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Calpine Reports Fourth Quarter and Full Year 2015 Results, Reaffirms 2016 Guidance

02/12/2016

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

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

  Three Months Ended December 31,   Year Ended December 31,
2015   2014   % Change 2015   2014   % Change
 
Operating Revenues $ 1,436 $ 1,939 (25.9 )% $ 6,472 $ 8,030 (19.4 )%
Commodity Margin $ 620 $ 538 15.2

 %

$ 2,786 $ 2,759 1.0

 %

Adjusted EBITDA $ 390 $ 345 13.0

 %

$ 1,976 $ 1,949 1.4

 %

Adjusted Free Cash Flow $ 97 $ 95 2.1

 %

$ 842 $ 830 1.4

 %

Per Share (diluted) $ 0.27 $ 0.24 12.5

 %

$ 2.31 $ 2.03 13.8

 %

Net Income (Loss)1 $ (47 ) $ 210 $ 235 $ 946
Per Share (diluted) $ (0.13 ) $ 0.54 $ 0.64 $ 2.31
Net Income (Loss), As Adjusted2 $ 67 $ (50 ) $ 385 $ 309
 

Reaffirming 2016 Full Year Guidance (in millions, except per share amounts):

  2016
 
Adjusted EBITDA $1,800 - 1,950
Adjusted Free Cash Flow $710 - 860
Per Share Estimate (diluted) $2.00 - 2.40
 

Recent Achievements:

  • Power Operations:
    — Generated approximately 115 million MWh3 in 2015
    — Achieved top quartile4 safety metrics: 0.73 total recordable incident rate in 2015
    — Delivered strong fleetwide starting reliability: 98.3%
  • Customer-Oriented Origination Efforts:
    — Entered into new ten-year contract with the Tennessee Valley Authority to provide 615 MW of energy and capacity from our Morgan Energy Center commencing in February 2016
    — Extended contract by ten years beyond 2021 to provide South Texas Electric Cooperative with approximately 500 MW of energy annually
    — Entered into new three-year contract with the San Francisco Public Utilities Commission to provide, on average, approximately 43 MW of energy and renewable energy annually, commencing in May 2016
  • Portfolio and Balance Sheet Management:
    — Completed acquisition of Granite Ridge Energy Center for $500 million5
    — Entered into $550 million First Lien Term Loan due 2023, intended to fund a portion of Granite Ridge acquisition, to repay project and corporate debt and for general corporate purposes
    — Redeemed approximately $120 million of our 7.875% First Lien Notes due 2023 at a price of 103
    — Extended revolver maturity by two years to 2020; increased capacity by $178 million to $1.678 billion into 2018

Calpine Corporation (NYSE: CPN) today reported fourth quarter 2015 Adjusted EBITDA of $390 million, compared to $345 million in the prior year period, and Adjusted Free Cash Flow of $97 million, or $0.27 per diluted share, compared to $95 million, or $0.24 per diluted share, in the prior year period. The increases in Adjusted EBITDA and Adjusted Free Cash Flow were primarily due to higher Commodity Margin driven by higher contribution from hedges and hedging through our retail subsidiary acquired in October 2015, the acquisition of our Fore River Energy Center in November 2014, the commencement of operations at our Garrison Energy Center in June 2015 and higher regulatory capacity revenue in PJM. Net Loss1 for the fourth quarter of 2015 was $47 million, or $0.13 per diluted share, compared to Net Income1 of $210 million, or $0.54 per diluted share, in the prior year period. The decrease in Net Income1 was primarily due to lower unrealized gains on power hedges in the fourth quarter of 2015 compared to the prior year period. Net Income, As Adjusted2, for the fourth quarter of 2015 was $67 million compared to Net Loss, As Adjusted2, of $50 million in the prior year period. The increase in Net Income, As Adjusted2, was largely driven by an income tax benefit in the fourth quarter of 2015 primarily related to a legal entity restructuring and the recognition of a future tax benefit related to a tax credit.

Full year 2015 Adjusted EBITDA was $1,976 million, compared to $1,949 million in the prior year, and Adjusted Free Cash Flow was $842 million, or $2.31 per diluted share, compared to $830 million, or $2.03 per diluted share, in the prior year. The increases in Adjusted EBITDA and Adjusted Free Cash Flow were primarily due to higher Commodity Margin mainly driven by higher contribution from hedges and increased generation. Net Income1 in 2015 was $235 million, or $0.64 per diluted share, compared to $946 million, or $2.31 per diluted share, in the prior year. The decrease in Net Income1 was primarily driven by a gain on the sale of six power plants in July 2014 that did not recur in 2015. Net Income, As Adjusted2, was $385 million in 2015 compared to $309 million in the prior year. The increase in Net Income, As Adjusted2, was largely driven by an income tax benefit in 2015 associated primarily with a legal entity restructuring and a tax credit, as previously discussed, as well as higher Commodity Margin, as previously discussed, partially offset by an increase in plant operating expense related to higher major maintenance expense resulting from our plant outage schedule.

“Calpine has become known for delivering on its financial commitments, and I am pleased to report that 2015 was no exception,” said Thad Hill, Calpine’s President and Chief Executive Officer. “Despite the most volatile commodity markets in recent memory, in 2015 we achieved record Adjusted EBITDA and Adjusted Free Cash Flow Per Share, successfully meeting our guidance for the year. We did this by reinforcing our commitment to our longstanding values of operational excellence, customer focus and financial discipline. I could not be prouder of the Calpine team for its efforts.

“With respect to our capital allocation program, we continue to make progress. Since October, we have balanced our expenditures between funding growth, including the acquisitions of Champion Energy and Granite Ridge Energy Center, and repaying debt, including the redemption of $120 million of our higher-interest notes. Overall, our capital allocation philosophy remains intact and will continue to include a mix of growth, share repurchases and debt reduction, the balance of which will vary over time depending upon the opportunity set. Fortunately, our strong cash flows continue to provide us with capital allocation flexibility as we consider the current environment and the opportunities it may present.

“Power markets are evolving more today than at any point since deregulation, primarily due to sustained low natural gas prices, continued subsidization of renewable generation, a growing focus on resource reliability and the proliferation of environmental regulations. This evolution has weighed upon the public equity markets as investors consider its impacts. Our message in that debate is clear: a modern, flexible and clean fleet like Calpine’s is essential in each of our markets today and will be even more so in the power generation sector of the future. As a team, we are intently focused on capitalizing on the opportunities before us.

“Looking at our 2016 financial guidance, we expect to achieve Adjusted EBITDA of $1.8 - $1.95 billion and Adjusted Free Cash Flow of $2.00 - $2.40 per share. I believe that our efforts in 2016 will further differentiate Calpine from the rest of the sector through the higher generation levels we are able to achieve in low gas price scenarios, the unparalleled quality of our assets which are capable of serving our markets for decades to come and the exercise of financial discipline.”

__________

1 Reported as Net Income (Loss) attributable to Calpine on our Consolidated Statements of Operations.

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

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

4 According to EEI Safety Survey (2014).

5 Excluding working capital adjustments.

SUMMARY OF FINANCIAL PERFORMANCE

Fourth Quarter Results

Adjusted EBITDA for the fourth quarter of 2015 was $390 million compared to $345 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily related to an $82 million increase in Commodity Margin, partially offset by a $34 million increase in plant operating expense6. The increase in plant operating expense was primarily related to costs associated with the wildfire that damaged our Geysers assets in September 2015. The increase in Commodity Margin was primarily due to:

            +   higher contribution from hedges and hedging through our retail subsidiary acquired in October 2015
+ higher regulatory capacity revenue in PJM and
+ the acquisition of our 731 MW Fore River Energy Center in November 2014 and commencement of commercial operations at our 309 MW Garrison Energy Center in June 2015, partially offset by
lower on-peak spark spreads due to milder weather and lower natural gas prices.

Net Loss1 was $47 million for the fourth quarter of 2015, compared to Net Income1 of $210 million in the prior year period. The year-over-year decline in Net Income1 was primarily due to a decrease in unrealized gains on power hedges compared to the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $67 million in the fourth quarter of 2015 compared to a Net Loss, As Adjusted2, of $50 million in the prior year period. The year-over-year improvement in Net Income, As Adjusted2, was primarily driven by an income tax benefit related to a legal entity restructuring that resulted in a partial release of our valuation allowance associated with our net operating losses, as well as the recognition of a future tax benefit related to a tax credit associated with our capital expenditures.

Adjusted Free Cash Flow was $97 million in the fourth quarter of 2015 compared to $95 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to an increase in Adjusted EBITDA, as previously discussed, partially offset by an increase in major maintenance expense resulting from our plant outage schedule.

Full Year Results

Adjusted EBITDA in 2015 was $1,976 million compared to $1,949 million in the prior year. The year-over-year increase in Adjusted EBITDA was primarily related to a $27 million increase in Commodity Margin. The increase in Commodity Margin was primarily due to:

            +   higher contribution from hedges in our West and East regions and hedging through our retail subsidiary, which 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 from our power plants in Texas and the East resulting from lower natural gas prices that drove lower systemwide coal-fired generation from our competitors, partially offset by
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 completion of our Deer Park and Channel Energy Center expansions in June 2014 and the commencement of commercial operations at our Garrison Energy Center in June 2015, and

lower regulatory capacity revenue in PJM during the first five months of 2015, partially offset by higher regulatory capacity revenue in PJM during the remaining seven months of 2015.

Net Income1 was $235 million in 2015, compared to $946 million in the prior year. The year-over-year decrease in Net Income1 was primarily due to a gain on the previously mentioned sale of the six power plants in our East region in July 2014 that did not recur in 2015. As detailed in Table 1, Net Income, As Adjusted2, was $385 million in 2015, compared to $309 million in the prior year. The year-over-year increase was driven largely by:

            +   an income tax benefit associated primarily with a legal entity restructuring and the recognition of a future tax benefit related to a tax credit, as previously discussed, and
+ higher Commodity Margin, as previously discussed, partially offset by
higher plant operating expense driven by higher major maintenance expense associated with our plant outage schedule.

Adjusted Free Cash Flow was $842 million in 2015, compared to $830 million in the prior year. Adjusted Free Cash Flow increased during the period primarily due to an increase in Adjusted EBITDA and a decrease in interest expense, partially offset by higher major maintenance expense, as previously discussed.

__________

6 Increase in plant operating expense excludes changes in major maintenance expense, stock-based compensation expense, non-cash loss on disposition of assets and other costs. See the table titled "Consolidated Adjusted EBITDA Reconciliation" for the actual amounts of these items for the three months ended December 31, 2015 and 2014.

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

   
Three Months Ended December 31, Year Ended December 31,
2015   2014 2015   2014
Net income (loss) attributable to Calpine $ (47 ) $ 210 $ 235 $ 946
Impairment losses(1) 123
(Gain) on sale of assets, net(1) (753 )
Debt modification and extinguishment costs(1) 8 5 40 346
Mark-to-market (gain) loss on derivatives(1)(2) 106   (265 ) 110   (353 )
Net Income (Loss), As Adjusted(3) $ 67   $ (50 ) $ 385   $ 309  

__________

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

(2) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market (gain) loss also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

(3) Non-GAAP financial measure, see “Regulation G Reconciliations” for further discussion of Net Income (Loss), As Adjusted.

REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin by Segment (in millions)

  Three Months Ended December 31,   Year Ended December 31,
2015   2014   Variance 2015   2014   Variance
West $ 263 $ 259 $ 4 $ 1,106 $ 1,050 $ 56
Texas 153 116 37 736 760 (24 )
East 204   163   41   944   949   (5 )
Total $ 620   $ 538   $ 82   $ 2,786   $ 2,759   $ 27  

West Region

Fourth Quarter: Commodity Margin in our West segment increased by $4 million in the fourth quarter of 2015 compared to the prior year period. Primary drivers were:

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

Full Year: Commodity Margin in our West segment increased by $56 million in 2015, compared to the prior year. Primary drivers were:

            +   higher contribution from hedges
+ higher generation from our power plants resulting from a decrease in hydroelectric generation in the Pacific Northwest and
+ higher contractual renewable energy credit revenues 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
a wildfire in northern California in September 2015 that negatively impacted our Geysers assets and
the expiration of the operating lease related to the Greenleaf power plants in June 2015.

Texas Region

Fourth Quarter: Commodity Margin in our Texas segment increased by $37 million in the fourth quarter of 2015 compared to the prior year period. Primary drivers were:

            +   higher contribution from hedges and hedging through our retail subsidiary and
+ higher generation from our power plants resulting from higher off-peak spark spreads and lower natural gas prices that drove lower systemwide coal-fired generation from our competitors, partially offset by
lower on-peak spark spreads resulting from lower natural gas prices and milder weather.

Full Year: Commodity Margin in our Texas segment decreased by $24 million in 2015, compared to the prior year. Primary drivers were:

              lower contribution from summer hedges partially offset by the positive impact from hedging through our retail subsidiary beginning in the fourth quarter of 2015 and
lower on-peak spark spreads, despite higher market heat rates, resulting from lower natural gas prices, partially offset by
+ higher generation from our power plants resulting from higher off-peak spark spreads and lower natural gas prices that drove lower systemwide coal-fired generation from our competitors and
+ a full year of operation in 2015 of our 1,000 MW Guadalupe Energy Center (which was acquired in February 2014) and our Deer Park and Channel Energy Center expansions (which were completed in June 2014).

East Region

Fourth Quarter: Commodity Margin in our East segment increased by $41 million in the fourth quarter of 2015 compared to the prior year period. Primary drivers were:

            +   higher contribution from hedges
+

higher regulatory capacity revenue in PJM and

+ a full period of operation in the fourth quarter of 2015 of our 731 MW Fore River Energy Center, which was acquired in November 2014, and the commencement of commercial operations of our 309 MW Garrison Energy Center in June 2015, partially offset by

a decrease in generation from our Mid-Atlantic power plants, partially offset by an increase in generation from our power plants in New England and the Southeast.

Full Year: Commodity Margin in our East segment increased by $76 million in 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
+ a full year of operation of our 731 MW Fore River Energy Center, which was acquired in November 2014, and the commencement of commercial operations at our 309 MW Garrison Energy Center in June 2015

+

higher generation from our power plants resulting from lower natural gas prices that drove lower systemwide coal-fired generation from our competitors and
+ a new contract at 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 revenue in PJM during the first five months of 2015, partially offset by higher regulatory capacity revenue in PJM during the remaining seven months of 2015.

LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES

Table 3: Liquidity (in millions)

  December 31, 2015   December 31, 2014
Cash and cash equivalents, corporate(1) $ 850 $ 460
Cash and cash equivalents, non-corporate 56   257
Total cash and cash equivalents 906 717
Restricted cash 228 244
Corporate Revolving Facility availability(2) 1,184 1,277
CDHI letter of credit facility availability 59   86
Total current liquidity availability(3) $ 2,377   $ 2,324

____________

(1) Includes $35 million and $47 million of margin deposits posted with us by our counterparties at December 31, 2015 and 2014, respectively.

(2) On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 2020 and increasing the capacity by an additional $178 million to $1.678 billion through June 2018, reverting back to $1.520 billion through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 2020.

(3) Subsequent to year-end, we used $500 million of liquidity to complete the acquisition of Granite Ridge Energy Center, excluding working capital adjustments.

Liquidity was approximately $2.4 billion as of December 31, 2015. Cash and cash equivalents increased during 2015 primarily due to $842 million of Adjusted Free Cash Flow earned in 2015, as well as the receipt of proceeds related to our 2023 First Lien Term Loan and 2024 Senior Unsecured Notes. These inflows were partially offset by repurchases of our common stock, ongoing investments in announced growth projects, the acquisition of Champion Energy and the repurchase and redemption of a portion of our 2023 First Lien Notes.

Table 4: Cash Flow Activities (in millions)

  Year Ended December 31,
2015   2014
Beginning cash and cash equivalents $ 717   $ 941  
Net cash provided by (used in):
Operating activities 863 854
Investing activities (841 ) (84 )
Financing activities 167   (994 )
Net increase (decrease) in cash and cash equivalents 189   (224 )
Ending cash and cash equivalents $ 906   $ 717  
 

Cash provided by operating activities was $863 million in 2015 compared to $854 million in the prior year. The increase in cash provided by operating activities was primarily due to an increase in income from operations, adjusted for non-cash items, and a reduction in debt modification and extinguishment payments, partially offset by an increase in working capital largely associated with changes in margining requirements.

Cash used in investing activities was $841 million during 2015, compared to $84 million in the prior year. In 2014, we received approximately $1.57 billion of proceeds from the sale of six power plants in our East region, partially offset by approximately $1.2 billion used to purchase our Fore River and Guadalupe Energy Centers. Corresponding 2015 activity included the purchase of Champion Energy for approximately $240 million plus working capital adjustments and an increase in capital expenditures for construction projects and outages.

Cash provided by financing activities was $167 million during 2015 and was primarily related to proceeds from the issuances of our 2024 Senior Unsecured Notes, 2022 First Lien Term Loan and 2023 First Lien Term Loan. These inflows were substantially offset by payments associated with the execution of our share repurchase program, the repayment of our 2018 First Lien Term Loan, and the repurchase and redemption of a portion of our 2023 First Lien Notes.

CAPITAL ALLOCATION

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.7

In 2015, we 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.

Acquisition of Granite Ridge Energy Center

In February 2016, we completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), for approximately $500 million, excluding working capital adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant meaningfully increases our capacity in the constrained New England market. The power plant features two combustion turbines, two heat recovery steam generators and one steam turbine. We funded the acquisition with a combination of cash on hand and financing.

Acquisition of Champion Energy

In October 2015, we acquired Champion Energy for approximately $240 million, excluding working capital adjustments. The addition of this well-established retail sales organization is consistent with our stated goal of getting closer to our end-use customers and provides us a valuable sales channel for directly reaching a much greater portion of the load we seek to serve.

2023 First Lien Notes

In December 2015, we used cash on hand to redeem 10% of the original aggregate principal amount of our 7.875% First Lien Notes due 2023, plus accrued and unpaid interest. The remaining principal on these notes was $573 million as of December 31, 2015.

2023 First Lien Term Loan

In December 2015, we entered into a $550 million First Lien Term Loan due 2023 and utilized $325 million of the proceeds received, together with cash on hand, to purchase Granite Ridge Energy Center. We intend to use the remaining proceeds to repay project and corporate debt and for general corporate purposes.

2022 First Lien Term Loan

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

2024 Senior Unsecured Notes

In February 2015, we issued $650 million of 5.5% Senior Unsecured Notes due 2024 to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase approximately $147 million of our 7.785% First Lien Notes due 2023 and for general corporate purposes.

Corporate Revolver Extension and Expansion

On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 27, 2020, and increasing the capacity by an additional $178 million to $1.678 billion through June 27, 2018, reverting back to $1.520 billion through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 27, 2020.

Project Debt

In November 2015, we refinanced and upsized our Steamboat project debt, which lowered the interest rate and extended the maturity by two years to November 2019.

In December 2015, we entered into an agreement with one of the two lessors of our Pasadena Power Plant to purchase their 50% interest, which will result in a reduction of our project debt of approximately $50 million. The transaction is expected to close during the second quarter of 2016.

___________

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

Growth and Portfolio Management

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 with dual-fuel capability. The power plant features one combustion turbine, one heat recovery steam generator and one steam turbine. We are in the early stages of development of a second phase of the Garrison Energy Center that will add approximately 430 MW of dual-fuel, combined-cycle capacity. PJM has completed its feasibility study of the project and the system impact study is underway.

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 68 MW of planned capacity at the York 2 Energy Center. This incremental 68 MW of planned capacity cleared the 2018/19 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 fourth 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.

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 by 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.

All Segments:

Turbine Modernization: We continue to move forward with our turbine modernization program. Through December 31, 2015, we have completed the upgrade of 13 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 East Region power plants.

OPERATIONS UPDATE

2015 Power Operations Achievements

  • Safety Performance:
    — Maintained top quartile8 safety metrics: 0.73 total recordable incident rate
  • Availability Performance:
    — Achieved low fleetwide forced outage factor: 2.3%
    — Delivered exceptional fleetwide starting reliability: 98.3%
  • Power Generation:
    — Seven gas-fired plants with full-year capacity factors greater than 70%: Channel, Hermiston, Morgan, Pasadena, Pastoria, Pine Bluff and Stony Brook
    Texas Region: Highest full year generation volume on record
    King City Cogeneration Plant: 100% starting reliability and 0% forced outage factor in 2015

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 was subsequently 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. Further, once repairs are completed, we expect generation capacity at our Geysers assets to be restored to pre-fire levels.

    Our 2015 financial results reflect an impact of approximately $36 million associated with the wildfire, including approximately $20 million in net revenue losses and approximately $16 million of plant operating expense related to property damage. We expect economic impact in 2016, if any, to be minimal.

2015 Commercial Operations Achievements:

  • Champion Energy: In October 2015, we acquired retail electric provider Champion Energy, consistent with our stated goal of getting closer to our end-use customers. In 2015, Champion Energy served approximately 22 million MWh of customer load consisting of approximately 2.1 million annualized residential customer equivalents at December 31, 2015, concentrated in Texas, the Northeast and Mid-Atlantic where Calpine has a substantial power generation presence.
  • Customer Relationships: During 2015, we entered into the following:

    West:
    — A PPA with Marin Clean Energy to provide up to 65 MW of power from our Delta Energy Center and other northern California power plants commencing in April 2015 and extending through December 2017
    — A ten-year PPA with Southern California Edison for 50 MW of capacity and renewable energy from our Geysers assets commencing in January 2018; the PPA remains subject to approval by the California Public Utilities Commission (CPUC)
    — Our ten-year PPA with Southern California Edison for 225 MW of capacity and renewable energy from our Geysers assets commencing in June 2017 was approved by the CPUC
    — A one-year resource adequacy contract with Southern California Edison for 238 MW from our Pastoria Energy Center commencing in January 2018
    — A three-year PPA with the San Francisco Public Utilities Commission to provide, on average, approximately 43 MW of energy and renewable energy annually, commencing in May 2016

    Texas:
    — A three-year PPA with Brazos Electric Power Cooperative to provide 300 MW of energy from our Texas power plant fleet commencing in January 2016
    — A three-year PPA with Pedernales Electric Cooperative to provide approximately 140 MW of energy from our Texas power plant fleet commencing in January 2017
    — A two-year PPA with Guadalupe Valley Electric Cooperative to provide approximately 270 MW of energy from our Texas power plant fleet commencing in June 2017. The execution of this PPA will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center
    — We extended our existing PPA with the South Texas Electric Cooperative to supply the Magic Valley Electric Cooperative’s full load requirements for ten years beyond 2021. Magic Valley Electric Cooperative’s peak summer load in 2015 was 490 MW

    East:
    — A 20-year PPA with Xcel Energy to provide up to 345 MW of capacity and energy from our Mankato Power Plant expansion when commercial operations commence and transmission-related upgrades have been completed
    — A ten-year PPA with Tennessee Valley Authority for 615 MW of energy and capacity from our Morgan Energy Center commencing in February 2016

___________

8 According to EEI Safety Survey (2014).

 

2016 FINANCIAL OUTLOOK

 
(in millions, except per share amounts) Full Year 2016
Adjusted EBITDA $ 1,800 - 1,950
Less:
Operating lease payments 25
Major maintenance expense and maintenance capital expenditures(1) 410
Cash interest, net(2) 635
Cash taxes 15
Other 5  
Adjusted Free Cash Flow $ 710 - 860
Per Share Estimate (diluted) $ 2.00 - 2.40
 

Debt amortization and repayment(3)

$

(435

)
Growth capital expenditures (net of debt funding) $ (285 )
Acquisition of Granite Ridge Energy Center(4) $ (500 )

(1) Includes projected 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 fees from consolidated and unconsolidated investments, net of capitalized interest and interest income.

(3) Includes $210 million of recurring amortization, as well as $225 million of proceeds from our 2023 First Lien Term Loan that we intend to use to repay project and corporate debt.

(4) Excluding working capital adjustments.

As detailed above, today we are reaffirming our 2016 guidance. We expect 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 growth projects throughout 2016, primarily the construction of York 2 Energy Center.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results for the fourth quarter and full year 2015 on Friday, February 12, 2016, 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 41578892. 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 41578892. Presentation materials to accompany the conference call will be available on our website on February 12, 2016.

ABOUT CALPINE

Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources. Our fleet of 84 power plants in operation or under construction represents more than 27,000 megawatts of generation capacity. Through wholesale power operations and our retail business, Champion Energy, we serve customers in 20 states and Canada. We specialize in developing, constructing, owning and operating natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our clean, efficient, modern and flexible fleet is uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. 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 Annual Report on Form 10-K for the year ended December 31, 2015, has been filed with the Securities and Exchange Commission (SEC) and is available 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 renewable sources of power and 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 revenue 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 or fuel oil and the 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 Annual Report on Form 10-K for the year ended December 31, 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 STATEMENTS OF OPERATIONS

     
(Unaudited)
Three Months Ended December 31, Year Ended December 31,
2015   2014 2015 2014
(in millions, except share and per share amounts)
Operating revenues:
Commodity revenue $ 1,456 $ 1,595 $ 6,389 $ 7,595
Mark-to-market gain (loss) (24 ) 338 65 419
Other revenue 4   6   18   16  
Operating revenues 1,436   1,939   6,472   8,030  
Operating expenses:
Fuel and purchased energy expense:
Commodity expense 835 1,058 3,589 4,815
Mark-to-market loss 83   75   178   77  
Fuel and purchased energy expense 918   1,133   3,767   4,892  
Plant operating expense 286 215 1,018 969
Depreciation and amortization expense 154 150 638 603
Sales, general and other administrative expense 38 36 138 144
Other operating expenses 24   22   80   88  
Total operating expenses 1,420   1,556   5,641   6,696  
Impairment losses 123
(Gain) on sale of assets, net (753 )
(Income) from unconsolidated investments in power plants (6 ) (7 ) (24 ) (25 )
Income from operations 22 390 855 1,989
Interest expense 157 154 628 645
Interest (income) (1 ) (1 ) (4 ) (6 )
Debt modification and extinguishment costs 8 5 40 346
Other (income) expense, net 10   1   18   21  
Income (loss) before income taxes (152 ) 231 173 983
Income tax expense (benefit) (108 ) 17   (76 ) 22  
Net income (loss) (44 ) 214 249 961
Net income attributable to the noncontrolling interest (3 ) (4 ) (14 ) (15 )
Net income (loss) attributable to Calpine $ (47 ) $ 210   $ 235   $ 946  
 
Basic earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 353,072   384,964   362,033   404,837  
Net income (loss) per common share attributable to Calpine — basic $ (0.13 ) $ 0.55   $ 0.65   $ 2.34  
 
Diluted earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 353,072   389,425   364,886   409,360  
Net income (loss) per common share attributable to Calpine — diluted $ (0.13 ) $ 0.54   $ 0.64   $ 2.31  
 

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 2015 and 2014

(in millions, except share and per share amounts)

   
2015 2014
ASSETS
Current assets:
Cash and cash equivalents $ 906 $ 717
Accounts receivable, net of allowance of $2 and $4 644 648
Inventories 475 447
Margin deposits and other prepaid expense 137 148
Restricted cash, current 216 195
Derivative assets, current 1,698 2,058
Other current assets 19   7  
Total current assets 4,095 4,220
Property, plant and equipment, net 13,012 13,190
Restricted cash, net of current portion 12 49
Investments in power plants 79 95
Long-term derivative assets 313 439
Long-term assets held for sale 130
Other assets 1,192   385  
Total assets $ 18,833   $ 18,378  
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable $ 552 $ 580
Accrued interest payable 129 165
Debt, current portion 221 199
Derivative liabilities, current 1,734 1,782
Other current liabilities 412   473  
Total current liabilities 3,048 3,199
Debt, net of current portion 11,868 11,083
Long-term derivative liabilities 473 444
Other long-term liabilities 277   221  
Total liabilities 15,666 14,947
 
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding at December 31, 2015 and 2014
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 356,755,747 shares issued and 356,662,004 shares outstanding at December 31, 2015, and 502,287,022 shares issued and 381,921,264 shares outstanding at December 31, 2014 1
Treasury stock, at cost, 93,743 and 120,365,758 shares, respectively (1 ) (2,345 )
Additional paid-in capital 9,594 12,440
Accumulated deficit (6,305 ) (6,540 )
Accumulated other comprehensive loss (179 ) (178 )
Total Calpine stockholders’ equity 3,109 3,378
Noncontrolling interest 58   53  
Total stockholders’ equity 3,167   3,431  
Total liabilities and stockholders’ equity $ 18,833   $ 18,378  
 

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2015 and 2014

(in millions)

   
2015 2014
Cash flows from operating activities:
Net income $ 249 $ 961
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization(1) 757 649
Debt extinguishment costs 6 36
Deferred income taxes (87 ) 5
Impairment losses 123
(Gain) on sale of assets, net (753 )
Mark-to-market activity, net 110 (353 )
(Income) from unconsolidated investments in power plants (24 ) (25 )
Return on unconsolidated investments in power plants 25 13
Stock-based compensation expense 26 36
Other 7 (4 )
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable 169 (87 )
Derivative instruments, net (183 ) (63 )
Other assets (120 ) 151
Accounts payable and accrued expenses (221 ) 185
Other liabilities 149   (20 )
Net cash provided by operating activities 863   854  
Cash flows from investing activities:
Purchases of property, plant and equipment (565 ) (492 )
Proceeds from sale of power plants, interests and other 1,573
Purchase of Fore River and Guadalupe Energy Centers (1 ) (1,197 )
Purchase of Champion Energy, net of cash acquired (296 )
Decrease in restricted cash 18 28
Other 3   4  
Net cash used in investing activities

 

(841 )

 

(84 )
Cash flows from financing activities:
Borrowings under CCFC Term Loans and First Lien Term Loans

 

2,137

 

420
Repayments of CCFC Term Loans and First Lien Term Loans (1,635 ) (45 )
Borrowings under Senior Unsecured Notes 650 2,800
Repayments of First Lien Notes (267 ) (2,920 )
Borrowings from project financing, notes payable and other 79 79
Repayments of project financing, notes payable and other (232 ) (178 )
Distribution to noncontrolling interest holder (10 ) (15 )
Financing costs (34 ) (56 )
Stock repurchases (529 ) (1,100 )
Proceeds from exercises of stock options 8 20
Other   1  
Net cash provided by (used in) financing activities 167   (994 )
Net increase (decrease) in cash and cash equivalents 189 (224 )
Cash and cash equivalents, beginning of period 717   941  
Cash and cash equivalents, end of period $ 906   $ 717  
 
Cash paid during the period for:
Interest, net of amounts capitalized $ 620 $ 610
Income taxes $ 21 $ 23
 
Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable $ 13 $ 3

Additions to property, plant and equipment through capital leases

$ 9 $ 19
Retirement of shares held in treasury $ 2,885 $

__________

(1) Includes depreciation and amortization included in commodity revenue, commodity expense and interest expense on our Consolidated Statements of Operations.

REGULATION G RECONCILIATIONS

In addition to disclosing financial results in accordance with U.S. GAAP, the accompanying fourth 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 December 31, 2015 and 2014 (in millions):

  Three Months Ended December 31, 2015
  Consolidation  
And
West Texas East Elimination Total
Commodity Margin $ 263 $ 153 $ 204 $ $ 620
Add: Mark-to-market commodity activity, net and other(1) (13 ) (73 ) (8 ) (8 ) (102 )
Less:
Plant operating expense 103 105 86 (8 ) 286
Depreciation and amortization expense 57 47 49 1 154
Sales, general and other administrative expense 12 16 11 (1 ) 38
Other operating expenses 9 3 12 24
(Income) from unconsolidated investments in power plants     (6 )   (6 )
Income (loss) from operations $ 69   $ (91 ) $ 44   $   $ 22  
 
Three Months Ended December 31, 2014
Consolidation
And
West Texas East Elimination Total
Commodity Margin $ 259 $ 116 $ 163 $ $ 538
Add: Mark-to-market commodity activity, net and other(1) 129 68 79 (8 ) 268
Less:
Plant operating expense 94 63 65 (7 ) 215
Depreciation and amortization expense 62 50 39 (1 ) 150
Sales, general and other administrative expense 13 16 7 36
Other operating expenses 11 1 10 22
(Income) from unconsolidated investments in power plants     (7 )   (7 )
Income from operations $ 208   $ 54   $ 128   $   $ 390  
 

The following tables reconcile our Commodity Margin to its U.S. GAAP results for the years ended December 31, 2015 and 2014 (in millions):

  Year Ended December 31, 2015
  Consolidation  
And
West Texas East Elimination Total
Commodity Margin $ 1,106 $ 736 $ 944 $ $ 2,786
Add: Mark-to-market commodity activity, net and other(3) 160 (120 ) (92 ) (29 ) (81 )
Less:
Plant operating expense 416 338 292 (28 ) 1,018
Depreciation and amortization expense 250 204 184 638
Sales, general and other administrative expense 35 63 40 138
Other operating expenses 37 9 36 (2 ) 80
(Income) from unconsolidated investments in power plants     (24 )   (24 )
Income from operations $ 528   $ 2   $ 324   $ 1   $ 855  
 
Year Ended December 31, 2014
Consolidation
And
West Texas East Elimination Total
Commodity Margin(2) $ 1,050 $ 760 $ 949 $ $ 2,759
Add: Mark-to-market commodity activity, net and other(3) 220 142 48 (31 ) 379
Less:
Plant operating expense 385 313 302 (31 ) 969
Depreciation and amortization expense 245 191 168 (1 ) 603
Sales, general and other administrative expense 41 64 39 144
Other operating expenses 50 5 32 1 88
Impairment losses 123 123
(Gain) on sale of assets, net (753 ) (753 )
(Income) from unconsolidated investments in power plants     (25 )   (25 )
Income from operations $ 549   $ 329   $ 1,111   $   $ 1,989  

_________

(1) Includes $(1) million and $2 million of lease levelization and $9 million and $3 million of amortization expense for the three months ended December 31, 2015 and 2014, respectively.

(2) Our East segment includes Commodity Margin of $81 million for the year ended December 31, 2014, related to the six power plants in our East segment that were sold in July 2014.

(3) Includes $(2) million and $(5) million of lease levelization and $20 million and $14 million of amortization expense for the years ended December 31, 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 months and years ended December 31, 2015 and 2014, as reported under U.S. GAAP (in millions):

  Three Months Ended December 31,   Year Ended December 31,
2015   2014(6) 2015   2014(6)
Net income (loss) attributable to Calpine $ (47 ) $ 210 $ 235 $ 946
Net income attributable to the noncontrolling interest 3 4 14 15
Income tax expense (benefit) (108 ) 17 (76 ) 22
Debt modification and extinguishment costs and other (income) expense, net 18 6 58 367
Interest expense, net of interest income 156   153   624   639  
Income from operations $ 22 $ 390 $ 855 $ 1,989
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1) 152 149 632 598
Major maintenance expense 73 45 268 234
Operating lease expense 7 8 30 34
Mark-to-market (gain) loss on commodity derivative activity 107 (263 ) 113 (342 )
Impairment losses 123
(Gain) on sale of assets (753 )
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest(2) 4 (1 ) 10 5
Stock-based compensation expense 7 6 26 36
Loss on dispositions of assets 8 16 1
Contract amortization 9 3 20 14
Other 1   8   6   10  
Total Adjusted EBITDA $ 390   $ 345   $ 1,976   $ 1,949  
Less:
Operating lease payments 7 8 30 34
Major maintenance expense and capital expenditures(3) 131 84 461 410
Cash interest, net(4) 158 155 626 652
Cash taxes (3 ) 2 15 18
Other   1   2   5  
Adjusted Free Cash Flow(5) $ 97   $ 95   $ 842   $ 830  
 
Weighted average shares of common stock outstanding (diluted, in thousands) 353,072   389,425   364,886   409,360  
Adjusted Free Cash Flow Per Share (diluted) $ 0.27   $ 0.24   $ 2.31   $ 2.03  

_________

(1) Depreciation and amortization expense in the income from operations calculation on our Consolidated 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 months and years ended December 31, 2015 and 2014.

(3) Includes $74 million and $272 million in major maintenance expense for the three months and year ended December 31, 2015, respectively, and $57 million and $189 million in maintenance capital expenditures for the three months and year ended December 31, 2015, respectively. Includes $47 million and $242 million in major maintenance expense for the three months and year ended December 31, 2014, respectively, and $37 million and $168 million in maintenance capital expenditures for the three months and year ended December 31, 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 $115 million and an increase of $129 million for the three months and year ended December 31, 2015, respectively, and a decrease in working capital of $136 million and $118 million for the three months and year ended December 31, 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 months and year ended December 31, 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 months and years ended December 31, 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 December 31,     Year Ended December 31,
2015   2014 2015   2014
Commodity Margin $ 620 $ 538 $ 2,786 $ 2,759
Other revenue 5 5 18 15
Plant operating expense(1) (200 ) (166 ) (710 ) (705 )
Sales, general and administrative expense(2) (35 ) (33 ) (128 ) (126 )
Other operating expenses(3) (14 ) (11 ) (47 ) (47 )
Adjusted EBITDA from unconsolidated investments in power plants 15 12 58 53
Other (1 )   (1 )  
Adjusted EBITDA $ 390   $ 345   $ 1,976   $ 1,949  

_________

(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 2016 Range: Low High
GAAP Net Income (1) $ 165 $ 315
Plus:
Interest expense, net of interest income 640 640
Depreciation and amortization expense 610 610
Major maintenance expense 265 265
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 December 31,     Year Ended December 31,
2015   2014 2015   2014
Total MWh generated (in thousands)(1) 27,046 26,106 112,150 100,617
West 9,036 8,960 34,836 34,195
Texas 11,559 10,388 47,873 38,678
East 6,451 6,758 29,441 27,744
 
Average availability 84.6 % 90.2 % 89.2 % 90.7 %
West 88.2 % 92.4 % 89.2 % 92.9 %
Texas 84.9 % 91.4 % 89.4 % 90.5 %
East 81.5 % 86.9 % 89.0 % 89.2 %
 
Average capacity factor, excluding peakers 53.4 % 52.3 % 55.6 % 48.4 %
West 59.0 % 57.6 % 56.8 % 55.4 %
Texas 57.0 % 51.2 % 59.5 % 49.9 %
East 42.7 % 47.8 % 48.8 % 40.0 %
 
Steam adjusted heat rate (Btu/kWh) 7,293 7,348 7,306 7,384
West 7,313 7,324 7,320 7,314
Texas 7,071 7,153 7,089 7,203
East 7,673 7,687 7,663 7,721

________

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

Source: Calpine Corporation

Calpine Corporation

Media Relations:

Brett Kerr, 713-830-8809

brett.kerr@calpine.com

or

Investor Relations:

Bryan Kimzey, 713-830-8777

bryan.kimzey@calpine.com