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During 2015, our employees achieved a total recordable incident rate of 0.73 recordable injuries per 100 employees which places us in the first quartile performance for power generation companies with 1,000 or more employees.

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Our entire fleet achieved a forced outage factor of 2.3% and a starting reliability of 98.3% during the year ended December 31, 2015.

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During 2015, our outage services subsidiary completed 15 major inspections and nine hot gas path inspections.

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For the past 15 years on average, our Geysers Assets have reliably generated approximately six million MWh of renewable power per year.

2.

Focus on Managing and Growing our Portfolio  — Our goal is to continue to grow our presence in core markets with an emphasis on acquisitions, expansions or modernizations of existing power plants. We intend to take advantage of favorable opportunities to continue to design, develop, acquire, construct and operate the next generation of highly efficient, operationally flexible and environmentally responsible power plants where such investment meets our rigorous financial hurdles, particularly if power contracts and financing are available and attractive returns are expected. Likewise, we actively seek to divest non-core assets where we can find opportunities to do so accretively. In addition, we believe that modernizations and expansions to our current assets offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. During 2015 and through the filing of this Report, we strategically repositioned

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In June 2015, our Garrison Energy Center commenced commercial operations, bringing online approximately 309 MW of combined-cycle, natural gas-fired capacity with dual-fuel capability.

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During the second quarter of 2015, we began construction of our 760 MW York 2 Energy Center and expect commercial operations to commence during the second quarter of 2017.

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In July 2015, the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments, was approved by the FERC and the Florida Public Service Commission. In accordance with the asset sale agreement, the sale will be consummated in January 2017 upon the conclusion of a 27-month PPA. This sale represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities.

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On October 1, 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.

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On February 5, 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 will increase capacity in our East segment, specifically the constrained New England market.

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Garrison Energy Center — 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 to our existing Garrison Energy Center. PJM has completed its feasibility study of the project and the system impact study is underway.

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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 COD 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 2018/2019 base residual auction.

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Guadalupe Peaking Energy Center — I n 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 COD 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.

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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.

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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.

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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

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In 2015, Champion Energy, our retail electric provider, 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.

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We entered into a new 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.

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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 in the first quarter of 2015.

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We entered into a new 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 CPUC.

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We entered into a new one-year resource adequacy contract with SCE for 238 MW from our Pastoria Energy Center commencing in January 2018.

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We entered into a new 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.

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We entered into a new three-year PPA with Brazos Electric Power Cooperative to provide 300 MW of energy from our Texas power plant fleet commencing in January 2016.

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We entered into a new three-year PPA with Pedernales Electric Cooperative to provide approximately 140 MW of energy from our Texas power plant fleet commencing in January 2017.

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We entered into a new 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.

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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.

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We entered into a new 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.

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We entered into a new ten-year PPA with the Tennessee Valley Authority to provide 615 MW of energy and capacity from our Morgan Energy Center commencing in February 2016.

4.

Focus on Advocacy and Corporate Responsibility  — We recognize that our business is heavily influenced by laws, regulations and rules at federal, state and local levels as well as by rules of the ISOs and RTOs that oversee the competitive markets in which we operate. We believe that being active participants in the legislative, regulatory and rulemaking processes may yield better outcomes for all stakeholders, including Calpine. Our two basic areas of focus are competitive wholesale power markets and environmental stewardship in power generation. Below are some recent examples of our advocacy efforts:

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Provided leadership in stakeholder processes at PJM on a new “Capacity Performance” product and at ISO-NE on its Pay-For-Performance initiatives, resulting in implementation of the FERC approved PJM Capacity Performance product and ISO-NE Pay-For-Performance capacity structure.

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Our employees participated as invited panelists at FERC technical conferences regarding price formation and “out-of-market payments” in organized markets.

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Successfully navigated a competitive generation supply bidding process in Florida, resulting in a contract for the acquisition of our Osprey Energy Center rather than a utility self-build as the most cost effective alternative for Florida ratepayers.

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Successfully advocated for a competitive generation supply bidding process in Minnesota and succeeded in obtaining an order requiring the local utility to enter into a long-term PPA for new additional capacity at our Mankato Power Plant.

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Provided leadership in the successful legal challenges against New Jersey for discriminatory behavior affecting FERC jurisdictional capacity auctions, resulting in a decision by the U.S. Circuit Court of Appeals for the Third Circuit striking New Jersey’s action as being in violation of U.S. law. Petitions for certiorari were filed with the U.S. Supreme Court, asking for review of the Third Circuit’s decision. In October 2015, the U.S. Supreme Court granted certiorari but has not scheduled the case for oral argument.

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Successfully advocated against proposed legislation in California requiring investor owned utilities to contract for 500 MW of new geothermal resources that would have discriminated against our existing geothermal fleet.

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Filed a brief with the D.C. Circuit supporting the EPA’s MATS rules which were upheld by the Court.

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Filed a brief with the U.S. Supreme Court supporting the EPA’s CSAPR rules which were upheld by the Court in a decision citing our brief.

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Filed a brief with the U.S. Supreme Court supporting the EPA’s GHG air permit rules which were upheld in part by the Court citing our brief in its opinion.

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Filed a brief with the D.C. Circuit supporting the EPA’s opposition to motions for stay of the Clean Power Plan; the D.C. Circuit denied the motions.

5.

Focus on Enhancing Shareholder Value  — We continue to make significant progress to deliver financially disciplined growth, to enhance shareholder value through disciplined capital allocation including the return of capital to shareholders and to manage the balance sheet for future growth and success. We are committed to remaining financially disciplined in our capital allocation decisions. The year ended December 31, 2015 was marked by the following accomplishments:

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We continued to return capital to our shareholders in the form of share repurchases, having cumulatively repurchased approximately $2.8 billion or 29% of our previously outstanding shares as of the filing of this Report.

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Specifically during 2015, we repurchased a total of 26.6 million shares of our outstanding common stock for approximately $ 529 million at an average price of $ 19.87 per share.

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

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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 22, 2019.

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In December 2015, 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.

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In December 2015, we entered into our 2023 First Lien Term Loan and will use the proceeds to fund a portion of the purchase price for the Granite Ridge Energy Center, to repay project and corporate debt and for general corporate purposes.

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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.

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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 million through June 27, 2018, reverting back to $1,520 million 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.

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First, we are a provider of power to utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial and residential customers. Effective after the October 1, 2015 acquisition, we entered the retail market in scale through our retail subsidiary, Champion Energy. Our power sales occur in several different product categories including baseload (around the clock generation), intermediate (generation typically more expensive than baseload and utilized during higher demand periods to meet shifting demand needs), and peaking energy (most expensive variable cost and utilized during the highest demand periods), for which the latter is provided by some of our stand-alone peaking power plants/units and from our combined-cycle power plants by using technologies such as steam injection or duct firing additional burners in the heat recovery steam generators. Many of our units have operated more frequently as baseload units at times when low natural gas prices have driven their production costs below those of some competing coal-fired units. We also sell “full requirements” electricity for wholesale and retail customers, whereby we utilize our power plants as well as market purchases to serve the total electricity demand of the customer even as it varies across time.

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Second, we provide capacity for sale to utilities, independent electric system operators and retail power providers. In various markets, retail power providers (or independent electric system operators on their behalf) are required to demonstrate adequate resources to meet their power sales commitments. To meet this obligation, they procure a market product known as capacity from power plant owners or resellers. Most electricity market administrators have acknowledged that an energy only market does not provide sufficient revenues to enable existing merchant generators to recover all of their costs or to encourage the construction of new power plants. Capacity auctions have been implemented in the Northeast, Mid-Atlantic and certain Midwest regional markets to address this issue. California has a bilateral capacity program. Texas does not presently have a capacity market or a requirement for retailers to ensure adequate resources.

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Third, we sell RECs from our Geysers Assets in northern California, as well as from our small solar power plant in New Jersey. California has an RPS that requires load serving entities to have RECs for a certain percentage of their demand for the purpose of guaranteeing a certain level of renewable generation in the state or in neighboring areas. Because geothermal is a renewable source of energy, we receive a REC for each MWh we produce and are able to sell our RECs to load serving entities. New Jersey has a solar specific RPS which enables us to sell RECs from a 4 MW photovoltaic solar generation facility located in Vineland, New Jersey.

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Fourth, our cogeneration power plants produce steam, in addition to electricity, for sale to industrial customers for use in their manufacturing processes or heating, ventilation and air conditioning operations.

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Fifth, we provide ancillary service products to wholesale power markets. These products include the right for the purchaser to call on our generation to provide flexibility to the market and support operation of the electric grid. For example, we are sometimes paid to reserve a portion of capacity at some of our power plants that could be deployed quickly should there be an unexpected increase in load or to assure reliability due to fluctuations in the supply of power from variable renewable resources such as wind and solar generation. These ramping characteristics are becoming increasingly necessary in markets where intermittent renewables have large penetrations.

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Economic pressures continue to increase for coal-fired power generation as state and federal agencies enact environmental regulations to reduce air emissions of certain pollutants such as SO 2 , NO X , GHG, Hg and acid gases, restrict the use of once-through cooling, and provide for stricter standards for managing coal combustion residuals. In October 2015, the EPA promulgated the Clean Power Plan which requires future reductions in GHG emissions from existing power plants of 32% from 2005 levels by 2030. We anticipate that older, less efficient fossil-fuel power plants that emit much higher amounts of GHG, SO 2 , NO X , Hg and acid gases, which operate nationwide, but more prominently in the eastern U.S., will be negatively impacted by current and future air emissions, water and waste regulations and legislation both at the state and federal levels which will require many coal-fired power plants to install expensive air pollution controls or reduce or discontinue operations. As a result, any retirements or curtailments could enhance our growth opportunities through greater utilization of our existing power plants and development of new power plants. The estimated capacity for fossil-fueled plants older than 50 years and the total estimated capacity for fossil-fueled plants by NERC region are as follows:

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An increase in power generated from renewable sources could lead to an increased need for flexible power that many of our power plants provide to protect the reliability of the grid and premium compensation for that flexibility; however, risks also exist that renewables have the ability to lower overall wholesale power prices which could negatively impact us. Significant economic and reliability concerns for renewable generation have been raised, but we expect that renewable market penetration will continue, assisted by state-level renewable portfolio standards and federal tax incentives. The Consolidated Appropriations Act which extended the production tax credit for wind through the end of 2016 with gradual decreases thereafter until the tax credit expires completely in 2019 and extended the 30% investment tax credit for solar through the end of 2019 with gradual decreases through 2021 after which the investment tax credit declines to 10% was enacted in December 2015. In October 2015, the EPA promulgated the Clean Power Plan which requires future reductions in GHG emissions from existing power plants and provides flexibility in meeting the emissions reduction requirements including adding renewable generation. Increased renewable penetration has a particularly negative impact on inflexible baseload units and may lead to retirement of additional baseload units, which would benefit us; however, our energy margin may also decrease due to lower market clearing prices. To the extent market structures evolve to appropriately compensate units for providing flexible capacity to ensure reliability, our capacity revenue may increase.

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One small but growing source of competing renewable generation in some of our regional markets (primarily California) is customer-sited (primarily rooftop) solar generation. Levelized costs for solar installation have fallen significantly over the past several years, aided by federal tax subsidies and other local incentives, and are now in some regions lower than customer retail electric rates. To the extent on-site solar generation is compensated at the full retail rate (an increasingly controversial policy known as “net energy metering”), rooftop solar installations may continue to grow. Should net energy metered solar installations remain capped at relatively low levels of penetration or net energy metering policies be weakened (by rate structure reforms that charge customers fixed amounts regardless of the level of electricity consumed, thus lowering the variable portion of the rates), rooftop solar growth might diminish. Absent incentives and supportive policies, rooftop solar is currently generally not competitive with wholesale power.

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The regulators in our core markets remain committed to the competitive wholesale power model, particularly in ERCOT, PJM and ISO-NE where they continue to focus on market design and rules to assure the long-term viability of competition and the benefits to customers that justify competition.

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Utilities are increasingly focused on demand side management – managing the level and timing of power usage through load curtailment, dispatching generators located at commercial or industrial sites, and “smart grid” technologies that may improve the efficiencies, dispatch usage and reliability of electric grids. Scrutiny of demand side resources has increased recently as system operators evaluate their reliability (especially at high levels of penetration) and environmental authorities deal with the implications of relying on smaller, less environmentally efficient generation sources during periods of peak demand when air quality is already challenged.

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Environmental permitting requirements for new power plants, transmission lines and pipelines continue to increase in stringency and complexity, resulting in prolonged, expensive development cycles and high capital investments.

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number of market participants, both in terms of physical presence as well as contribution toward financial market liquidity;

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amount of generation capacity available in the market, including solar and wind capacity;

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fluctuations in power supply due to planned and unplanned outages of generators;

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cost of fuel, which could be impacted by the efficiency of generation technology and fluctuations in fuel supply or interruptions in natural gas transportation;

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relative ease or difficulty of developing, permitting and constructing new power plants;

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achieve and maintain a lower cost of production, primarily by maintaining unit availability, efficiency and production cost management;