Forward-Looking Information
This Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our accompanying Consolidated Financial Statements and related notes. See the cautionary statement regarding forward-looking statements on page 1 of this Report for a description of important factors that could cause actual results to differ from expected results. See also Item 1A. "Risk Factors."
INTRODUCTION AND OVERVIEW
Our Business
We are one of the largest power generators in the U.S. measured by power produced. We own and operate primarily natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive wholesale power markets in California, Texas and the Mid-Atlantic region of the U.S. We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of power plants. We purchase natural gas and fuel oil as fuel for our power plants, engage in related natural gas transportation and storage transactions, and we purchase electric transmission rights to deliver power to our customers. We also enter into natural gas and power physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants. Our goal is to be recognized as the premier wholesale power company in the U.S. as measured by our employees, customers, regulators, shareholders and communities in which our facilities are located. We seek to achieve sustainable growth through financially disciplined power plant development, construction, acquisition, operation and ownership. We will continue to pursue opportunities to improve our fleet performance and reduce operating costs. In order to manage our various physical assets and contractual obligations, we will continue to execute commodity agreements within the guidelines of our Risk Management Policy. We assess our business on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. Our reportable segments are West (including geothermal), Texas, North (including Canada) and Southeast.
Our portfolio, including partnership interests, consists of 92 power plants, including 4 under construction (1 new power plant and 3 expansions of existing power plants), located throughout 20 states in the U.S. and in Canada, with an aggregate generation capacity of 27,321 MW and 1,163 MW under construction. Our fleet, including projects under construction, consists of 74 combustion turbine-based plants, 2 fossil steam-based plants, 15 geothermal turbine-based plants and 1 photovoltaic solar plant. Our segments have an aggregate generation capacity of 6,751 MW with an additional 773 MW under construction in the West, 8,014 MW with additional 390 MW under construction in Texas, 7,320 MW in the North and 5,236 MW in the Southeast. Our Geysers Assets are included in our West segment.
Current Year Operational Developments
Our objective is to be the "best-in-class" in regards to certain operational performance metrics, such as safety, availability, reliability, efficiency and cost management. In addition, we continue to grow our presence in core markets with an emphasis on expansions or modernizations of existing power plants. Our notable operational performance metrics, significant projects under construction, organic growth initiatives and modernizations are discussed below:
• We produced approximately 116 billion KWh of electricity in 2012, 23% more than the same period in 2011 (includes generation from power plants owned but not operated by us and our share of generation from our unconsolidated power plants).

• Our entire fleet achieved a forced outage factor of 1.6% in 2012, our lowest on record and an improvement of 36% from 2011.

• Our entire fleet achieved an impressive starting reliability of 98.3% in 2012.

•        During 2012, our outage services subsidiary completed 11 major
         inspections and 19 hot gas path inspections.


•        For the past twelve consecutive years, our Geysers Assets have reliably
         generated approximately 6 million MWh per year and, in 2012, achieved an
         exceptional availability factor of approximately 97%.

•        Construction of our Russell City Energy Center and modernization at our
         Los Esteros Critical Energy Facility continue to move forward with
         expected completion dates during the summer of 2013.


•        We continue to make progress with our turbine modernization program and
         have ongoing development and expansion activities which include the
         advanced development of the Garrison Energy Center located in Dover,
         Delaware and the expansions of our Deer Park and Channel Energy Centers
         in Texas which are now under construction.

Enhancing Shareholder Value
We continue to make significant progress to deliver financially disciplined
growth, to enhance shareholder value through our capital allocation and share
repurchases and to set the foundation for continued growth and success. Given
our strong cash flow from operations, we are committed to remaining financially
disciplined in our capital allocation decisions. The year ended December 31,
2012 was marked by the following accomplishments:
•         As of the filing of this Report, we have completed our previously
          announced $600 million share repurchase program, having repurchased a
          total of 35,568,833 shares of our outstanding common stock at an
          average price paid of $16.87 per share. In February 2013, our Board of
          Directors authorized the repurchase of an additional $400 million in
          shares of our common stock, bringing the cumulative authorization total
          to $1.0 billion.


•         During the first quarter of 2012, we terminated our legacy interest
          rate swaps formerly hedging our First Lien Credit Facility for a
          payment of approximately $156 million which eliminated our exposure
          from these instruments to further declines in interest rates.


•         On October 9, 2012, we issued our 2019 First Lien Term Loan and used
          the proceeds to reduce our overall cost of debt and simplify our
          capital structure by redeeming a portion of our First Lien Notes and
          repaying project debt.


•         On November 7, 2012, we completed the purchase of a modern, natural
          gas-fired, combined-cycle power plant with a nameplate capacity of 800
          MW located in Bosque County, Texas for approximately $432 million which
          increased capacity in our Texas segment.


•         On December 27, 2012, we, through our indirect, wholly-owned subsidiary
          Calpine Power Company, completed the sale of 100% of our ownership
          interest in each of the Broad River Entities for approximately $423
          million. This transaction resulted in the disposition of our Broad
          River power plant, an 847 MW natural gas-fired, peaking power plant
          located in Gaffney, South Carolina, and includes a five year consulting
          agreement with the buyer. We expect to use the sale proceeds for our
          capital allocation activities and for general corporate purposes.


•         On December 31, 2012, we completed the sale of Riverside Energy Center,
          LLC to WP&L for approximately $402 million. We expect to use the sale
          proceeds for our capital allocation activities and for general
          corporate purposes.

For a further discussion of our capital management and significant financing transactions completed in 2012, see "- Liquidity and Capital Resources." Customer-Oriented Origination Business
We continue to focus on providing products and services that are beneficial to our customers. A summary of certain significant contracts entered into in 2012 is as follows:

•         We entered into a new twenty-year PPA with Western Farmers Electric
          Cooperative to provide 160 MW of power generated by our Oneta Energy
          Center, commencing in June 2014. The capacity under contract will
          increase in increments, up to a maximum of 280 MW in years 2019 through
          2035.


•         We entered into a new five-year PPA with Southwestern Public Service
          Company, a subsidiary of Xcel Energy, to provide an additional 200 MW
          of power generated by our Oneta Energy Center commencing on June 1,
          2014.


•         We entered into a new five-year resource adequacy contract with PG&E
          for approximately 280 MW of combined heat and power capacity from our
          Los Medanos Energy Center commencing in the summer 2013.


•         We entered into a new seven-year resource adequacy contract with
          Southern California Edison Company ("SCE") for approximately 280 MW of
          combined heat and power capacity from our Los Medanos Energy Center and
          a new five-year resource adequacy contract with SCE for approximately
          120 MW of combined heat and power capacity from our Gilroy Cogeneration
          Plant, both commencing in January 2014.


•         We amended an existing PPA with Dow Chemical Company for an incremental
          energy sale of up to approximately 158,000 MWh per year of energy from
          our Los Medanos Energy Center which runs through February 2025.


•         We entered into a new fifteen-year PPA with American Electric Power
          Service Corporation, as agent for Public Service Company of Oklahoma,
          to provide 260 MW of energy, capacity and ancillary services from our
          Oneta Energy Center commencing in June 2016.

•         We entered into a new ten-year PPA with the Tennessee Valley Authority
          to provide the full output of power generated by our Decatur Energy
          Center, a natural gas-fired, combined-cycle power plant that can
          generate up to 795 MW, commencing in January 2013.

Our Regulatory and Environmental Profile We are subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of our power plants. Federal and state legislative and regulatory actions continue to change how our business is regulated. The EPA is moving forward on climate change regulation, and has already promulgated regulations related to other air pollutant emissions, and some states and regions in the U.S. have implemented or are considering implementing regulations to reduce GHG emissions. We are actively participating in these debates at the federal, regional and state levels. For a further discussion of the environmental and other governmental regulations that affect us, see "- Governmental and Regulatory Matters" in Item 1. of this Report. Although we cannot predict the ultimate effect future climate change regulations or legislation could have on our business, we believe that we will be less adversely impacted by potential Cap-and-trade limits, carbon taxes or required environmental upgrades as a result of future potential regulation or legislation addressing GHG, other air emissions, as well as water use or emissions, than compared to our competitors who use other fossil fuels or steam condensation technologies.
Since our inception in 1984, we have been a leader in environmental stewardship and have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of power plants. The combination of our Geysers Assets and our high efficiency portfolio of natural gas-fired power plants results in substantially lower emissions of these gases compared to our competitors' power plants using other fossil fuels, such as coal. Consequently, our power generation portfolio has the lowest GHG footprint per MWh of any major wholesale power producer in the U.S. In addition, we strive to preserve our nation's valuable water and land resources. To condense steam, we primarily use cooling towers with a closed water cooling system or air cooled condensers. Since our power plants are modern and efficient and utilize clean burning natural gas, we do not require large areas of land for our power plants nor do we require large specialized landfills for the disposal of coal ash or nuclear plant waste. Our Market and Our Key Financial Performance Drivers The market Spark Spread, sales of RECs, revenues from our PPAs and steam sales and the results from our marketing, hedging and optimization activities are the primary drivers of our Commodity Margin and contribute significantly to our financial results. The market Spark Spread is primarily impacted by fuel prices, weather and reserve margins, which impact our supply and demand fundamentals. Those factors, plus the relationship between our operating Heat Rate compared to the Market Heat Rate, our power plant operating performance and availability are key to our financial performance.
Fluctuations in natural gas price levels affect our Commodity Margin (depending on our hedge levels and holding other factors constant). When less efficient, higher cost natural gas-fired units set power prices in our regional markets, higher natural gas prices tend to increase our Commodity Margin. In these instances, while our production costs increase when natural gas prices are higher, our competitors' costs (and power prices) increase at a greater rate, leading to higher Commodity Margin. Similarly, when natural gas prices decline, our Commodity Margin tends to decline.
In 2012, given very low natural gas prices, natural gas-fired, combined-cycle units in many markets were frequently cheaper to dispatch than coal-fired power plants. When coal-fired electricity production costs exceed natural gas-fired production costs, coal-fired units tend to set power prices. In these hours, lower natural gas prices tend to increase our Commodity Margin, since our production costs fall while power prices remain constant (depending on our hedge levels and holding other factors constant).
Efficient operation of our fleet creates the opportunity to capture Commodity Margin in a cost effective manner. However, unplanned outages during periods when Commodity Margin is positive could result in a loss of that opportunity. We generally measure our fleet performance based on our availability factors, Heat Rate and plant operating expense. The higher our availability factor, the better positioned we are to capture Commodity Margin. The less natural gas we must consume for each MWh of power generated, the lower our Heat Rate. The lower our operating Heat Rate compared to the Market Heat Rate, the more favorable the impact on our Commodity Margin. Holding all other factors constant, our Commodity Margin increases when we are able to lower our operating Heat Rate compared to the Market Heat Rate and conversely decreases when our operating Heat Rate increases compared to the Market Heat Rate. See also "- The Market for Power - Our Power Markets and Market Fundamentals" in Item 1. of this Report for additional information on how these factors impact our Commodity Margin.

RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2012 AND 2011
Below are our results of operations for the year ended December 31, 2012, as
compared to the same period in 2011 (in millions, except for percentages and
operating performance metrics). In the comparative tables below, increases in
revenue/income or decreases in expense (favorable variances) are shown without
brackets while decreases in revenue/income or increases in expense (unfavorable
variances) are shown with brackets.
                                             2012          2011         Change       % Change
Operating revenues:
Commodity revenue                         $   5,417     $   6,753     $  (1,336 )        (20 )
Unrealized mark-to-market gain                   48            35            13           37
Other revenue                                    13            12             1            8
Operating revenues                            5,478         6,800        (1,322 )        (19 )
Operating expenses:
Fuel and purchased energy expense:
Commodity expense                             2,894         4,299         1,405           33
Unrealized mark-to-market loss                  130            60           (70 )          #
Fuel and purchased energy expense             3,024         4,359         1,335           31
Plant operating expense                         922           904           (18 )         (2 )
Depreciation and amortization expense           562           550           (12 )         (2 )
Sales, general and other administrative
expense                                         140           131            (9 )         (7 )
Other operating expenses                         78            77            (1 )         (1 )
Total operating expenses                      4,726         6,021         1,295           22
(Gain) on sale of assets, net                  (222 )           -           222            #
(Income) from unconsolidated investments
in power plants                                 (28 )         (21 )           7           33
Income from operations                        1,002           800           202           25
Interest expense                                736           760            24            3
Loss on interest rate derivatives                14           145           131           90
Interest (income)                               (11 )          (9 )           2           22
Debt extinguishment costs                        30            94            64           68
Other (income) expense, net                      15            21             6           29
Income (loss) before income taxes               218          (211 )         429            #
Income tax expense (benefit)                     19           (22 )         (41 )          #
Net income (loss)                               199          (189 )         388            #
Net income attributable to the
noncontrolling interest                           -            (1 )           1            #
Net income (loss) attributable to Calpine $     199     $    (190 )   $     389            #


                                             2012        2011      Change    % Change
Operating Performance Metrics:
MWh generated (in thousands)(1)            112,216     90,875     21,341           23
Average availability                          91.3 %     90.1 %      1.2 %          1
Average total MW in operation(1)            27,318     27,234         84            -
Average capacity factor, excluding peakers    53.7 %     44.3 %      9.4 %         21
Steam Adjusted Heat Rate                     7,361      7,412         51            1


__________
# Variance of 100% or greater

(1) Represents generation and capacity from power plants that we both consolidate and operate. See "- Description of Our Power Plants - Table of Operating Power Plants and Projects Under Construction and Advanced Development" for our total equity generation and capacities.

We evaluate our Commodity revenue and Commodity expense on a collective basis because the price of power and natural gas tend to move together as the price for power is generally determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in "Commodity Margin and Adjusted EBITDA."
Commodity revenue, net of Commodity expense, increased $69 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due to:

•         higher contribution from hedges primarily in our Texas segment during
          the third quarter of 2012 compared to the third quarter of 2011;


•         higher generation in our Texas and North segments due to lower natural
          gas prices during 2012 compared to 2011 and higher generation in our
          West segment due to improved market conditions, less hydroelectric
          generation and a nuclear power plant outage in California during 2012;
          and


•         an extreme cold weather event in Texas that occurred on February 2,
          2011, and resulted in unplanned outages at some of our power plants,
          negatively impacting our revenue for the year ended December 31, 2011,
          which did not reoccur in 2012; partially offset by

• lower regulatory capacity revenue during 2012 compared to 2011; and

• the expiration of contracts which decreased revenue during the year ended December 31, 2012 compared to the year ended December 31, 2011.

Generation increased 23% primarily due to lower natural gas prices in our Texas segment during certain periods in the first half of 2012 and in our North segment during certain periods throughout 2012 and improved market conditions, less hydroelectric generation and a nuclear power plant outage in our West segment during the year ended December 31, 2012. During the year ended December 31, 2012, generation increased as natural gas prices were low enough that during certain periods some of our modern, natural gas-fired, combined-cycle power plants in Texas and PJM became less expensive on a marginal basis than coal-fired generation resulting in these plants running baseload. The increase in generation also resulted in a 1% decrease in our Steam Adjusted Heat Rate for the year ended December 31, 2012, compared to the year ended December 31, 2011, as our power plants tend to operate more efficiently under baseload operations. Our average total MW in operation increased by 84 MW primarily due to the acquisition of our 762 MW Bosque Energy Center, our 565 MW York Energy Center which achieved COD in March 2011 and an increase in capacity resulting from our turbine modernization program partially offset by the temporary shut down of our Los Esteros Critical Energy Facility associated with the upgrade from simple-cycle to combined-cycle technology.

Unrealized mark-to-market gain/loss from hedging our future generation and fuel needs, for the year ended December 31, 2012, compared to the year ended December 31, 2011, had an unfavorable variance of $57 million primarily driven by the realization of favorable natural gas hedge positions in 2012 previously reported in unrealized mark-to-market gain/loss at December 31, 2011, partially offset by settlements during 2012 of Heat Rate hedge positions that were unfavorable based on forward curves at December 31, 2011.

Despite a 23% increase in generation, our normal, recurring plant operating expense was largely unchanged for the year ended December 31, 2012, compared to the year ended December 31, 2011, after accounting for $20 million in reimbursements for insurance claims from prior periods that disproportionately reduced our plant operating expense for the year ended December 31, 2011.

Depreciation and amortization expense increased by $12 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily resulting from a decrease of $17 million for the year ended December 31, 2011 related to a revision in the expected settlement dates of the asset retirement obligations related to our natural gas-fired and geothermal power plants, partially offset by a decrease of $2 million resulting from lower depreciation associated with the sale of Broad River in December 2012.
Gain on sale of assets, net consists of a $215 million gain related to the sale of 100% of our ownership interests in each of the Broad River Entities, and a $7 million gain related to the sale of our Riverside Energy Center, both of which closed in December 2012. See Note 3 of the Notes to Consolidated Financial Statements for further information.

Income from unconsolidated investments in power plants increased for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due to a $3 million favorable change in fair value related to hedging activities associated with derivative contracts at Greenfield LP, a $2 million increase in operating income for Whitby due to the expiration of an unfavorable natural gas transportation contract in 2011 and a $1 million increase in operating income for Greenfield LP due to lower natural gas prices in 2012 compared to 2011.

Interest expense decreased by $24 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due to a decrease in our annual effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and unrealized gains (losses) on interest rate swaps, to 7.3% for the year ended December 31, 2012, from 7.6% for the year ended December 31, 2011. The issuance of our First Lien Term Loans in 2011 and 2012 allowed us to reduce our overall cost of debt by replacing a portion of our First Lien Notes and variable rate project debt with corporate level term loans carrying a lower variable interest rate. See Note 6 of the Notes to Consolidated Financial Statements for further information regarding the issuance of our First Lien Term Loans, the repayment of the portion of our First Lien Notes and the repayment of variable rate project debt.

Loss on interest rate derivatives had a favorable change of $131 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily resulting from $91 million of historical unrealized losses previously deferred in AOCI and reclassified into income in January 2011 in connection with the retirement of the First Lien Credit Facility term loans. Also contributing to the year-over-year change was a favorable change of $40 million resulting from interest rate swap breakage costs related to the repayment of project debt in June 2011 and changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility term loans. See Note 8 of the Notes to Consolidated Financial Statements for further discussion of our interest rate swaps formerly hedging our First Lien Credit Facility term loans.

Debt extinguishment costs for the year ended December 31, 2012, consisted of $18 million associated with the redemption premium, the write-off of unamortized deferred financing costs and debt premium and discount related to repayment of a portion of our First Lien Notes and variable rate project debt during the fourth quarter of 2012, and $12 million associated with the purchase of two of the three third party interests in GEC Holdings, LLC in March 2012 that were previously recorded as preferred interests and classified as debt under U.S. GAAP. Debt extinguishment costs for the year ended December 31, 2011, primarily . . .