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Calpine Reports Fourth Quarter and Full Year 2014 Results, Reaffirms 2015 Guidance

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Calpine Corporation (NYSE:CPN) :

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

Three Months Ended December 31, Year Ended December 31,
2014 2013 % Change 2014 2013 % Change
Operating Revenues $ 1,939 $ 1,438 34.8 % $ 8,030 $ 6,301 27.4 %
Commodity Margin $ 538 $ 589 (8.7 )% $ 2,759 $ 2,568 7.4 %
Adjusted EBITDA $ 345 $ 399 (13.5 )% $ 1,949 $ 1,830 6.5 %
Adjusted Free Cash Flow $ 95 $ 126 (24.6 )% $ 830 $ 677 22.6 %
Per Share (diluted) $ 0.24 $ 0.29 (17.2 )% $ 2.03 $ 1.52 33.6 %
Net Income (Loss)1 $ 210 $ (97 ) $ 946 $ 14
Per Share (diluted) $ 0.54 $ (0.23 ) $ 2.31 $ 0.03
Net Income (Loss), As Adjusted2 $ (50 ) $ 21 $ 309 $ 186

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

2015
Adjusted EBITDA $1,900 – 2,100
Adjusted Free Cash Flow $810 – 1,010
Per Share Estimate (diluted) $2.10 – 2.60

Recent Achievements:

  • Power and Commercial Operations:
    - Generated approximately 103 million MWh3 of electricity in 2014
    - Achieved goal of forced outage factor below 2% for third consecutive year
    - Delivered impressive safety performance, including a record-low total recordable incident rate: 0.64
  • Portfolio Management:
    - Completed acquisition of Fore River Energy Center for approximately $530 million, or $655/kW
    - Entered into agreement to sell our Osprey Energy Center for approximately $166 million, excluding adjustments, upon conclusion of the plant’s existing PPA in January 2017, subject to federal and state approval
    - Advanced development efforts for our Mankato Power Plant, where our customer has received Minnesota regulatory approval to execute a PPA with us that will facilitate expansion of the plant by 345 MW
  • Capital Allocation Progress:
    - Since 2011, completed $2.4 billion of share repurchases, or approximately 25% of shares outstanding4
    - Completed approximately $277 million of share repurchases since last earnings release, bringing total repurchases to approximately $1.1 billion in 2014 and $125 million year-to-date in 2015
    - Redeemed approximately $120 million of our 7.875% First Lien Notes due 2023 at a price of 103
    - Issued $650 million of 5.5% Senior Unsecured Notes due 2024, funding primarily Fore River acquisition and repurchases of higher interest rate debt

Calpine Corporation (NYSE:CPN) today reported fourth quarter 2014 Adjusted EBITDA of $345 million, compared to $399 million in the prior year period, and Adjusted Free Cash Flow of $95 million, or $0.24 per diluted share, compared to $126 million, or $0.29 per diluted share, in the prior year period. Net Income1 for the fourth quarter of 2014 was $210 million, or $0.54 per diluted share, compared to a Net Loss1 of $97 million, or $0.23 per diluted share, in the prior year period. The increase in Net Income1 was primarily due to unrealized gains on power hedges driven by a decrease in forward power prices resulting from a decline in natural gas prices in December 2014. Net Loss, As Adjusted2, for the fourth quarter of 2014 was $50 million compared to Net Income, As Adjusted2, of $21 million in the prior year period. The decreases in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted2, were primarily due to lower Commodity Margin driven largely by the sale of six power plants in July 2014 and lower regulatory capacity revenue in PJM.

Full year 2014 Adjusted EBITDA was $1,949 million, compared to $1,830 million in the prior year period, and Adjusted Free Cash Flow was $830 million, or $2.03 per diluted share, compared to $677 million, or $1.52 per diluted share, in the prior year period. Net Income1 in 2014 was $946 million, or $2.31 per diluted share, compared to $14 million, or $0.03 per diluted share, in the prior year period. The increase in Net Income1 was primarily due to a gain on the previously mentioned asset sale, as well as higher Commodity Margin. Net Income, As Adjusted2, in 2014 was $309 million compared to $186 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 net portfolio changes, stronger market conditions during the first quarter of 2014 driven by colder than normal weather and our ability to capture the value of our dual-fueled plants in the East during extreme commodity pricing environments.

“2014 was a remarkable year for Calpine, with accomplishments on many fronts,” said Thad Hill, Calpine’s President and Chief Executive Officer. “We successfully delivered on our financial commitments, driving Adjusted EBITDA, Adjusted Free Cash Flow and Adjusted Free Cash Flow Per Share to record levels. Among our more notable operational accomplishments, we provided critical, reliable power during the Polar Vortex; we effectively managed volatile commodity markets; and we originated more than 2,000 MW of new contracts with our customers, further adding to the value of our fleet.

“Equally important, we enhanced shareholder value through the deployment of more than $3 billion of capital, representing approximately one-third of our market capitalization. We realigned our portfolio with our strategic objectives by monetizing the Southeast, acquiring plants in Texas and New England, and completing plant expansions along the Houston Ship Channel. Meanwhile, we further optimized our capital structure with the introduction of unsecured debt and returned $1.1 billion of capital to our shareholders through share repurchases. Since commencing our share repurchase program in 2011, we have now repurchased approximately $2.4 billion, or 25% of our shares outstanding.

“In 2015, we are continuing to build on this progress, having today announced the future sale of our Osprey Energy Center, which will effectively capture approximately $225 million of value (including the PPA) from an otherwise underperforming merchant asset in a non-core market. Additionally, we have made significant regulatory progress toward the expansion of our Mankato Power Plant, where our customer has been authorized by the Minnesota PUC to execute a 20-year contract with us. Meanwhile, we continue to demonstrate our commitment to returning capital to shareholders through opportunistic share repurchases. I am encouraged by our achievements thus far this year and am reaffirming our 2015 financial guidance.

“Our clean, modern, reliable and flexible fleet is poised to benefit from increasingly stringent environmental regulations, market focus on pay-for-performance initiatives and the secular shift away from traditional baseload generation in favor of dispatchable resources, particularly given low natural gas prices.”

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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 Based upon 490.6 million shares outstanding as of 6/30/11, immediately prior to announcement of repurchase program.

SUMMARY OF FINANCIAL PERFORMANCE

Fourth Quarter Results

Adjusted EBITDA for the fourth quarter of 2014 was $345 million compared to $399 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to a $51 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, partially offset by
+ the acquisition of Guadalupe Energy Center in February 2014, as well as the completion of the expansions of our Deer Park and Channel energy centers in June 2014 and
+ higher contribution from hedges in our West and Texas segments

Net Income1 was $210 million for the fourth quarter of 2014, compared to a Net Loss1 of $97 million in the prior year period. The year-over-year improvement in Net Income1 was primarily due to unrealized gains on power hedges driven by a decrease in forward power prices resulting from a decline in natural gas prices in December 2014. As detailed in Table 1, Net Loss, As Adjusted2, was $50 million in the fourth quarter of 2014 compared to Net Income, As Adjusted2, of $21 million in the prior year period. The year-over-year decline was driven largely by:

lower Commodity Margin, as previously discussed and

higher income tax expense due to higher Net Income1 in 2014 compared to the prior year period, changes in state apportionment and state law changes, partially offset by

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

Adjusted Free Cash Flow was $95 million in the fourth quarter of 2014 compared to $126 million in the prior year period. Adjusted Free Cash Flow decreased during the period primarily due to the decrease in Adjusted EBITDA, partially offset by lower interest expense, as previously discussed.

Full Year Results

Adjusted EBITDA in 2014 was $1,949 million compared to $1,830 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily due to a $191 million increase in Commodity Margin, partially offset by an increase in plant operating expense5 further described below. The increase in Commodity Margin was primarily due 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 the relative cost of consuming fuel oil was lower than natural gas and
+ stronger market conditions resulting in higher on-peak 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
the expiration of a tolling contract associated with our Delta Energy Center in December 2013 and our Osprey Energy Center in May 2014, the latter of which was replaced with a new contract in October 2014, and
lower regulatory capacity revenue in PJM during the second half of the year.

Net Income1 was $946 million in 2014, compared to $14 million in the prior year period. The year-over-year improvement in Net Income1 was primarily due to a gain on the previously mentioned asset sale, as well as higher Commodity Margin, as previously discussed. As detailed in Table 1, Net Income, As Adjusted2, was $309 million in 2014, compared to $186 million in the prior year period. The year-over-year improvement was driven largely by:

+ higher Commodity Margin, as previously discussed and
+ lower interest expense due to 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, the reversal in 2013 of previously recognized regulatory fees that did not recur in 2014 and a reclassification in 2014 of shared expenses associated with our Freeport Energy Center.

Adjusted Free Cash Flow was $830 million in 2014, compared to $677 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 and lower interest expense, as previously discussed.

5 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 and years ended December 31, 2014 and 2013.

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

Three Months Ended December 31, Year Ended December 31,
2014 2013 2014 2013
Net income (loss) attributable to Calpine $ 210 $ (97 ) $ 946 $ 14
Impairment losses(1) 16 123 16
(Gain) on sale of assets, net(1) (753 )
Debt extinguishment costs(1) 5 76 346 144
MtM (gain) loss on derivatives(1)(2) (265 ) 26 (353 ) 12
Net Income (Loss), As Adjusted(3) $ (50 ) $ 21 $ 309 $ 186

__________

(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 (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,
2014 2013 Variance 2014 2013 Variance
West $ 259 $ 283 $ (24 ) $ 1,050 $ 1,020 $ 30
Texas 116 95 21 760 632 128
East 163 211 (48 ) 949 916 33
Total $ 538 $ 589 $ (51 ) $ 2,759 $ 2,568 $ 191

West Region

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

the expiration of a tolling contract associated with our Delta Energy Center in December 2013 and
lower generation resulting from milder weather, partially offset by
+ higher contribution from hedges.

Full Year: Commodity Margin in our West segment increased by $30 million in 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 on-peak 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.

Texas Region

Fourth Quarter: Commodity Margin in our Texas segment increased by $21 million in the fourth 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, and
+ higher contribution from hedges.

Full Year: Commodity Margin in our Texas segment increased by $128 million in 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 on-peak spark spreads resulting from stronger market conditions in the first quarter of 2014 and
+ higher contribution from hedges.

East Region

Fourth Quarter: Commodity Margin in our East segment decreased by $18 million in the fourth quarter of 2014 compared to the prior year period, after excluding a decrease of $30 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, partially offset by
+ higher spark spreads as a result of favorable market conditions.

Full Year: Commodity Margin in our East segment increased by $104 million in 2014 compared to the prior year period, after excluding a decrease of $71 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 the relative cost of consuming fuel oil was lower than natural gas and
+ higher spark spreads realized by our Mid-Atlantic power plants, which benefited from locationally advantaged natural gas prices in the second half of 2014, partially offset by
lower contribution from hedges
the net effect of the expiration of a previously existing PPA associated with our Osprey Energy Center in May 2014 and a new PPA that began in October 2014 and
lower regulatory capacity revenue in PJM during the second half of the year.

LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES

Table 3: Liquidity

December 31, December 31,
2014 2013
(in millions)
Cash and cash equivalents, corporate(1)(2) $ 460 $ 649
Cash and cash equivalents, non-corporate 257 292
Total cash and cash equivalents 717 941
Restricted cash 244 272
Corporate Revolving Facility availability(3) 1,277 758
CDHI letter of credit facility availability 86 7
Total current liquidity availability $ 2,324 $ 1,978

__________

(1) Includes $47 million and $5 million of margin deposits posted with us by our counterparties at December 31, 2014 and 2013, respectively.

(2) On February 3, 2015, we issued our $650 million 2024 Senior Unsecured Notes and used the proceeds to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, and to repurchase approximately $150 million of our 2023 First Lien Notes and for general corporate purposes.

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

Liquidity was approximately $2.3 billion as of December 31, 2014. Cash and cash equivalents decreased during 2014 primarily due to acquisitions made during the year, as well as ongoing repurchases of our stock, partially offset by 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

Year Ended December 31,
2014 2013
(in millions)
Beginning cash and cash equivalents $ 941 $ 1,284
Net cash provided by (used in):
Operating activities 854 549
Investing activities (84 ) (593 )
Financing activities (994 ) (299 )
Net decrease in cash and cash equivalents (224 ) (343 )
Ending cash and cash equivalents $ 717 $ 941

Cash flows provided by operating activities in 2014 resulted in net inflows of $854 million compared to $549 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), driven by higher Commodity Margin, partially offset by an increase in plant operating expense. Also contributing to the increase was a decrease in working capital employed, largely due to lower net margin requirements and net accounts receivable/payable balances, as well as a decrease in interest payments due to lower effective interest rates as a result of refinancing activity throughout 2014. Partially offsetting these items, debt extinguishment payments increased due to the refinancing of our First Lien Notes during 2014.

Cash flows used in investing activities were $84 million in 2014 compared to $593 million in the prior year period. The decrease was primarily due to our 2014 portfolio management activities, which resulted in approximately $1.57 billion of proceeds from the sale of six power plants in our East segment, partially offset by approximately $1.2 billion used to purchase our Fore River and Guadalupe Energy Centers.

Cash flows used in financing activities in 2014 were $994 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

Returning capital to our shareholders by repurchasing shares of our common stock is a key and ongoing component of our capital allocation program. We continue to 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 $2.4 billion of our common stock, representing approximately 25% of shares outstanding.4

During 2014, we repurchased a total of 49.7 million shares of our outstanding common stock for approximately $1.1 billion at an average price of $22.14 per share. In 2015, through the issuance of this release, we have repurchased a total of 5.8 million shares of our outstanding common stock for approximately $125 million at an average price of $21.68 per share.

Sale of Six Power Plants

On July 3, 2014, we completed the sale of six of our power plants in our 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.

Osprey Energy Center

During the third quarter of 2014, we executed a PPA with Duke Energy Florida, Inc., related to our Osprey Energy Center with a term of 27 months which commenced in October 2014. Subsequently, we executed an asset sale agreement during the fourth quarter of 2014 for the sale of our Osprey Energy Center to Duke Energy Florida, Inc., upon the conclusion of the PPA for approximately $166 million, excluding working capital and other adjustments. The asset sale agreement is subject to federal and state regulatory approval and represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities.

Fore River Energy Center

On November 7, 2014, we completed the purchase of 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, increased capacity in our East segment, specifically the constrained New England market.

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, 2020 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 December 2014, we used cash on hand to redeem 10% of the original aggregate principal amount of our 2023 First Lien Notes, plus accrued and unpaid interest.

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 $150 million of our 7.875% First Lien Notes due 2023 and for general corporate purposes.

PLANT DEVELOPMENT

Texas:

Guadalupe Energy Center: On February 26, 2014, we completed the purchase of a modern, natural gas-fired, combined-cycle power plant with a nameplate capacity of 1,050 MW located in Guadalupe County, Texas for approximately $625 million, excluding working capital adjustments, which increased capacity in our Texas region. We also paid $15 million to acquire rights to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker plant. Development efforts are ongoing and we are continuing to advance entitlements (such as permits, zoning and transmission).

Channel and Deer Park Expansions: In June 2014, we completed construction to expand the baseload capacity of our Deer Park and Channel energy centers by approximately 260 MW6 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.

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 began in April 2013, and we expect to commence commercial operations 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, system impact and facilities studies for this phase. The facilities study results are being internally evaluated.

York 2 Energy Center: York 2 Energy Center is a 760 MW dual fuel combined-cycle project that will be co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. The project’s capacity cleared PJM’s 2017/2018 base residual auction and we expect commercial operations to commence during the second quarter of 2017. We executed a preliminary notice to proceed for the engineering, procurement and construction agreement during the fourth quarter of 2014 and are currently pursuing key permits and approvals for the project. PJM is completing a feasibility study for increasing York 2 Energy Center’s capacity by 120 MW.

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. Commercial operation of the expanded capacity may commence as early as June 2018, subject to applicable regulatory approvals and other contract conditions.

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 December 31, 2014, we have completed the upgrade of thirteen Siemens and eight GE turbines totaling approximately 210 MW and have committed to upgrade three additional turbines. In addition, we have begun a program to update our dual-fueled turbines at certain of our power plants in our East region.

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

OPERATIONS UPDATE

2014 Power Operations Achievements

  • Safety Performance:
    - Maintained top quartile7 safety metrics: 0.64 total recordable incident rate
  • Availability Performance:
    - Achieved low fleetwide forced outage factor: 1.9%
    - Delivered exceptional fleetwide starting reliability: 98.6%
  • Power Generation:
    - Provided approximately 6 million MWh of renewable baseload generation from our Geysers geothermal plants for the 14th consecutive year
    - Guadalupe, Hidalgo and Bethlehem energy centers: 100% starting reliability

___________

7 According to EEI Safety Survey (2013).

2014 Commercial Operations Achievements:

  • Customer-oriented Growth: During 2014, we entered into the following new contracts:

    West:
    - A ten-year PPA, subject to approval by the California Public Utilities Commission (CPUC), with Southern California Edison (SCE) to provide 225 MW of capacity and renewable energy from our Geysers assets commencing in June 2017
    - A 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
    - A three-year resource adequacy contract with 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
    - A two-year resource adequacy contract with SCE for our Delta Energy Center for 500 MW of capacity commencing in January 2017

    Texas:
    - A six-year PPA with the City of San Marcos to provide power from our Texas power plant fleet commencing in July 2015
    - A two-year PPA with Pedernales Electric Cooperative to provide approximately 70 MW of power from our Texas power plant fleet commencing in August 2016
    - A 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

    East:
    - A five-year PPA with Dairyland Power Cooperative to provide capacity and energy from our RockGen Energy Center commencing in June 2018. The capacity under contract will initially be 135 MW, and then will increase to 235 MW for the final four years of the contract
    - A PPA with a term of 27 months with Duke Energy Florida, Inc., to provide 515 MW of power and capacity from our Osprey Energy Center, which commenced in October 2014. The capacity under contract increased to 580 MW beginning in January 2015

2015 FINANCIAL OUTLOOK

(in millions, except per share amounts)

Full Year 2015
Adjusted EBITDA $ 1,900 – 2,100
Less:
Operating lease payments 35
Major maintenance expense and maintenance capital expenditures(1) 395
Cash interest, net(2) 630
Cash taxes 25
Other 5
Adjusted Free Cash Flow $ 810 – 1,010
Per Share Estimate (diluted) $ 2.10 – 2.60
Debt amortization(3) $ (360 )
Growth capital expenditures (net of debt funding) $ (355 )

________

(1) Includes projected major maintenance expense of $235 million and maintenance capital expenditures of $160 million in 2015. Capital expenditures exclude major construction and development projects.

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

(3) Includes the repurchase of approximately $150 million of our 2023 First Lien Notes in February 2015.

As detailed above, today we are reaffirming our 2015 guidance. 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 commencement 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 fourth quarter and full year of 2014 on Friday, February 13, 2015, at 10 a.m. Eastern time / 9 a.m. Central time. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing (800) 446-1671 in the U.S. or (847) 413-3362 outside the U.S. The confirmation code is 38744477. 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 38744477. Presentation materials to accompany the conference call will be available on our website on February 13, 2015.

ABOUT CALPINE

Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources. Our fleet of 88 power plants in operation or under construction represents nearly 27,000 megawatts of generation capacity. Serving customers in 18 states and Canada, we specialize in developing, constructing, owning and operating natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our clean, efficient, modern and flexible fleet is uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. We focus on competitive wholesale power markets and advocate for market-driven solutions that result in nondiscriminatory forward price signals for investors. Please visit www.calpine.com to learn more about why Calpine is a generation ahead – today.

Calpine’s Annual Report on Form 10-K for the year ended December 31, 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 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 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;
  • Competition, including risks associated with marketing and selling power in the evolving energy markets;
  • Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies);
  • The expiration or early termination of our PPAs and the related results on revenues;
  • Future capacity revenues may not occur at expected levels;
  • Natural disasters, such as hurricanes, earthquakes and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants serve and our corporate headquarters;
  • Disruptions in or limitations on the transportation of natural gas, fuel oil and transmission of power;
  • Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions;
  • Our ability to attract, motivate and retain key employees;
  • Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and
  • Other risks identified in this press release and in our 2014 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 STATEMENTS OF OPERATIONS

(Unaudited)
Three Months Ended December 31, Year Ended December 31,
2014 2013 2014 2013
(in millions, except share and per share amounts)
Operating revenues:
Commodity revenue $ 1,595 $ 1,507 $ 7,595 $ 6,374
Mark-to-market gain (loss) 338 (72 ) 419 (86 )
Other revenue 6 3 16 13
Operating revenues 1,939 1,438 8,030 6,301
Operating expenses:
Fuel and purchased energy expense:
Commodity expense 1,058 899 4,815 3,808
Mark-to-market (gain) loss 75 (43 ) 77 (72 )
Fuel and purchased energy expense 1,133 856 4,892 3,736
Plant operating expense 215 211 969 895
Depreciation and amortization expense 150 152 603 593
Sales, general and other administrative expense 36 34 144 136
Other operating expenses 22 23 88 81
Total operating expenses 1,556 1,276 6,696 5,441
Impairment losses 16 123 16
(Gain) on sale of assets, net (753 )
(Income) from unconsolidated investments in power plants (7 ) (5 ) (25 ) (30 )
Income from operations 390 151 1,989 874
Interest expense 154 174 645 696
Interest (income) (1 ) (1 ) (6 ) (6 )
Debt extinguishment costs 5 76 346 144
Other (income) expense, net 1 5 21 20
Income (loss) before income taxes 231 (103 ) 983 20
Income tax expense (benefit) 17 (10 ) 22 2
Net income (loss) 214 (93 ) 961 18
Net income attributable to the noncontrolling interest (4 ) (4 ) (15 ) (4 )
Net income (loss) attributable to Calpine $ 210 $ (97 ) $ 946 $ 14
Basic earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 384,964 429,331 404,837 440,666
Net income (loss) per common share attributable to Calpine – basic $ 0.55 $ (0.23 ) $ 2.34 $ 0.03
Diluted earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 389,425 429,331 409,360 444,773
Net income (loss) per common share attributable to Calpine – diluted $ 0.54 $ (0.23 ) $ 2.31 $ 0.03
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 2014 and 2013
(in millions, except share and per share amounts)
2014 2013
ASSETS
Current assets:
Cash and cash equivalents $ 717 $ 941
Accounts receivable, net of allowance of $4 and $5 648 552
Inventories 447 364
Margin deposits and other prepaid expense 148 309
Restricted cash, current 195 203
Derivative assets, current 2,058 445
Other current assets 7 42
Total current assets 4,220 2,856
Property, plant and equipment, net 13,190 12,995
Restricted cash, net of current portion 49 69
Investments in power plants 95 93
Long-term derivative assets 439 105
Other assets 385 441
Total assets $ 18,378 $ 16,559
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable $ 580 $ 462
Accrued interest payable 165 162
Debt, current portion 199 204
Derivative liabilities, current 1,782 451
Other current liabilities 473 252
Total current liabilities 3,199 1,531
Debt, net of current portion 11,083 10,908
Long-term derivative liabilities 444 243
Other long-term liabilities 221 309
Total liabilities 14,947 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, 502,287,022 shares issued and 381,921,264 shares outstanding at December 31, 2014, and 497,841,056 shares issued and 429,038,988 shares outstanding at December 31, 2013 1 1
Treasury stock, at cost, 120,365,758 and 68,802,068 shares, respectively (2,345 ) (1,230 )
Additional paid-in capital 12,440 12,389
Accumulated deficit (6,540 ) (7,486 )
Accumulated other comprehensive loss (178 ) (160 )
Total Calpine stockholders’ equity 3,378 3,514
Noncontrolling interest 53 54
Total stockholders’ equity 3,431 3,568
Total liabilities and stockholders’ equity $ 18,378 $ 16,559
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2014 and 2013
(in millions)
2014 2013
Cash flows from operating activities:
Net income $ 961 $ 18
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense(1) 649 638
Debt extinguishment costs 36 43
Deferred income taxes 5 14
Impairment losses 123 16
(Gain) on sale of assets, net (753

)

Mark-to-market activity, net (353

)

12

(Income) from unconsolidated investments in power plants (25

)

(30

)
Return on unconsolidated investments in power plants 13 25
Stock-based compensation expense 36 36
Other (4

)

1

Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable (87

)

(113

)
Derivative instruments, net (63

)

(7

)
Other assets 151 (148 )
Accounts payable and accrued expenses 185 (1 )
Other liabilities (20

)

45

Net cash provided by operating activities 854 549
Cash flows from investing activities:
Purchases of property, plant and equipment (492

)

(575

)
Proceeds from sale of power plants, interests and other 1,573 1
Purchase of Fore River and Guadalupe Energy Centers (1,197

)

(Increase) decrease in restricted cash 28 (18 )
Other 4 (1 )
Net cash used in investing activities

(84

)

(593

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

420

1,587
Repayments of CCFC Term Loans, CCFC Notes and First Lien Term Loans (45 ) (1,031 )
Borrowings under Senior Unsecured Notes 2,800
Borrowings under First Lien Notes 1,234
Repayments of First Lien Notes (2,920 ) (1,550 )
Borrowings from project financing, notes payable and other 79 182
Repayments of project financing, notes payable and other (178 ) (66 )
Distribution to noncontrolling interest holder (15 )
Financing costs (56 ) (53 )
Stock repurchases (1,100 ) (623 )
Proceeds from exercises of stock options 20 20
Other 1 1
Net cash used in financing activities (994 ) (299 )
Net decrease in cash and cash equivalents (224 ) (343 )
Cash and cash equivalents, beginning of period 941 1,284
Cash and cash equivalents, end of period $ 717 $ 941
Cash paid during the period for:
Interest, net of amounts capitalized $ 610 $ 672
Income taxes $ 23 $ 24
Supplemental disclosure of non-cash investing activities:
Change in capital expenditures included in accounts payable $ 3 $ 27
Additions to property, plant and equipment through capital leases $ 19 $

__________

(1) Includes depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated 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, at December 31, 2014, our reportable segments were West (including geothermal), Texas and East (including Canada).

The following tables reconcile our Commodity Margin to its U.S. GAAP results for the three months ended December 31, 2014 and 2013 (in millions):

Three Months Ended December 31, 2014
Consolidation
And
West Texas East Elimination Total
Commodity Margin(1) $ 259 $ 116 $ 163 $ $ 538
Add: Mark-to-market commodity activity, net and other(2) 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
Three Months Ended December 31, 2013
Consolidation
And
West Texas East Elimination Total
Commodity Margin(1) $ 283 $ 95 $ 211 $ $ 589
Add: Mark-to-market commodity activity, net and other(2) (48 ) 33 15 (7 ) (7 )
Less:
Plant operating expense 94 55 71 (9 ) 211
Depreciation and amortization expense 63 40 50 (1 ) 152
Sales, general and other administrative expense 13 13 8 34
Other operating expenses 12 (1 ) 8 4 23
Impairment loss 16 16
(Income) from unconsolidated investments in power plants (5 ) (5 )
Income from operations $ 37 $ 21 $ 94 $ (1 ) $ 151

The following tables reconcile our Commodity Margin to its U.S. GAAP results for the years ended December 31, 2014 and 2013 (in millions):

Year Ended December 31, 2014
Consolidation
And
West Texas East Elimination Total
Commodity Margin(3) $ 1,050 $ 760 $ 949 $ $ 2,759
Add: Mark-to-market commodity activity, net and other(4) 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 loss 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
Year Ended December 31, 2013
Consolidation
And
West Texas East Elimination Total
Commodity Margin(3) $ 1,020 $ 632 $ 916 $ $ 2,568
Add: Mark-to-market commodity activity, net and other(4) (50 ) 51 27 (31 ) (3 )
Less:
Plant operating expense 365 269 292 (31 ) 895
Depreciation and amortization expense 227 165 203 (2 ) 593
Sales, general and other administrative expense 37 56 42 1 136
Other operating expenses 45 3 33 81
Impairment loss 16 16
(Income) from unconsolidated investments in power plants (30 ) (30 )
Income from operations $ 280 $ 190 $ 403 $ 1 $ 874

_________

(1) Our East segment includes commodity margin of nil and $30 million for the three months ended December 31, 2014 and 2013, respectively, related to the six power plants in our East segment that were sold in July 2014.

(2) Includes $2 million and $(11) million of lease levelization and $3 million and $3 million of amortization expense for the three months ended December 31, 2014 and 2013, respectively.

(3) Our East segment includes Commodity Margin of $81 million and $152 million for the years ended December 31, 2014 and 2013, respectively, related to the six power plants in our East segment that were sold in July 2014.

(4) Includes $(5) million and $6 million of lease levelization and $14 million and $14 million of amortization expense for the years ended December 31, 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 (loss) attributable to Calpine for the three months and years ended December 31, 2014 and 2013, as reported under U.S. GAAP.

Three Months Ended
December 31, Year Ended December 31,

2014

2013(1) 2014(2) 2013(2)
(in millions) (in millions)
Net income (loss) attributable to Calpine $ 210 $ (97 ) $ 946 $ 14
Net income attributable to the noncontrolling interest 4 4 15 4
Income tax expense (benefit) 17 (10 ) 22 2
Debt extinguishment costs and other (income) expense, net 6 81 367 164
Interest expense, net of interest income 153 173 639 690
Income from operations $ 390 $ 151 $ 1,989 $ 874
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(3) 149 152 598 593
Major maintenance expense 45 42 234 224
Operating lease expense 8 9 34 35
Mark-to-market (gain) loss on commodity derivative activity (263 ) 29 (342 ) 14
Impairment losses 16 123 16
(Gain) on sale of assets, net (753 )
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest(4) (1 ) 1 5 14
Stock-based compensation expense 6 8 36 36
(Gain) loss on dispositions of assets (1 ) 1 4
Acquired contract amortization 3 3 14 14
Other 8 (11 ) 10 6
Total Adjusted EBITDA $ 345 $ 399 $ 1,949 $ 1,830
Less:
Operating lease payments 8 8 34 34
Major maintenance expense and capital expenditures(5) 84 89 410 392
Cash interest, net(6) 155 172 652 700
Cash taxes 2 1 18 19
Other 1 3 5 8
Adjusted Free Cash Flow(7) $ 95 $ 126 $ 830 $ 677
Weighted average shares of common stock outstanding (diluted, in thousands) 389,425 429,331 409,360 444,773
Adjusted Free Cash Flow Per Share (diluted) $ 0.24 $ 0.29 $ 2.03 $ 1.52

_________

(1) Adjusted EBITDA related to the six power plants sold in our East segment on July 3, 2014, was $16 million for the three months ended December 31, 2013.

(2) Our East segment includes Adjusted EBITDA of $43 million and $88 million for the years ended December 31, 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 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 months and years ended December 31, 2014 and 2013.

(5) 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 expenditure for the three months and year ended December 31, 2014, respectively. Includes $43 million and $228 million in major maintenance expense for the three months and year ended December 31, 2013, respectively, and $46 million and $164 million in maintenance capital expenditure for the three months and year ended December 31, 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 $136 million and $118 million for the three months and year ended December 31, 2014, respectively, and a decrease in working capital of $135 million and an increase in working capital of $130 million for the three months and year ended December 31, 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 months and years ended December 31, 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 December 31, Year Ended December 31,
2014 2013 2014 2013
(in millions) (in millions)
Commodity Margin $ 538 $ 589 $ 2,759 $ 2,568
Other revenue 5 3 15 12
Plant operating expense(1) (166 ) (165 ) (705 ) (645 )
Sales, general and administrative expense(2) (33 ) (30 ) (126 ) (117 )
Other operating expenses(3) (11 ) (10 ) (47 ) (42 )
Adjusted EBITDA from unconsolidated investments in power plants 12 14 53 58
Other (2 ) (4 )
Adjusted EBITDA $ 345 $ 399 $ 1,949 $ 1,830

_________

(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 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 December 31, Year Ended December 31,
2014 2013 2014 2013
Total MWh generated (in thousands)(1) 26,106 25,585 100,617 101,610
West 8,960 10,359 34,195 36,110
Texas 10,388 8,119 38,678 33,343
East 6,758 7,107 27,744 32,157
Average availability 90.2 % 91.2 % 90.7 % 91.7 %
West 92.4 % 92.9 % 92.9 % 92.2 %
Texas 91.4 % 90.6 % 90.5 % 89.8 %
East 86.9 % 90.4 % 89.2 % 93.0 %
Average capacity factor, excluding peakers 52.3 % 48.0 % 48.4 % 48.7 %
West 57.6 % 66.7 % 55.4 % 62.6 %
Texas 51.2 % 47.2 % 49.9 % 48.9 %
East 47.8 % 34.4 % 40.0 % 38.7 %
Steam adjusted heat rate (Btu/kWh) 7,348 7,339 7,384 7,386
West 7,324 7,241 7,314 7,308
Texas 7,153 7,214 7,203 7,198
East 7,687 7,608 7,721 7,663

________

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

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