   415  
Cash flows from investing activities:
Purchases of property, plant and equipment (354 )

(472

)

Proceeds from sale of power plants, interests and other 1,573
Purchase of Guadalupe Energy Center, net of cash (656 )
(Increase) decrease in restricted cash (15 ) 5
Other 2  

(1

)

Net cash provided by (used in) investing activities

 

550  

 

(468

)

Cash flows from financing activities:
Borrowings under CCFC Term Loans

 

420

 

1,197
Repayment of CCFC Term Loans, CCFC Notes and First Lien Term Loans (34 )

(1,022

)

Borrowings under Senior Unsecured Notes 2,800
Repayments of First Lien Notes (2,800 )
Borrowings from project financing, notes payable and other 79 139
Repayments of project financing, notes payable and other (116 )

(51

)

Distribution to noncontrolling interest holder (12 )
Financing costs (55 )

(27

)

Stock repurchases (767 )

(462

)

Proceeds from exercises of stock options 19   19  
Net cash used in financing activities (466 )

(207

)

Net increase (decrease) in cash and cash equivalents 588

(260

)

Cash and cash equivalents, beginning of period 941   1,284  
Cash and cash equivalents, end of period $ 1,529   $ 1,024  
 
Cash paid during the period for:
Interest, net of amounts capitalized $ 534 $ 547
Income taxes $ 19 $ 22
 
Supplemental disclosure of non-cash investing activities:
Change in capital expenditures included in accounts payable $ 8 $ 10
 

__________

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

REGULATION G RECONCILIATIONS

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

Net Income (Loss), As Adjusted, represents net income (loss) attributable to Calpine, adjusted for certain non-cash and non-recurring items as previously detailed in Table 1, including mark-to-market (gain) loss on derivatives, and other adjustments. Net Income (Loss), As Adjusted, is presented because we believe it is a useful tool for assessing the operating performance of our company in the current period. Net Income (Loss), As Adjusted, is not intended to represent net income (loss), the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, revenue from renewable energy credits, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities including natural gas transactions hedging future power sales, 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 (loss) from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

Adjusted EBITDA represents net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization, adjusted for certain non-cash and non-recurring items as detailed in the following reconciliation. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

We believe Adjusted EBITDA is 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 effects 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 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

During the third quarter of 2014, we altered the composition of our geographic segments to combine our former North and Southeast segments into one segment which was renamed the East segment. This change reflects the manner in which our geographic information is presented internally to our chief operating decision maker following the sale of six power plants in July 2014 from what was formerly our Southeast segment. Thus, beginning in the third quarter of 2014, our reportable segments are West (including geothermal), Texas and East (including North, Southeast and Canada).

During the fourth quarter of 2013, we changed the methodology previously used during 2013 for allocating corporate expenses to our segments. This change had no impact to our Consolidated Condensed Statements of Operations for the three and nine months ended September 30, 2013; however, segment amounts previously reported for the three and nine months ended September 30, 2013, were adjusted by immaterial amounts.

The following tables reconcile our Commodity Margin to its U.S. GAAP results for the three months ended September 30, 2014 and 2013 (in millions):

 
Three Months Ended September 30, 2014
      Consolidation  
And
West Texas East Elimination Total
Commodity Margin(1) $ 361 $ 346 $ 237 $ $ 944
Add: Mark-to-market commodity activity, net and other(2) 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  
 
 
Three Months Ended September 30, 2013
      Consolidation  
And
West Texas East Elimination Total
Commodity Margin(1) $ 337 $ 328 $ 320 $ $ 985
Add: Mark-to-market commodity activity, net and other(2) 16 (5 ) 3 (8 ) 6
Less:
Plant operating expense 84 56 67 (7 ) 200
Depreciation and amortization expense 58 41 51 150
Sales, general and other administrative expense 9 13 10 1 33
Other operating expenses 12 2 9 (3 ) 20
(Income) from unconsolidated investments in power plants     (9 )   (9 )
Income from operations $ 190   $ 211   $ 195   $ 1   $ 597  
 

The following tables reconcile our Commodity Margin to its U.S. GAAP results for the nine months ended September 30, 2014 and 2013 (in millions):

 
Nine Months Ended September 30, 2014
      Consolidation  
And
West Texas East Elimination Total
Commodity Margin(3) $ 791 $ 644 $ 786 $ $ 2,221
Add: Mark-to-market commodity activity, net and other(4) 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  
 
 
Nine Months Ended September 30, 2013
      Consolidation  
And
West Texas East Elimination Total
Commodity Margin(3) $ 737 $ 537 $ 705 $ $ 1,979
Add: Mark-to-market commodity activity, net and other(4) (2 ) 18 12 (24 ) 4
Less:
Plant operating expense 271 214 221 (22 ) 684
Depreciation and amortization expense 164 125 153 (1 ) 441
Sales, general and other administrative expense 24 43 34 1 102
Other operating expenses 33 4 25 (4 ) 58
(Income) from unconsolidated investments in power plants     (25 )   (25 )
Income from operations $ 243   $ 169   $ 309   $ 2   $ 723  
 

_________

(1) 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. Commodity Margin related to these plants was $65 million for the three months ended September 30, 2013.

(2) Includes $49 million and $44 million of lease levelization and $4 million and $4 million of amortization expense for the three months ended September 30, 2014 and 2013, respectively.

(3) Our East segment includes Commodity Margin of $81 million and $122 million for the nine months ended September 30, 2014 and 2013, respectively, related to the six power plants in our East segment that were sold in July 2014.

(4) Includes $(7) million and $17 million of lease levelization and $11 million and $11 million of amortization expense for the nine months ended September 30, 2014 and 2013, 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, 2014 and 2013, as reported under U.S. GAAP.

   

Three Months Ended
September 30,

Nine Months Ended
September 30,

2014(1)   2013(1) 2014(2)   2013(2)
(in millions) (in millions)
Net income attributable to Calpine $ 614   $ 306 $ 736   $ 111
Net income attributable to the noncontrolling interest 5 11
Income tax expense 9 110 5 12
Debt extinguishment costs and other (income) expense, net 344 7 361 83
Interest expense, net of interest income 154   174   486   517  
Income from operations $ 1,126 $ 597 $ 1,599 $ 723
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(3) 152 149 449 441
Major maintenance expense 36 33 189 182
Operating lease expense 9 9 26 26
Mark-to-market (gain) loss on commodity derivative activity (11 ) (43 ) (79 ) (15 )
Impairment losses 123 123
(Gain) on sale of assets (753 ) (753 )
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest(4) (3 ) 6 13
Stock-based compensation expense 8 8 30 28
Loss on dispositions of assets 1 1 5
Acquired contract amortization 4 4 11 11
Other 54   44   2   17  
Total Adjusted EBITDA $ 745   $ 802   $ 1,604   $ 1,431  
Less:
Operating lease payments 9 9 26 26
Major maintenance expense and capital expenditures(5) 67 62 326 303
Cash interest, net(6) 160 173 497 528
Cash taxes 2 1 16 18
Other 1   1   4   5  
Adjusted Free Cash Flow(7) $ 506   $ 556   $ 735   $ 551  
 
Weighted average shares of common stock outstanding (diluted, in thousands) 402,962   438,493   416,056   448,546  
Adjusted Free Cash Flow Per Share (diluted) $ 1.26   $ 1.27   $ 1.77   $ 1.23  
 

_________

(1) Adjusted EBITDA 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. Adjusted EBITDA related to these plants was $54 million for the three months ended September 30, 2013.

(2) Our East segment includes Adjusted EBITDA of $43 million and $75 million for the nine months ended September 30, 2014 and 2013, respectively, related to the six power plants in our East segment that were sold in July 2014.

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

(4) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for each of the three and nine months ended September 30, 2014 and 2013.

(5) 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. Includes $34 million and $185 million in major maintenance expense for the three and nine months ended September 30, 2013, respectively, and $28 million and $118 million in maintenance capital expenditure for the three and nine months ended September 30, 2013, respectively.

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

(7) Excludes a decrease in working capital of $24 million and an increase of $18 million for the three and nine months ended September 30, 2014, respectively, and an increase in working capital of $59 million and $265 million for the three and nine months ended September 30, 2013, respectively. Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance.

In the following table, we have reconciled our Adjusted EBITDA to our Commodity Margin, both of which are non-GAAP measures, for the three and nine months ended September 30, 2014 and 2013. 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.

   
Three Months Ended September 30, Nine Months Ended September 30,
2014   2013 2014   2013
(in millions) (in millions)
Commodity Margin $ 944   $ 985 $ 2,221   $ 1,979
Other revenue 3 3 10 9
Plant operating expense(1) (171 ) (160 ) (539 ) (480 )
Sales, general and administrative expense(2) (33 ) (28 ) (93 ) (87 )
Other operating expenses(3) (12 ) (11 ) (36 ) (32 )
Adjusted EBITDA from unconsolidated investments in power plants 13 15 41 44
Other 1   (2 )   (2 )
Adjusted EBITDA $ 745   $ 802   $ 1,604   $ 1,431  
 

_________

(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

   
Full Year 2014 Range: Low High
(in millions)
GAAP Net Income (1) $ 609 $ 659
Plus:
Debt extinguishment costs 341 341
Impairment losses 123 123
Gain on sale of assets, net (753 ) (753 )
Interest expense, net of interest income 650 650
Depreciation and amortization expense 600 600
Major maintenance expense 230 230
Operating lease expense 35 35
Other(2) 80   80  
Adjusted EBITDA $ 1,915 $ 1,965
Less:
Operating lease payments 35 35
Major maintenance expense and maintenance capital expenditures(3) 405 405
Cash interest, net(4) 650 650
Cash taxes 20 20
Other 5   5  
Adjusted Free Cash Flow $ 800 $ 850
 

_________

(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 $240 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.

Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance

   
Full Year 2015 Range: Low High
(in millions)
GAAP Net Income (1) $ 295 $ 495
Plus:
Interest expense, net of interest income 630 630
Depreciation and amortization expense 630 630
Major maintenance expense 230 230
Operating lease expense 35 35
Other(2) 80   80
Adjusted EBITDA $ 1,900 $ 2,100
Less:
Operating lease payments 35 35
Major maintenance expense and maintenance capital expenditures(3) 395 395
Cash interest, net(4) 630 630
Cash taxes 25 25
Other 5   5
Adjusted Free Cash Flow $ 810 $ 1,010
 

_________

(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 $235 million and maintenance capital expenditures of $160 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,
2014   2013 2014   2013
Total MWh generated (in thousands)(1) 28,449 29,688 74,511 76,025
West 9,634 10,185 25,235 25,751
Texas 11,924 9,924 28,290 25,224
East 6,891 9,579 20,986 25,050
 
Average availability 96.6 % 97.6 % 90.9 % 92.0 %
West 98.6 % 97.9 % 93.1 % 91.9 %
Texas 96.3 % 97.8 % 90.2 % 89.5 %
East 95.1 % 97.3 % 89.8 % 93.9 %
 
Average capacity factor, excluding peakers 57.7 % 55.7 % 47.1 % 49.0 %
West 61.9 % 68.5 % 54.7 % 61.1 %
Texas 58.8 % 57.7 % 49.4 % 49.5 %
East 50.8 % 44.8 % 38.0 % 40.2 %
 
Steam adjusted heat rate (Btu/kWh) 7,402 7,414 7,396 7,402
West 7,325 7,317 7,310 7,335
Texas 7,215 7,226 7,222 7,193
East 7,848 7,713 7,733 7,679
 

________

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

Contacts

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

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