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HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE: CPN): Summary of Second Quarter 2017 Financial Results (in millions): Reaffirming 2017 Guidance (in millions): Recent Achievements: Power and Commercial Operations:— Generated more than 22 million MWh3 in the second quarter of 2017— Delivered strong fleetwide starting reliability: 97.7% Portfolio Management:— Returned our Delta Energy Center to service in simple-cycle steam bypass configuration in June 2017; plan to return the unit to full combined-cycle configuration in fourth quarter of 2017— Negotiating Reliability Must Run contracts with CAISO for two natural gas-fired peaking power plants in California Balance Sheet Management:— As part of our $2.7 billion plan to delever and reduce interest expense, we have paid down approximately $294 million of debt (net) through the second quarter of 2017 out of $850 million paydown planned for 2017 Strategy:— Board of Directors and management in discussions regarding a potential sale of Calpine Calpine Corporation (NYSE:CPN) today reported Net Loss1 of $216 million, or $0.61 per diluted share, for the second quarter of 2017 compared to $29 million, or $0.08 per diluted share, in the prior year period. The period-over-period increase in Net Loss was primarily due to higher income tax expense in the current year in jurisdictions where we do not have net operating losses, an unfavorable variance in mark-to-market gain/loss, net, and increases in plant operating expense and depreciation and amortization expense. Cash provided by operating activities for the second quarter of 2017 was $152 million compared to $94 million in the prior year. The increase in cash provided by operating activities in the second quarter of 2017 was primarily due to a decrease in working capital employed resulting from the period-over-period change in net margining requirements associated with our commodity hedging activity, partially offset by a decrease in income from operations, adjusted for non-cash items. Adjusted EBITDA2 for the second quarter of 2017 was $419 million compared to $452 million in the prior year period. The decrease in Adjusted EBITDA was primarily due to lower Commodity Margin2, largely driven by a $40 million natural gas transportation billing credit received in the second quarter of 2016 that did not recur in the current year period, as well as higher plant operating expense, primarily due to our retail acquisitions. Adjusted Unlevered Free Cash Flow2 for the second quarter of 2017 was $263 million compared to $324 million in the prior year period, and Adjusted Free Cash Flow2 was $103 million compared to $158 million in the prior year period. The decreases in Adjusted Unlevered Free Cash Flow and Adjusted Free Cash Flow were primarily driven by lower Adjusted EBITDA, as previously discussed, and higher major maintenance expense and capital expenditures due to the timing of our outage schedule. Net loss for the first half of 2017 was $272 million, or $0.77 per diluted share, compared to $227 million, or $0.64 per diluted share in the prior year period. The period-over-period increase in Net Loss was primarily due to increases in plant operating expense and depreciation and amortization expense, and a decrease in commodity revenue, net of commodity expense partially offset by a favorable variance in mark-to-market gain/loss, net and a gain recorded in the first half of 2017 for the sale of Osprey Energy Center. Cash provided by operating activities for the first half of 2017 was $246 million compared to $125 million in the prior year period. The increase in cash provided by operating activities in the first half of 2017 was primarily due to a decrease in working capital employed resulting from the period-over-period change in net margining requirements associated with our commodity hedging activity, partially offset by a decrease in income from operations, adjusted for non-cash items. Adjusted EBITDA for the first half of 2017 was $745 million compared to $826 million in the prior year period. The decrease in Adjusted EBITDA was primarily due to lower Commodity Margin, largely driven by a gas transportation billing credit received in the second quarter of 2016 that did not recur in the current year period, and lower energy margins due to decreased contribution from wholesale hedges and weaker market conditions in the first quarter, as well as higher plant operating expense, primarily due to our retail acquisitions. Adjusted Unlevered Free Cash Flow for the first half of 2017 was $470 million compared to $590 million in the prior year period, and Adjusted Free Cash Flow was $146 million compared to $260 million in the prior year period. The decreases in Adjusted Unlevered Free Cash Flow and Adjusted Free Cash Flow were primarily driven by lower Adjusted EBITDA, as previously discussed, and higher major maintenance expense and capital expenditures due to the timing of our outage schedule. “I am pleased to report solid second quarter results, and I am proud of the hard work of our team and the operational excellence of our portfolio,” said Thad Hill, Calpine’s President and Chief Executive Officer. “During the second quarter, we saw stronger power prices for our Texas plants in the constrained Houston zone, and the PJM capacity auction yielded positive prints for our locationally advantaged Mid-Atlantic fleet. In California, our natural gas-fired assets were critical to grid reliability during the recent June heat wave, particularly during the daily evening peaks. “While these trends support what we believe to be a sound investment thesis for Calpine, the public equity markets have undervalued our business and underappreciated our strong track record of executing on our financial commitments and our stable cash flows. Early this spring, our Board of Directors decided to explore strategic alternatives for the company, seeking to enhance value for our shareholders. At this time, our Board, together with management and financial and legal advisors, are in discussions regarding a potential sale of Calpine." The Board plans to proceed in a timely manner but has not set a definitive timetable for completion of these discussions. There can be no assurance that these discussions will result in a transaction of any kind, or if a transaction is undertaken, as to terms or timing. Calpine does not intend to disclose developments or provide updates on the status of these discussions unless or until it is determined that further disclosure is appropriate or required by law. Notwithstanding these discussions, the Calpine team remains committed to operational excellence, customer focus and financial discipline. ________ 1 Reported as Net Loss attributable to Calpine on our Consolidated Condensed Statements of Operations. 2 Non-GAAP financial measure, see “Regulation G Reconciliations” for further details. 3 Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants. SUMMARY OF FINANCIAL PERFORMANCE Second Quarter Results Adjusted EBITDA for the second quarter of 2017 was $419 million compared to $452 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to a $10 million decrease in Commodity Margin and an $18 million increase in plant operating expense4, which was largely driven by net portfolio changes including our retail acquisitions. Excluding the benefit from a $40 million natural gas transportation billing credit received in the second quarter of 2016, Commodity Margin would have been up $30 million, primarily due to: + + higher on-peak spark spreads in the ERCOT Houston zone and in California during the hours in which we generated, partially offset by lower market spark spreads in the East and lower fleetwide generation, – – Adjusted Unlevered Free Cash Flow was $263 million in the second quarter of 2017 compared to $324 million in the prior year period. Adjusted Free Cash Flow was $103 million in the second quarter of 2017 compared to $158 million in the prior year period. Adjusted Unlevered Free Cash Flow and Adjusted Free Cash flow decreased primarily due to lower Adjusted EBITDA, as previously discussed, and higher major maintenance expense and capital expenditures due to outage timing. Year-to-Date Results Adjusted EBITDA for the first half of 2017 was $745 million compared to $826 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to a $32 million decrease in Commodity Margin and a $42 million increase in plant operating expense4, which was largely driven by net portfolio changes including our retail acquisitions. The decrease in Commodity Margin was primarily due to: – – – – + + higher market spark spreads in ERCOT, partially offset by lower market spark spreads in our East region. Adjusted Unlevered Free Cash Flow was $470 million for the first half of 2017 compared to $590 million in the prior year period. Adjusted Free Cash Flow was $146 million for the first half of 2017 compared to $260 million in the prior year period. Adjusted Unlevered Free Cash Flow and Adjusted Free Cash flow decreased primarily due to lower Adjusted EBITDA, as previously discussed, and higher major maintenance expense and capital expenditures due to outage timing. __________ 4 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 and six months ended June 30, 2017 and 2016. REGIONAL SEGMENT REVIEW OF RESULTS Table 1: Commodity Margin by Segment (in millions) West Region Second Quarter: Commodity Margin in our West segment decreased by $10 million in the second quarter of 2017 compared to the prior year period. Primary drivers were: – + + Year-to-Date: Commodity Margin in our West segment increased by $14 million in the first half of 2017 compared to the prior year period. Primary drivers were: + increased contribution from the expansion of our retail hedging activity following the acquisition of Calpine Energy Solutions in December 2016 and + – Texas Region Second Quarter: Commodity Margin in our Texas segment increased by $7 million in the second quarter of 2017 compared to the prior year period. Primary drivers were: + + – Year-to-Date: Commodity Margin in our Texas segment increased by $2 million in the first half of 2017 compared to the prior year period. Primary drivers were: + higher market spark spreads and + – – East Region Second Quarter: Commodity Margin in our East segment decreased $7 million in the second quarter of 2017 compared to the prior year period. Primary drivers were: – – – + Year-to-Date: Commodity Margin in our East segment decreased by $48 million in the first half of 2017 compared to the prior year period. Primary drivers were: – – – – + + LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES Table 2: Liquidity (in millions) ____________ (1) Includes $1 million and $16 million of margin deposits posted with us by our counterparties at June 30, 2017, and December 31, 2016, respectively. (2) Our ability to use availability under our Corporate Revolving Facility is unrestricted. (3) Our ability to use corporate cash and cash equivalents is unrestricted. Our $300 million CDHI letter of credit facility is restricted to support certain obligations under PPAs and power transmission and natural gas transportation agreements. Liquidity was approximately $1.8 billion as of June 30, 2017. Cash and cash equivalents decreased in the first half of 2017 primarily due to net repayments of debt, consistent with our announced plan to reduce leverage. Table 3: Cash Flow Activities (in millions) Cash provided by operating activities in the first half of 2017 was $246 million compared to $125 million in the prior year period. The year-over-year increase was primarily due to a decrease in working capital employed resulting from the period-over-period change in net margining requirements associated with our commodity hedging activity, partially offset by a decrease in income from operations, adjusted for non-cash items. Cash used in investing activities was $51 million during the first half of 2017 compared to $676 million in the prior year period. The decrease was primarily related to acquisitions, divestitures and capital expenditures. In the first quarter of 2017, we closed on the acquisition of North American Power for $111 million and closed on the sale of Osprey Energy Center, receiving net proceeds of $162 million. In the first quarter of 2016, we purchased Granite Ridge Energy Center for $526 million. There was also a year-over-year decrease of $36 million in capital expenditures, primarily due to lower expenditures on construction projects during the first half of 2017 as compared to 2016. Cash used in financing activities was $319 million during the first half of 2017 and primarily related to net repayment of debt in accordance with our deleveraging plan. Managing Our Balance Sheet We further optimized our capital structure during the first half of 2017, as follows: 2023 First Lien Notes: — As part of our commitment to reduce debt and interest expense, on March 6, 2017, we redeemed the remaining $453 million of our 7.875% First Lien Notes due in 2023 using cash on hand along with the proceeds from a new $400 million, three-year First Lien Term Loan priced at LIBOR + 1.75% per annum. We intend to repay the 2019 First Lien Term Loan in full by the end of 2018. This accelerates debt reduction and results in substantial annual interest savings of more than $20 million in the interim. 2017 First Lien Term Loan: — We repaid approximately $150 million of our 2017 First Lien Term Loan using cash on hand during the first quarter of 2017. Expanding Our Customer Sales Channels We continue to focus on getting closer to our customers through expansion of our retail platform, which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Energy Solutions in late 2016 and North American Power in early 2017. Our retail platform geographically and strategically complements our wholesale generation fleet by providing forward liquidity with sufficient margins. The combination of our wholesale origination and retail platform provides Calpine access to both direct and mass market sales channels. Our direct sales efforts aim to provide our larger customers with customized products, leveraging both our successful wholesale origination efforts and Calpine Energy Solutions’ presence among large commercial and industrial organizations to secure new contracts. Our mass market approach relies upon our expanded Champion Energy retail platform to serve the needs of both residential and smaller commercial and industrial customers across the country. We believe that our retail platform is strategically complete and are now focused on integrating it into our business and optimizing its financial performance. Acquisition of North American Power & Gas, LLC On January 17, 2017, we completed the purchase of North American Power for approximately $105 million, excluding working capital and other adjustments. North American Power is a growing retail energy supplier for homes and small businesses and is primarily concentrated in the Northeast U.S., where Calpine has a substantial power generation presence. Champion Energy also has a substantial retail sales footprint in the Northeast U.S. that is enhanced by the addition of North American Power, which has been integrated into our Champion Energy retail platform. With this acquisition, we now serve residential load in 63 utility service territories as compared to 51 in 2016. Portfolio Management East: Washington Parish: On April 21, 2017, we entered into an agreement with Entergy Louisiana (Entergy), a subsidiary of Entergy Corporation, to construct an approximately 360 MW natural gas-fired peaking power plant on a partially developed site that we own near Bogalusa, Louisiana. Within a short period of time subsequent to the plant commencing commercial operations and meeting certain performance objectives, Entergy will purchase the plant for a fixed payment, including a fair market return. Construction on the facility will not commence until 2019 with COD expected in early 2021. The agreement contains conditions precedent to effectiveness including, but not limited to, approval of the Louisiana Public Service Commission. We plan to fund the project with a construction loan that will be repaid upon receipt of sale proceeds. York 2 Energy Center: York 2 Energy Center is an 828 MW dual-fuel, combined-cycle project that is 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. Due to construction delays, we are now targeting COD in the first half of 2018. Osprey Energy Center: On January 3, 2017, we completed the sale of Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration. Texas: Clear Lake Power Plant: On February 1, 2017, we retired our 400 MW Clear Lake Power Plant due to a lack of adequate compensation in Texas. Built in 1985, Clear Lake utilized an older, less efficient technology. Guadalupe Peaking Energy Center: In April 2017, we canceled an agreement with Guadalupe Valley Electric Cooperative (GVEC) related to the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our existing Guadalupe Energy Center. In lieu of building the facility, we will now serve GVEC with 200 MW of generating capacity under a 10-year PPA beginning in June 2019. West: California Peakers: As a result of the pending expiration of a PPA in December 2017, we informed CAISO of our intent to suspend operations at four of our California peaking natural gas-fired power plants with capacity totaling 186 MW. CAISO has determined that two of these power plants, Yuba City and Feather River energy centers, are needed to continue reliable operation of the power grid. We are currently negotiating Reliability Must Run contracts for these two power plants. South Point Energy Center: As a result of the denial by the Nevada Public Utility Commission of the sale of South Point Energy Center to Nevada Power Company in February 2017, we terminated the corresponding asset sale agreement in the first quarter of 2017. We are currently assessing our options related to South Point Energy Center. OPERATIONS UPDATE Second Quarter Power Operations Achievements: Availability Performance:— Delivered strong fleetwide starting reliability: 97.7% Power Generation:— Generated more than 22 million MWh3— Four merchant plants achieved greater than 65% net capacity factor: Bosque, Garrison, Freestone and Pasadena 2017 Operating Event at our Delta Energy Center On January 29, 2017, we experienced an operating event at our Delta Energy Center that resulted in an emergency shutdown of the power plant and significant damage to the steam turbine and steam turbine generator. The unit returned to service in simple-cycle steam bypass configuration in June 2017, and our current plan is to return the unit to full combined-cycle configuration in the fourth quarter of 2017. We anticipate that insurance will cover a significant portion of our losses, after applicable deductibles. 2017 FINANCIAL OUTLOOK ____________ (1) Maintenance capital expenditures exclude major construction and development projects. (2) Includes commitment, letter of credit and other bank fees from consolidated and unconsolidated investments, net of capitalized interest and interest income. (3) Includes projected major maintenance expense of $275 million and maintenance capital expenditures of $160 million. As detailed above, today we are reaffirming our 2017 Adjusted EBITDA and Adjusted Free Cash Flow guidance ranges and are introducing guidance for Adjusted Unlevered Free Cash Flow. We expect Adjusted EBITDA of $1.8 billion to $1.95 billion, Adjusted Unlevered Free Cash Flow of $1.355 billion to $1.505 billion and Adjusted Free Cash Flow of $710 million to $860 million in 2017. INVESTOR CONFERENCE CALL AND WEBCAST We will host a conference call to discuss our financial and operating results for the second quarter on Friday, July 28, 2017, 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 45310747. A 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 45310747. Presentation materials to accompany the conference call will be posted on our website on July 28, 2017. ABOUT CALPINE Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources with operations in competitive power markets. Our fleet of 80 power plants in operation or under construction represents approximately 26,000 megawatts of generation capacity. Through wholesale power operations and our retail businesses Calpine Energy Solutions and Champion Energy, we serve customers in 25 states, Canada and Mexico. Our clean, efficient, modern and flexible fleet uses advanced technologies to generate power in a low-carbon and environmentally responsible manner. We are uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. Please visit www.calpine.com to learn more about how Calpine is creating power for a sustainable future. Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, has been filed with the Securities and Exchange Commission (SEC) and is available on the SEC’s website at www.sec.gov. FORWARD-LOOKING INFORMATION In addition to historical information, this release contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this release. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. We believe that the forward-looking statements are based upon reasonable assumptions and expectations. However, 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 wholesale and retail markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate; Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our Senior Unsecured Notes, First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, 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 from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, and other risks associated with marketing and selling power in the evolving energy markets; Structural changes in the supply and demand of power resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies); The expiration or early termination of our PPAs and the related results on revenues; Future capacity revenue may not occur at expected levels; Natural disasters, such as hurricanes, earthquakes, droughts, wildfires and floods, acts of terrorism or cyber-attacks that may affect our power plants or the markets our power plants or retail operations serve and our corporate offices; Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power; Our ability to manage our counterparty and customer exposure and credit risk, including our commodity positions; Our ability to attract, motivate and retain key employees; Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and Other risks identified in this press release, in our Annual Report on Form 10-K for the year ended December 31, 2016, and in other reports filed by us with the SEC. Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise. (51 __________ (1) Includes amortization recorded in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts. (2) On April 3, 2017, we completed the purchase of the King City Cogeneration Plant lease in exchange for a three-year promissory note with a discounted value of $57 million. We recorded a net increase to property, plant and equipment, net on our Consolidated Condensed Balance Sheet of $15 million due to the increased value of the promissory note as compared to the carrying value of the lease. REGULATION G RECONCILIATIONS In addition to disclosing financial results in accordance with U.S. GAAP, the accompanying second quarter 2017 earnings release contains non-GAAP financial measures. Commodity Margin, Adjusted Free Cash Flow, Adjusted Unlevered Free Cash Flow and Adjusted EBITDA are non-GAAP financial measures that we use as measures of our performance and liquidity. These non-GAAP measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance and liquidity, and the financial results calculated in accordance with U.S. GAAP and reconciliations from these results should be carefully evaluated. Commodity Margin includes revenues recognized on our wholesale and retail power sales activity, electric capacity sales, renewable energy credit sales, steam sales, realized settlements associated with our marketing, hedging, optimization and trading activity, fuel and purchased energy expenses, commodity transmission and transportation expenses and environmental compliance expenses. 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 is not a measure calculated in accordance with U.S. GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with U.S. GAAP. 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 Free Cash Flow represents cash flows from operating activities including the effects of maintenance capital expenditures, adjustments to reflect the Adjusted Free Cash Flow from unconsolidated investments and to exclude the noncontrolling interest and other miscellaneous adjustments such as the effect of changes in working capital. Adjusted Unlevered Free Cash Flow is calculated on the same basis as Adjusted Free Cash Flow but excludes the effect of cash interest, net, and operating lease payments, thus capturing the performance of our business independent of its capital structure. Adjusted Free Cash Flow and Adjusted Unlevered Free Cash Flow are presented because we believe they are useful measures of liquidity to assist in comparing financial results from period to period on a consistent basis and to readily view operating trends, as measures 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 results. Adjusted Free Cash Flow and Adjusted Unlevered Free Cash Flow are liquidity measures and are not intended to represent cash flows from operations, the most directly comparable U.S. GAAP measure, and are not necessarily comparable to similarly titled measures reported by other companies. Adjusted EBITDA represents net loss attributable to Calpine before net (income) attributable to the noncontrolling interest, interest, taxes, depreciation and amortization, and is also adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase, modification or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any 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. 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. Adjusted EBITDA is not intended to represent 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 are presenting Adjusted EBITDA along with a reconciliation to Adjusted Unlevered Free Cash Flow to demonstrate the relationship between our traditional performance measure, Adjusted EBITDA, and our new liquidity measure, Adjusted Unlevered Free Cash Flow. Commodity Margin Reconciliation The following tables reconcile income (loss) from operations to Commodity Margin for the three and six months ended June 30, 2017 and 2016 (in millions): _________ (1) Includes $(24) million and $(20) million of lease levelization and $44 million and $27 million of amortization expense for the three months ended June 30, 2017 and 2016, respectively. (2) Includes $(46) million and $(42) million of lease levelization and $104 million and $54 million of amortization expense for the six months ended June 30, 2017 and 2016, respectively. Consolidated Adjusted EBITDA Reconciliation In the following table, we have reconciled our Adjusted EBITDA to our Commodity Margin, both of which are non-GAAP measures, for the three and six months ended June 30, 2017 and 2016. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. Amounts below are shown exclusive of the noncontrolling interest (in millions): _________ (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. In the following table, we have reconciled our net loss attributable to Calpine to Adjusted EBITDA for the three and six months ended June 30, 2017 and 2016, as reported under U.S. GAAP (in millions). We also reconciled Adjusted EBITDA to Adjusted Unlevered Free Cash Flow to demonstrate the relationship between our traditional performance measure, Adjusted EBITDA, and our new liquidity measure, Adjusted Unlevered Free Cash Flow. ____________ (1) Excludes depreciation and amortization expense attributable to the non-controlling interest. (2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for each of the three and six months ended June 30, 2017 and 2016. (3) Includes $86 million and $151 million in major maintenance expense for the three and six months ended June 30, 2017, respectively, and $59 million and $109 million in maintenance capital expenditures for the three and six months ended June 30, 2017, respectively. Includes $81 million and $146 million in major maintenance expenditures for the three and six months ended June 30, 2016, respectively, and $41 million and $81 million in maintenance capital expenditures for the three and six months ended June 30, 2016, respectively. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (5) Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance. Adjusted Unlevered Free Cash Flow Reconciliation In the following table, we have reconciled our cash flows from operating activities to our Adjusted Unlevered Free Cash Flow for the three and six months ended June 30, 2017 and 2016 (in millions). _________ (1) Maintenance capital expenditures exclude major construction and development projects. (2) Adjustment excludes $3 million and $35 million in amortization of acquired derivatives contracts for three months ended June 30, 2017 and 2016, respectively, and $(10) million and $45 million in amortization of acquired derivatives contracts for the six months ended June 30, 2017 and 2016, respectively. (3) Other primarily represents miscellaneous items excluded from Adjusted Free Cash Flow that are included in cash flow from operations. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (5) Includes $86 million and $151 million in major maintenance expense for the three and six months ended June 30, 2017, respectively, and $59 million and $109 million in maintenance capital expenditures for the three and six months ended June 30, 2017, respectively. Includes $81 million and $146 million in major maintenance expense for the three and six months ended June 30, 2016, respectively, and $41 million and $81 million in maintenance capital expenditures for the three and six months ended June 30, 2016, respectively. Adjusted Unlevered Free Cash Flow Reconciliation for Guidance (in millions) ____________ (1) Maintenance 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 projected major maintenance expense of $275 million and maintenance capital expenditures of $160 million. OPERATING PERFORMANCE METRICS The table below shows the operating performance metrics for the periods presented: ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us. (2) Generation, average availability and steam adjusted heat rate exclude power plants and units that are inactive.

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE: CPN): Summary of First Quarter 2017 Financial Results (in millions): NM Reaffirming 2017 Full Year Guidance (in millions): Recent Achievements: Power and Commercial Operations:— Generated more than 21 million MWh3 in the first quarter of 2017— Delivered strong fleetwide starting reliability: 97.5% Portfolio Management:— Signed a 10-year PPA with Guadalupe Valley Electric Cooperative for 200 MW beginning in 2019, concurrently canceling construction of a 418 MW natural gas-fired peaking power plant in Texas— Retired 400 MW Clear Lake Power Plant due to lack of adequate compensation in Texas— Monetizing legacy site through an agreement to construct and sell an approximately 360 MW natural gas-fired peaking power plant to Entergy Louisiana after commercial operation, expected in early 2021— Negotiating Reliability Must Run contracts with CAISO for two natural gas-fired peakers in California— Closed on the sale of Osprey Energy Center to Duke Energy for $166 million4— Acquired growing residential retail provider North American Power for approximately $105 million4, representing an attractively priced portfolio addition to our Champion Energy retail platform Balance Sheet Management:— As part of our $2.7 billion plan to delever and reduce interest expense, we paid down approximately $233 million of debt (net) in the first quarter of 2017 out of $850 million paydown planned for 2017 Calpine Corporation (NYSE: CPN) today reported Net Loss1 of $56 million, or $0.16 per diluted share, for the first quarter of 2017 compared to $198 million, or $0.56 per diluted share, in the prior year period. The period-over-period decrease in Net Loss was primarily due to the favorable variance in our net mark-to-market activities driven by changes in forward commodity prices and the positive effect of our retail hedging activities. Cash provided by operating activities for the first quarter of 2017 was $94 million compared to $31 million in the prior year. The increase in cash provided by operating activities was primarily due to a decrease in working capital employed resulting from the period over period change in net margining requirements associated with our commodity hedging activity, partially offset by a decrease in income from operations, adjusted for non-cash items. Adjusted EBITDA2 for the first quarter was $326 million compared to $374 million in the prior year period, and Adjusted Free Cash Flow2 was $43 million compared to $102 million in the prior year period. The decreases in Adjusted EBITDA and Adjusted Free Cash Flow were primarily due to lower Commodity Margin2, largely driven by lower energy margins due to decreased contribution from wholesale hedges and weaker market conditions, lower regulatory capacity revenue in our East segment and the sales of Mankato Power Plant in October 2016 and Osprey Energy Center in January 2017. These changes were partially offset by our retail acquisitions of Calpine Energy Solutions in December 2016 and North American Power in January 2017. Net Loss, As Adjusted2, for the first quarter of 2017 was $114 million compared to $104 million in the prior year period. The increase in Net Loss, As Adjusted, was primarily due to lower Commodity Margin, as previously discussed, as well as increases in plant operating expense and depreciation and amortization expense primarily due to our retail acquisitions, partially offset by a higher income tax benefit resulting primarily from changes in estimated tax benefits and a favorable adjustment to our reserve for uncertain tax positions. “This year’s first quarter results reflect our ability to meet our financial commitments despite a very mild winter in Texas and the East and above-normal hydroelectric generation in the West,” said Thad Hill, Calpine’s President and Chief Executive Officer. “We are reaffirming our full year guidance range of $1.8 to $1.95 billion of Adjusted EBITDA, given upside in the back half of the year from our retail acquisitions and higher regulatory capacity payments in the East. “During the quarter, we began executing on our deleveraging plan while continuing to make progress on controlling costs and integrating our retail platform. We have completed $233 million of our full year target of $850 million in debt reduction, and we are on track to complete our $2.7 billion of planned debt paydown by the end of 2019. “We also continued our relentless focus on managing our portfolio for long-term value. Specifically, I am pleased to announce three great examples of how our customer-focused efforts helped us find mutually beneficial solutions. First, we have signed a 10-year PPA with Guadalupe Valley Electric Cooperative to supply 200 MW of power from our existing Texas fleet, replacing our prior agreement to construct a new 418 MW peaking power plant. Secondly, we are announcing the monetization of a legacy development site in Louisiana, where we have entered into a construction and sale agreement with Entergy Louisiana for a natural gas-fired peaking power plant. Finally, we completed the sale of our Osprey Energy Center to Duke Energy Florida. “We also took further action to economically optimize our portfolio by filing to retire four of our natural gas-fired peakers in California at the beginning of 2018 when their contracts expire. The California Independent System Operator has since declared that two of the units are required for reliability, and we are currently negotiating Reliability Must Run contracts that will appropriately compensate us for providing critical reliability to the grid. “Finally, we have been advocating for competitive power markets, including opposing out-of-market nuclear bailouts that are being debated or implemented in multiple states. We fundamentally disagree with adding more subsidies into functioning wholesale markets and are actively challenging them at the state level and in the courts. Regardless of those outcomes, we are optimistic that independent system operators and the new FERC will move through tariff reform to protect the integrity of their markets from state intervention. Competitive wholesale power markets need to provide non-discriminatory forward price signals that result in market-driven solutions that ensure reliable power. Calpine’s clean, modern and flexible fleet is integral to maintaining reliability in each of our wholesale power markets.” ________ 1 Reported as Net Loss attributable to Calpine on our Consolidated Condensed Statements of Operations. 2 Non-GAAP financial measure, see “Regulation G Reconciliations” for further details. 3 Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants. 4 Excluding working capital and other adjustments. SUMMARY OF FINANCIAL PERFORMANCE First Quarter Results Adjusted EBITDA for the first quarter of 2017 was $326 million compared to $374 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to a $22 million decrease in Commodity Margin and $24 million increase in plant operating expense5, which was largely driven by net portfolio changes including our retail acquisitions, as previously discussed. The decrease in Commodity Margin was primarily due to: Adjusted Free Cash Flow was $43 million in the first quarter of 2017 compared to $102 million in the prior year period. Adjusted Free Cash Flow decreased due to lower Adjusted EBITDA, as previously discussed, and higher major maintenance capital expenditures primarily due to improvements of our Geysers assets. __________ 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 ended March 31, 2017 and 2016. REGIONAL SEGMENT REVIEW OF RESULTS Table 1: Commodity Margin by Segment (in millions) West Region First Quarter: Commodity Margin in our West segment increased by $24 million in the first quarter of 2017 compared to the prior year period. Primary drivers were: Texas Region First Quarter: Commodity Margin in our Texas segment decreased by $5 million in the first quarter of 2017 compared to the prior year period. Primary drivers were: East Region First Quarter: Commodity Margin in our East segment decreased $41 million in the first quarter of 2017 compared to the prior year period. Primary drivers were: LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES Table 2: Liquidity (in millions) ____________ (1) Includes $9 million and $16 million of margin deposits posted with us by our counterparties at March 31, 2017, and December 31, 2016, respectively. (2) Our ability to use availability under our Corporate Revolving Facility is unrestricted. (3) Our ability to use corporate cash and cash equivalents is unrestricted. Our $300 million CDHI letter of credit facility is restricted to support certain obligations under PPAs and power transmission and natural gas transportation agreements. Liquidity was approximately $1.8 billion as of March 31, 2017. Cash and cash equivalents decreased in the first quarter of 2017 primarily due to the acquisition of North American Power, capital expenditures on construction projects and outages, and net repayments of debt, partially offset by cash provided by the sale of Osprey Energy Center, as well as from operating activities. Table 3: Cash Flow Activities (in millions) Cash provided by operating activities in the first quarter of 2017 was $94 million compared to $31 million in the prior year period, as previously discussed. Cash used in investing activities was $13 million during the first quarter of 2017 compared to $611 million in the prior year period. The decrease was primarily related to acquisitions, divestitures and capital expenditures. In the first quarter of 2017, we closed on the acquisition of North American Power for $111 million and closed on the sale of Osprey Energy Center, receiving net proceeds of $162 million. In the first quarter of 2016, we purchased Granite Ridge Energy Center for $527 million. There was also a decrease of $42 million for capital expenditures primarily due to lower expenditures on construction projects and outages during the first quarter of 2017 as compared to 2016. Cash used in financing activities was $256 million during the first quarter of 2017 and primarily related to net repayment of debt in accordance with our deleveraging plan. CAPITAL ALLOCATION Our capital allocation philosophy seeks to maximize levered cash returns to equity while maintaining a strong balance sheet. We seek to enhance shareholder value through a diverse and balanced capital allocation approach that includes portfolio management, organic or acquisitive growth, returning capital to shareholders and debt reduction. The mix of this activity shifts over time given the external market environment and the opportunity set. In the current environment, we believe that paying down debt and strengthening our balance sheet is a high-return investment for our shareholders. We also consider the repurchases of our own shares of common stock as an attractive investment opportunity, and we utilize the expected returns from this investment as the benchmark against which we evaluate all other capital allocation decisions. We believe this philosophy closely aligns our objectives with those of our shareholders. Managing Our Balance Sheet We further optimized our capital structure during the quarter ended March 31, 2017, as follows: 2023 First Lien Notes: — As part of our commitment to reduce debt and interest expense, on March 6, 2017, we redeemed the remaining $453 million of our 7.875% First Lien Notes due in 2023 using cash on hand along with the proceeds from a new $400 million, three-year First Lien Term Loan priced at LIBOR + 1.75% per annum. We intend to repay the 2019 First Lien Term Loan in full by the end of 2018. This accelerates debt reduction and results in substantial annual interest savings of more than $20 million in the interim. 2017 First Lien Term Loan: — We repaid approximately $150 million of our 2017 First Lien Term Loan using cash on hand during the first quarter of 2017. Expanding Our Customer Sales Channels We continue to focus on getting closer to our customers through expansion of our retail platform, which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Energy Solutions in late 2016 and North American Power in early 2017. Our retail platform geographically and strategically complements our wholesale generation fleet by providing forward liquidity with sufficient margins. The combination of our wholesale origination and retail platform provides Calpine access to both direct and mass market sales channels. Our direct sales efforts aim to provide our larger customers with customized products, leveraging both our successful wholesale origination efforts and Calpine Energy Solutions’ presence among large commercial and industrial organizations to secure new contracts. Our mass market approach relies upon our expanded Champion Energy retail platform to serve the needs of both residential and smaller commercial and industrial customers across the country. We believe that our retail platform is strategically complete and are now focused on integrating it into our business and optimizing its financial performance. Acquisition of North American Power & Gas, LLC On January 17, 2017, we completed the purchase of North American Power for approximately $105 million, excluding working capital and other adjustments. North American Power is a growing retail energy supplier for homes and small businesses and is primarily concentrated in the Northeast U.S., where Calpine has a substantial power generation presence and where Champion Energy has a substantial retail sales footprint that is enhanced by the addition of North American Power, which has been integrated into our Champion Energy retail platform. With this acquisition, we now serve residential load in 63 utility service territories as compared to 51 in 2016. Portfolio Management East: Washington Parish: On April 21, 2017, we entered into an agreement with Entergy Louisiana (Entergy), a subsidiary of Entergy Corporation, to construct an approximately 360 MW natural gas-fired peaking power plant on a partially developed site that we own near Bogalusa, Louisiana. Within a short period of time subsequent to the plant commencing commercial operations and meeting certain performance objectives, Entergy will purchase the plant for a fixed payment, including a fair market return. Construction on the facility will not commence until 2019 with COD expected in early 2021. The agreement contains conditions precedent to effectiveness including, but not limited to, approval of the Louisiana Public Service Commission. We plan to fund the project with a construction loan that will be repaid upon receipt of sale proceeds. York 2 Energy Center: York 2 Energy Center is an 828 MW dual-fuel, combined-cycle project that is 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 is under construction, and the initial 760 MW of capacity cleared PJM’s last three base residual auctions with the 68 MW of incremental capacity clearing the last two base residual auctions. Due to construction delays, we are now targeting COD in early 2018. Osprey Energy Center: On January 3, 2017, we completed the sale of Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration. Texas: Clear Lake Power Plant: On February 1, 2017, we retired our 400 MW Clear Lake Power Plant due to a lack of adequate compensation in Texas. Built in 1985, Clear Lake utilized an older, less efficient technology. Guadalupe Peaking Energy Center: In April 2017, we canceled an agreement with Guadalupe Valley Electric Cooperative (GVEC) related to the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our existing Guadalupe Energy Center. In lieu of building the facility, we will now serve GVEC with 200 MW of generating capacity under a 10-year PPA beginning in June 2019. West: California Peakers: As a result of the pending expiration of a PPA in December 2017, we informed CAISO of our intent to suspend operations at four of our California peaking natural gas-fired power plants with capacity totaling 186 MW. CAISO has determined that two of these power plants, Yuba City and Feather River energy centers, are needed to continue reliable operation of the power grid. We are currently negotiating Reliability Must Run contracts for these two power plants. South Point Energy Center: As a result of the denial by the Nevada Public Utility Commission of the sale of South Point Energy Center to Nevada Power Company in February 2017, we terminated the corresponding asset sale agreement in the first quarter of 2017. We are currently assessing our options related to South Point Energy Center. OPERATIONS UPDATE First Quarter Power Operations Achievements: Availability Performance:— Delivered strong fleetwide starting reliability: 97.5% Power Generation:— Generated more than 21 million MWh3— Texas fleet: Record low first quarter forced outage factor— Westbrook Energy Center: 100% starting reliability across 215 starts 2017 Operating Event at our Delta Energy Center On January 29, 2017, we experienced an operating event at our Delta Energy Center that resulted in an emergency shutdown of the power plant and significant damage to the steam turbine and steam turbine generator. Our current plan is to return the unit to service in simple-cycle steam bypass configuration in June 2017 and full combined-cycle configuration in the fourth quarter of 2017. We anticipate that insurance will cover a significant portion of our losses, after applicable deductibles. 2017 FINANCIAL OUTLOOK — ____________ (1) Includes projected major maintenance expense of $315 million and maintenance capital expenditures of $120 million in 2017. Capital expenditures exclude major construction and development projects. (2) Includes commitment, letter of credit and other fees from consolidated and unconsolidated investments, net of capitalized interest and interest income. (3) Amount includes $200 million of recurring amortization, as well as the $550 million repayment of the 2017 First Lien Term Loan, a portion of the $453 million of our callable 7 7/8% 2023 Senior Secured Notes and the buyout of the Pasadena lessor interest. As detailed above, today we are reaffirming our 2017 guidance range. We expect Adjusted EBITDA of $1.8 billion to $1.95 billion and Adjusted Free Cash Flow of $710 million to $860 million. We expect to invest $220 million in our ongoing growth-related projects during 2017, primarily the construction of York 2 Energy Center. INVESTOR CONFERENCE CALL AND WEBCAST We will host a conference call to discuss our financial and operating results for the first quarter on Friday, April 28, 2017, 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 44658283. A 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 44658283. Presentation materials to accompany the conference call will be posted on our website on April 28, 2017. ABOUT CALPINE Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources with operations in competitive power markets. Our fleet of 80 power plants in operation or under construction represents approximately 26,000 megawatts of generation capacity. Through wholesale power operations and our retail businesses Calpine Energy Solutions and Champion Energy, we serve customers in 25 states, Canada and Mexico. Our clean, efficient, modern and flexible fleet uses advanced technologies to generate power in a low-carbon and environmentally responsible manner. We are uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. Please visit www.calpine.com to learn more about how Calpine is creating power for a sustainable future. Calpine’s Annual Report on Form 10-Q for the quarter ended March 31, 2017, has been filed with the Securities and Exchange Commission (SEC) and is available on the SEC’s website at www.sec.gov. FORWARD-LOOKING INFORMATION In addition to historical information, this release contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this release. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. We believe that the forward-looking statements are based upon reasonable assumptions and expectations. However, you are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to: Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability and extent to which we hedge risks; Laws, regulations and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate; Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our Senior Unsecured Notes, First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, 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 from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, and other risks associated with marketing and selling power in the evolving energy markets; Structural changes in the supply and demand of power resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies); The expiration or early termination of our PPAs and the related results on revenues; Future capacity revenue may not occur at expected levels; Natural disasters, such as hurricanes, earthquakes, droughts, wildfires and floods, acts of terrorism or cyber-attacks that may affect our power plants or the markets our power plants or retail operations serve and our corporate headquarters; Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power; Our ability to manage our counterparty and customer exposure and credit risk, including our commodity positions; Our ability to attract, motivate and retain key employees; Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and Other risks identified in this press release, in our Annual Report on Form 10-K for the year ended December 31, 2016, and in other reports filed by us with the SEC. Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise. Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) (in millions) (13 (611 396 — __________ (1) Includes amortization included in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts. REGULATION G RECONCILIATIONS In addition to disclosing financial results in accordance with U.S. GAAP, the accompanying first quarter 2017 earnings release contains non-GAAP financial measures. Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These non-GAAP measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance, and the financial results calculated in accordance with U.S. GAAP and reconciliations from these results should be carefully evaluated. Net Loss, As Adjusted, represents net loss attributable to Calpine, adjusted for certain non-cash and non-recurring items, including mark-to-market (gain) loss on derivatives, debt modification and extinguishment costs and other adjustments. Net 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 Loss, As Adjusted, is not intended to represent net income (loss), the most comparable U.S. GAAP measure, as an indicator of operating performance, and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, revenue from renewable energy credits, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin is not a measure calculated in accordance with U.S. GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with U.S. GAAP. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Adjusted EBITDA represents net loss attributable to Calpine before net (income) 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, modification or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any 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 (loss) 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 liquidity measure and is not intended to represent cash flows from operating activities, the most directly comparable U.S. GAAP measure, and is not necessarily comparable to similarly titled measures reported by other companies. Net Loss, As Adjusted Reconciliation The following table reconciles our Net Loss, As Adjusted, to its U.S. GAAP results for the three months ended March 31, 2017 and 2016 (in millions): __________ (1) Assumes 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 include hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. Commodity Margin Reconciliation The following tables reconcile Income (loss) from operations to Commodity Margin for the three months ended March 31, 2017 and 2016 (in millions): $ 88 $ 221 $ (114 ) $ — (6 ) (110 ) (6 ) $ 153 $ — _________ (1) Includes $(22) million and $(22) million of lease levelization and $60 million and $27 million of amortization expense for the three months ended March 31, 2017 and 2016, respectively. Consolidated Adjusted EBITDA Reconciliation In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our net income attributable to Calpine for the three months ended March 31, 2017 and 2016, as reported under U.S. GAAP (in millions): _________ (1) Excludes depreciation and amortization expense attributable to the non-controlling interest. (2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for each of the three months ended March 31, 2017 and 2016. (3) Includes $65 million and $65 million in major maintenance expense for the three months ended March 31, 2017 and 2016, respectively, and $50 million and $40 million in maintenance capital expenditures for the three months ended March 31, 2017 and 2016, respectively. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (5) 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 ended March 31, 2017 and 2016. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. Amounts below are shown exclusive of the noncontrolling interest (in millions): _________ (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 Free Cash Flow Reconciliation In the following table, we have reconciled our cash flows from operating activities to our Adjusted Free Cash Flow for the three months ended March 31, 2017 and 2016 (in millions): _________ (1) Adjustment excludes $(13) million and $10 million in amortization of acquired derivatives contracts for the three months ended March 31, 2017 and 2016, respectively. (2) Adjustment primarily represents miscellaneous items excluded from Adjusted EBITDA that are included in cash flow from operations. Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance (in millions) _________ (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 $315 million and maintenance capital expenditures of $120 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: ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us. (2) Generation, average availability and steam adjusted heat rate exclude power plants and units that are inactive.

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE: CPN): Summary of 2016 Financial Results (in millions): NM NM NM NM Reaffirming 2017 Full Year Guidance (in millions): Recent Achievements: Power and Commercial Operations:— Achieved new Calpine record and top quartile3 safety metric: 0.55 total recordable incident rate in 2016— Generated approximately 110 million MWh4 in 2016— Delivered strong fleetwide starting reliability: 97.9% Portfolio Management:— Announced and closed accretive acquisition of leading commercial and industrial retail electricity provider Calpine Energy Solutions, formerly Noble Americas Energy Solutions, LLC— Acquired growing residential retail provider North American Power for approximately $105 million5, representing an attractively priced portfolio addition to our Champion Energy retail platform— Closed on the sale of our Mankato Power Plant to Southern Company for $396 million5— Closed on the sale of our Osprey Power Plant to Duke Energy for $166 million5 Balance Sheet Management:— As part of our commitment to delever and reduce interest expense, we have commenced the redemption and refinancing of $453 million of our 7.875% First Lien Notes due 2023, resulting in more than $20 million of annual interest savings— Redeemed $120 million of our 7.875% First Lien Notes due 2023 at a price of 103— Repriced our 2023 First Lien Term Loans by lowering the margin over LIBOR by 0.25% to 2.75% and extended the maturity of 2024 First Lien Term Loan from May 2022 to January 2024— Increased revolver capacity by approximately $112 million to $1,790 million through June 2020 Calpine Corporation (NYSE: CPN) today reported Net Income1 of $24 million, or $0.07 per diluted share, for the fourth quarter of 2016 compared to Net Loss1 of $47 million, or $0.13 per diluted share, in the prior year period. Net Income in 2016 was $92 million, or $0.26 per diluted share, compared to $235 million, or $0.64 per diluted share, in the prior year. The year-over-year increase in Net Income during the fourth quarter was primarily due to a gain recognized on the sale of our Mankato Power Plant and lower planet operating expense, partially offset by a higher income tax expense due to the restructuring of certain international entities in 2015 that did not recur in 2016. The decrease in Net Income in 2016 compared to 2015 was primarily due to lower operating revenue, net of operating expense, and higher income tax expense, as previously discussed, partially offset by the gain recognized on the sale of our Mankato Power Plant. Adjusted EBITDA2 for the fourth quarter was $357 million compared to $390 million in the prior year period, and Adjusted Free Cash Flow2 was $93 million compared to $97 million in the prior year period. The decreases in Adjusted EBITDA and Adjusted Free Cash Flow were primarily due to lower Commodity Margin2, largely driven by lower energy margins due to decreased contribution from wholesale hedges, partially offset by a decrease in plant operating expense6 due to the net period-over-period impact from a wildfire at our Geysers assets in 2015. Net Loss, As Adjusted2, for the fourth quarter of 2016 was $145 million compared to Net Income, As Adjusted, of $67 million in the prior year period. The decrease in Net Income, As Adjusted, was primarily due to lower Commodity Margin and higher income tax expense, as previously discussed. Adjusted EBITDA in 2016 was $1,815 million compared to $1,976 million in the prior year, and Adjusted Free Cash Flow was $736 million compared to $842 million in the prior year. The decreases in Adjusted EBITDA and Adjusted Free Cash Flow were largely due to lower Commodity Margin, driven primarily by lower energy margins due to decreased contribution from wholesale hedges, partially offset by a decrease in plant operating expense6 due to the net year-over-year impact from a wildfire at our Geysers assets in 2015 and a decrease in repairs and maintenance expense and production-related expense. Net Loss, As Adjusted, was $28 million in 2016 compared to Net Income, As Adjusted, of $385 million in the prior year. The decrease in Net Income, As Adjusted, was primarily due to lower Commodity Margin and higher income tax expense, as previously discussed. “Today, I am pleased to announce solid full-year 2016 earnings, continuing our strong, stable track record,” said Thad Hill, Calpine’s President and Chief Executive Officer. “Specifically, for the eighth consecutive year, we delivered on our financial performance commitments, achieving full-year Adjusted EBITDA and Adjusted Free Cash Flow within our guidance range, despite a challenging commodity environment in 2016. Our enduring commitment to operational excellence, customer focus and financial discipline is reflected in our 2016 accomplishments - our best safety performance on record; maintaining a competitive cost structure while continuing to achieve best-in-class operating performance and leading the industry in advocacy efforts; the successful integration of Champion Energy and the strategic completion of our broader retail platform through two additional acquisitions; and the divestiture of non-core generation assets for good value. Difficult markets come and go, but the Calpine team has stayed focused where it matters. I extend my sincere personal thanks to the entire Calpine team. “As I look ahead at 2017, our top priorities are to successfully integrate our retail platforms, execute on our delevering plan and, once again, deliver on our 2017 guidance of $1.8 - $1.95 billion of Adjusted EBITDA and $710 - $860 million of Adjusted Free Cash Flow. “On the retail front, over the past several months, we have strategically solidified and expanded our platform with acquisitions that complement our wholesale fleet and increase our access to end-use customers while boosting our margins in core power markets. We accretively recycled capital by completing the sales of our Mankato and Osprey power plants in non-core regions and reinvesting the proceeds into the purchases of Calpine Energy Solutions, one of the nation’s largest suppliers of power to commercial and industrial customers, and North American Power, a residential retail energy provider. With these changes to our portfolio, the integration of our retail businesses, not only with each other but also with our existing wholesale power business, is a priority. In order to assure a successful effort, Trey Griggs, formerly our Executive Vice President and Chief Commercial Officer, has assumed a new role as Executive Vice President and President, Calpine Retail, leading the integration and expanding the retail platform going forward. Andrew Novotny, Senior Vice President of Commercial Operations, and Caleb Stephenson, Senior Vice President of Wholesale Origination and Commercial Analytics, will oversee our wholesale activities and report directly to me. These organizational changes will establish alignment for our team to meet our goals for 2017 and beyond. “In terms of debt reduction, we have begun to execute on and are today updating the delevering plan we laid out on our third quarter earnings call. In December 2016, we redeemed $120 million of our 7.875% First Lien Notes that mature in 2023. More recently, we called the remaining $453 million of these notes, which will be funded with cash and proceeds from a 2019 term loan that we are committed to paying off in 2018. This structure accelerates our delevering plan and achieves interest savings in the interim. Our updated plan calls for $2.7 billion of committed or planned debt paydown by 2019, reducing our leverage by almost 1.5 turns at current Adjusted EBITDA levels. Importantly, after this paydown, we project that we will still have several hundred million dollars of deployable cash by the end of 2019, as well as increased financial flexibility. “In 2017, our delevering and retail integration efforts will be enhanced by our continued focus on financial discipline, maintaining our active advocacy for and defense of competitive power markets and remaining the premier operator of the highest quality assets. In short, these attributes have and will continue to enable us to deliver stable results through commodity market cycles. As these aspects of the strategy complement each other, our continued results and cash generation will provide value to shareholders for years to come.” __________ 1 Reported as Net Income (Loss) attributable to Calpine on our Consolidated Statements of Operations. 2 Non-GAAP financial measure, see “Regulation G Reconciliations” for further details. 3 According to EEI Safety Survey (2015). 4 Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants. 5 Excluding working capital and other adjustments. 6 Increase in plant operating expense excludes changes in major maintenance expense, stock-based compensation expense, non-cash loss on disposition of assets and other costs. See the table titled “Consolidated Adjusted EBITDA Reconciliation” for the actual amounts of these items for the three months and years ended December 31, 2016 and 2015. SUMMARY OF FINANCIAL PERFORMANCE Fourth Quarter Results Adjusted EBITDA for the fourth quarter of 2016 was $357 million compared to $390 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to a $73 million decrease in Commodity Margin, partially offset by a $36 million decrease in plant operating expense6, as previously discussed. The decrease in Commodity Margin was primarily due to: the net impact of our portfolio management activities, including the acquisition of Granite Ridge Energy Center in February 2016, partially offset by the sale of Mankato Power Plant in October 2016 and Adjusted Free Cash Flow was $93 million in the fourth quarter of 2016 compared to $97 million in the prior year period. Adjusted Free Cash Flow decreased due to lower Adjusted EBITDA, as previously discussed, partially offset by lower major maintenance expense and capital expenditures associated with the timing of planned outages. Full Year Results Adjusted EBITDA in 2016 was $1,815 million compared to $1,976 million in the prior year. The year-over-year decrease in Adjusted EBITDA was primarily related to a $182 million decrease in Commodity Margin, partially offset by a $22 million decrease in plant operating expense6, as previously discussed. The decrease in Commodity Margin was primarily due to: the net impact of our contracts, including the expiration of a PPA and a resource adequacy contract at our Pastoria Energy Center in December 2015, partially offset by a new PPA at our Morgan Energy Center in February 2016 and the receipt of a natural gas pipeline transportation billing credit in the West in the second quarter of 2016, the net impact of our portfolio management activities, including the acquisition of Granite Ridge Energy Center in February 2016 and the commencement of commercial operations at Garrison Energy Center in June 2015, partially offset by the expiration of the Greenleaf operating lease in June 2015 and the sale of Mankato Power Plant in October 2016. Adjusted Free Cash Flow was $736 million in 2016, compared to $842 million in the prior year. Adjusted Free Cash Flow decreased during the period primarily due to due to lower Adjusted EBITDA, as previously discussed, partially offset by lower major maintenance expense and capital expenditures associated with the timing of planned outages. REGIONAL SEGMENT REVIEW OF RESULTS Table 1: Commodity Margin by Segment (in millions) West Region Fourth Quarter: Commodity Margin in our West segment decreased by $21 million in the fourth quarter of 2016 compared to the prior year period. Primary drivers were: Full Year: Commodity Margin in our West segment decreased by $115 million in 2016, compared to the prior year. Primary drivers were: Texas Region Fourth Quarter: Commodity Margin in our Texas segment decreased by $9 million in the fourth quarter of 2016 compared to the prior year period. Primary drivers were: Full Year: Commodity Margin in our Texas segment decreased by $81 million in 2016, compared to the prior year. Primary drivers were: East Region Fourth Quarter: Commodity Margin in our East segment decreased $43 million in the fourth quarter of 2016 compared to the prior year period. Primary drivers were: the net impact of our portfolio management activities, including the acquisition of Granite Ridge Energy Center in February 2016, partially offset by the sale of Mankato Power Plant in October 2016 and Full Year: Commodity Margin in our East segment increased by $14 million in 2016, compared to the prior year. Primary drivers were: the net impact of our portfolio management activities, including the acquisition of Granite Ridge Energy Center in February 2016 and the commencement of commercial operations at Garrison Energy Center in June 2015, partially offset by the sale of Mankato Power Plant in October 2016, the positive impact of a new PPA associated with our Morgan Energy Center, which became effective in February 2016, and higher contribution from our retail hedging activity during 2016 following the acquisitions of Champion Energy in October 2015 and Calpine Energy Solutions in December 2016, partially offset by LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES Table 2: Liquidity (in millions) __________ (1) Includes $16 million and $35 million of margin deposits posted with us by our counterparties at December 31, 2016 and 2015, respectively. On January 3, 2017, we received $162 million in cash proceeds from the sale of Osprey Energy Center. (2) Our ability to use availability under our Corporate Revolving Facility is unrestricted. 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. On December 1, 2016, we further amended our Corporate Revolving Facility, increasing the capacity by $112 million to $1,790 million for the full term through June 27, 2020. (3) Our ability to use corporate cash and cash equivalents is unrestricted. Our $300 million CDHI letter of credit facility is restricted to support certain obligations under PPAs and power transmission and natural gas transportation agreements. Liquidity was approximately $1.9 billion as of December 31, 2016. Cash and cash equivalents decreased in 2016 primarily due to the acquisitions of Granite Ridge Energy Center and Calpine Energy Solutions, capital expenditures on construction projects and outages, and repayments of project financing, notes payable and financing costs, partially offset by cash provided by the sale of our Mankato Power Plant, as well as from operating and financing activities. Table 3: Cash Flow Activities (in millions) ) Cash provided by operating activities in 2016 was $1,030 million compared to $876 million in the prior year. The increase in cash provided by operating activities was primarily due to a decrease in working capital employed, a reduction in cash paid for interest due to our refinancing activities and a reduction in debt modification and extinguishment payments, partially offset by a decrease in income from operations, adjusted for non-cash items. Cash used in investing activities was $1,919 million during 2016 compared to $841 million in the prior year. The increase was primarily related to the purchases of Calpine Energy Solutions for $1,150 million (before recovery of working capital and collateral) and Granite Ridge Energy Center for $526 million, partially offset by approximately $164 million of net proceeds from the sale of Mankato Power Plant and a decrease in capital expenditures on construction projects and outages. Cash provided by financing activities was $401 million during 2016 and was primarily related to proceeds from the issuances of our 2017 First Lien Term Loan, 2023 First Lien Term Loan and 2026 First Lien Notes. These inflows were partially offset by payments associated with the redemption of our 2023 First Lien Notes and repayment of our 2019 and 2020 First Lien Term Loans. CAPITAL ALLOCATION Our capital allocation philosophy seeks to maximize levered cash returns to equity while maintaining a strong balance sheet. We seek to enhance shareholder value through a diverse and balanced capital allocation approach that includes portfolio management, organic or acquisitive growth, returning capital to shareholders and debt reduction. The mix of this activity shifts over time given the external market environment and the opportunity set. In the current environment, we believe that paying down debt and strengthening our balance sheet is a high return investment for our shareholders. We also consider the repurchases of our own shares of common stock as an attractive investment opportunity, and we utilize the expected returns from this investment as the benchmark against which we evaluate all other capital allocation decisions. We believe this philosophy closely aligns our objectives with those of our shareholders. Managing Our Balance Sheet We further optimized our capital structure by refinancing, redeeming or amending several of our debt instruments during the year ended December 31, 2016: 2023 First Lien Notes: — As part of our commitment to reduce debt and interest expense, on February 3, 2017, we issued a notice of redemption to repay the remaining $453 million of our 7.875% First Lien Notes due in 2023 using cash on hand along with the proceeds from a new $400 million three-year First Lien Term Loan priced at LIBOR + 1.75% per annum. We intend to repay the 2019 First Lien Term Loan in full by the end of 2018. This accelerates debt reduction and achieves substantial annual interest savings of more than $20 million in the interim.— In December 2016, we used cash on hand to redeem $120 million of our 7.875% First Lien Notes due in 2023 at a price of 103. First Lien Term Loans: — In December 2016, we repriced our 2023 First Lien Term Loans by lowering the margin over LIBOR by 0.25% to 2.75% and extended the maturity of our 2024 First Lien Term Loan from May 2022 to January 2024. Russell City Project Debt: — In November 2016, we repriced our Russell City project debt by lowering the margin over LIBOR by 0.50% - 0.75% through the maturity date. Corporate Revolving Facility: — On December 1, 2016, we amended our Corporate Revolving Facility to increase the aggregate revolving loan commitments available thereunder by approximately $112 million to $1,790 million for the full term through the maturity date of June 27, 2020. Expanding Our Customer Sales Channels We continue to focus on getting closer to our customers through expansion of our retail platform, which began with the acquisition of Champion Energy in 2015, and was followed by the acquisitions of Calpine Energy Solutions in late 2016 and North American Power in early 2017. Our retail platform geographically and strategically complements our wholesale generation fleet by providing forward liquidity with sufficient margins. The combination of our wholesale origination and retail platform provides Calpine access to both direct and mass market sales channels. Our direct sales efforts aim to provide our larger customers with customized products, leveraging both our successful wholesale origination efforts and Calpine Energy Solutions’ presence among large commercial and industrial organizations to secure new contracts. Our mass market approach relies upon our expanded Champion Energy retail platform to serve the needs of both residential and smaller commercial and industrial customers across the country. We believe that our retail platform is strategically complete and are now focused on integrating it into our business and optimizing its financial performance. Acquisition of Calpine Energy Solutions On December 1, 2016, we completed the purchase of Calpine Energy Solutions, formerly Noble Americas Energy Solutions, along with a swap contract for approximately $800 million plus approximately $350 million of net working capital at closing. We recovered approximately $250 million in cash subsequent to closing and expect to recover an additional approximately $200 million through collateral synergies and the runoff of acquired legacy hedges, substantially within the first year. Calpine Energy Solutions is a commercial and industrial retail electricity provider with customers in 19 states in the U.S., including presence in California, Texas, the Mid-Atlantic and Northeast, where our wholesale power generation fleet is primarily concentrated. The acquisition of this best-in-class direct energy sales platform is consistent with our stated goal of getting closer to our end-use customers and expands our retail customer base, complementing our existing retail business while providing us a valuable sales channel for reaching a much greater portion of the load we seek to serve. Acquisition of North American Power & Gas, LLC On January 17, 2017, we completed the purchase of North American Power for approximately $105 million, excluding working capital and other adjustments. North American Power is a growing retail energy supplier for homes and small businesses and is primarily concentrated in the Northeast U.S., where Calpine has a substantial power generation presence and where Champion Energy has a substantial retail sales footprint that will be enhanced by the addition of North American Power, which will be integrated into our Champion Energy retail platform. Portfolio Management East: York 2 Energy Center: York 2 Energy Center is an 828 MW dual-fuel, combined-cycle project that is 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 is under construction, and the initial 760 MW of capacity cleared PJM’s last three base residual auctions with the 68 MW of incremental capacity clearing the last two base residual auctions. Due to construction delays, we are now targeting COD in late 2017. Mankato Power Plant: On October 26, 2016, we completed the sale of our Mankato Power Plant, a 375 MW natural gas-fired, combined-cycle power plant and a 345 MW expansion project under advanced development located in Minnesota, to Southern Power Company, a subsidiary of Southern Company, for $396 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration. Osprey Energy Center: On January 3, 2017, we completed the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration. Texas: Clear Lake Power Plant: During the third quarter of 2016, we filed with ERCOT to retire our 400 MW Clear Lake Power Plant. ERCOT subsequently approved our plan to discontinue operations. Built in 1985, Clear Lake utilized an older technology. Due to growing maintenance costs and lack of adequate compensation in Texas, we retired the power plant on February 1, 2017. Guadalupe Peaking Energy Center: In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) related to the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center. Under the terms of the agreement, construction of the Guadalupe Peaking Energy Center (“GPEC”) may commence at our discretion, so long as the power plant reaches commercial operation by June 1, 2019. When the power plant begins commercial operation, GVEC will purchase a 50% ownership interest in GPEC. Once built, GPEC will feature two fast-ramping combustion turbines capable of responding to peaks in power demand. This project represents a mutually beneficial response to our customer’s desire to have direct access to peaking generation resources, as it leverages the benefits of our existing site and development rights and our construction and operating expertise, as well as our customer’s ability to fund its investment at attractive rates, all while affording us the flexibility of timing the plant’s construction in response to market pricing signals. West: South Point Energy Center: On April 1, 2016, we entered into an asset sale agreement for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy for approximately $76 million plus the assumption by the purchaser of existing transmission capacity contracts with a future net present value payment obligation of approximately $112 million, approximately $9 million in remaining tribal lease costs and approximately $21 million in near-term repairs, maintenance and capital improvements to restore the power plant to full capacity. The sale is subject to certain conditions precedent, as well as federal and state regulatory approvals. This transaction supports our effort to divest non-core assets outside our strategic concentration. In December 2016, the Nevada Public Utility Commission (NPUC) issued an order rejecting the asset sale agreement. In January 2017, Nevada Power Company filed a motion for reconsideration of this order. In February 2017, the FERC approved Nevada Power Company’s acquisition of South Point. However, on February 8, 2017, the NPUC denied Nevada Power Company’s purchase of South Point. Nevada Power Company has the right to appeal this decision. We are also currently assessing our options; however, we do not anticipate that the denial of the sale by the NPUC will have a material effect on our financial condition, results of operations or cash flows. OPERATIONS UPDATE 2016 Power Operations Achievements: Safety Performance:— Maintained top quartile4 safety metrics: 0.55 total recordable incident rate Availability Performance:— Achieved low fleetwide forced outage factor7: 2.1%— Delivered strong fleetwide starting reliability: 97.9% Power Generation:— Three Texas merchant power plants with full-year capacity factors greater than 65%:Bosque, Freestone and Pasadena— California peakers achieved 98.2% starting reliability on 1,483 start attempts 2015 Wildfire at our Geysers assets In September 2015, a wildfire spread to our Geysers assets in Lake and Sonoma counties, California. The wildfire affected several of our geothermal power plants in the region, which sustained damage to ancillary structures such as cooling towers and communication/electric deliverability infrastructure. Repairs have been completed, and our Geysers assets are currently generating renewable power for our customers at pre-fire levels. The repair and replacement costs, as well as our net revenue losses relating to the wildfire, were limited to our insurance deductibles of approximately $36 million, all of which was recognized in 2015. The losses incurred in 2016 related to the wildfire were primarily offset by insurance proceeds. We record insurance proceeds in the same financial statement line as the related loss is incurred and recorded approximately $24 million and $2 million in business interruption proceeds in operating revenues during the years ended December 31, 2016 and 2015, respectively. The wildfire and insurance proceeds recovery did not have a material effect on our financial condition, results of operations or cash flows. 2017 Operating Event at our Delta Energy Center On January 29, 2017, we experienced an operating event at our Delta Energy Center that resulted in an emergency shutdown of the power plant; the duration of which has yet to be determined. We are currently assessing the damage to the plant, in particular the steam turbine and steam turbine generator. Based on preliminary information, we anticipate that insurance will cover a significant portion of our losses, after applicable deductibles. 2016 Customer-Based Achievements: Wholesale: — 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.— Our ten-year PPA with Southern California Edison for 50 MW of capacity and renewable energy from our Geysers assets commencing in January 2018 was approved by the California Public Utility Commission in the second quarter of 2016.— We entered into a new five-year steam agreement, subject to certain conditions precedent, with a wholly owned subsidiary of The Dow Chemical Company to provide steam from our Texas City Power Plant through 2021.— We entered into a new five-year PPA with USS-POSCO Industries to provide 50 MW of energy and steam from our Los Medanos Energy Center commencing in January 2017, which also provides for annual extensions through 2024.— We entered into a new five-year PPA with a third party to provide 50 MW of capacity from our RockGen Energy Center commencing in June 2017, which increases to 100 MW of capacity commencing in June 2019. Retail: — In 2016, our retail subsidiaries served approximately 65 million MWh of customer load consisting of approximately 6.5 million annualized residential customer equivalents at December 31, 2016.— Champion Energy was ranked highest in customer satisfaction among Texas retail electric providers according to the J.D. Power 2016 Electric Provider Retail Customer Satisfaction Study. This is the sixth time Champion Energy has received the top ranking in the past seven years.— During 2016, Champion Energy expanded its service territory to include commercial and industrial customers in Maine, Connecticut and California. ___________ 7 Excludes the impacts of the 2015 Geysers wildfire, Sutter Energy Center (suspended operations) and South Point (pending sale). 2017 FINANCIAL OUTLOOK — ____________ (1) Includes projected major maintenance expense of $315 million and maintenance capital expenditures of $120 million in 2017. Capital expenditures exclude major construction and development projects. (2) Includes commitment, letter of credit and other fees from consolidated and unconsolidated investments, net of capitalized interest and interest income. (3) Amount includes $200 million of recurring amortization, as well as the $550 million repayment of the 2017 First Lien Term Loan, a portion of the of $453 million of our callable 7 7/8% 2023 Senior Secured Notes and the buyout of the Pasadena lessor interest. As detailed above, today we are reaffirming our 2017 guidance range. We expect Adjusted EBITDA of $1.8 billion to $1.95 billion and Adjusted Free Cash Flow of $710 million to $860 million. We expect to invest $220 million in our ongoing growth-related projects during 2017, primarily the construction of York 2 Energy Center. INVESTOR CONFERENCE CALL AND WEBCAST We will host a conference call to discuss our financial and operating results for the fourth quarter and full year 2016 on Friday, February 10, 2017, at 10 a.m. Eastern time / 9 a.m. Central time. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing (800) 447-0521 in the U.S. or (847) 413-3238 outside the U.S. The confirmation code is 43994310. A 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 43994310. Presentation materials to accompany the conference call will be posted on our website on February 10, 2017. ABOUT CALPINE Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources with operations in competitive power markets. Our fleet of 80 power plants in operation or under construction represents approximately 26,000 megawatts of generation capacity. Through wholesale power operations and our retail businesses Calpine Energy Solutions and Champion Energy, we serve customers in 25 states, Canada and Mexico. Our clean, efficient, modern and flexible fleet uses advanced technologies to generate power in a low-carbon and environmentally responsible manner. We are uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. Please visit www.calpine.com to learn more about why Calpine is a generation ahead - today. Calpine’s Annual Report on Form 10-K for the year ended December 31, 2016, has been filed with the Securities and Exchange Commission (SEC) and is available on the SEC’s website at www.sec.gov. FORWARD-LOOKING INFORMATION In addition to historical information, this release contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this release. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. We believe that the forward-looking statements are based upon reasonable assumptions and expectations. However, you are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to: Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability and extent to which we hedge risks; Laws, regulations and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate; Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our Senior Unsecured Notes, First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, 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 from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, and other risks associated with marketing and selling power in the evolving energy markets; Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies); The expiration or early termination of our PPAs and the related results on revenues; Future capacity revenue may not occur at expected levels; Natural disasters, such as hurricanes, earthquakes, droughts, wildfires and floods, acts of terrorism or cyber-attacks that may affect our power plants or the markets our power plants or retail operations serve and our corporate headquarters; Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power; Our ability to manage our counterparty and customer exposure and credit risk, including our commodity positions; Our ability to attract, motivate and retain key employees; Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and Other risks identified in this press release, in our Annual Report on Form 10-K for the year ended December 31, 2016, and in other reports filed by us with the SEC. Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise. Three Months Ended December 31, Weighted average shares of common stock outstanding (in thousands) Net income (loss) per common share attributable to Calpine — basic Weighted average shares of common stock outstanding (in thousands) CALPINE CORPORATION AND SUBSIDIARIES CALPINE CORPORATION AND SUBSIDIARIES $ $ $ (1,231 ) — (120 ) (364 ) (9 ) (58 ) (6 ) (1 154 (488 ) 189 717 $ $ $ (37 ) $ $ $ $ __________ (1) Includes amortization included in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts. (2) On October 26, 2016, we completed the sale of Mankato Power Plant for $407 million, including working capital and other adjustments. We received net proceeds of $164 million after the noncash reduction of Steamboat project debt of $243 million as the funds were provided directly to the lender in conjunction with the sale of the power plant. (3) On December 1, 2016, we completed the purchase of Calpine Solutions, formerly Noble Americas Energy Solutions, along with a swap contract for approximately $800 million plus approximately $350 million of net working capital at closing. We recovered approximately $250 million in cash subsequent to closing and prior to year end December 31, 2016. REGULATION G RECONCILIATIONS In addition to disclosing financial results in accordance with U.S. GAAP, the accompanying fourth quarter 2016 earnings release contains non-GAAP financial measures. Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These non-GAAP measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance, and the financial results calculated in accordance with U.S. GAAP and reconciliations from these results should be carefully evaluated. Net Income (Loss), As Adjusted, represents net income (loss) attributable to Calpine, adjusted for certain non-cash and non-recurring items, including mark-to-market (gain) loss on derivatives, debt modification and extinguishment costs and other adjustments. Net Income (Loss), As Adjusted, is presented because we believe it is a useful tool for assessing the operating performance of our company in the current period. Net Income (Loss), As Adjusted, is not intended to represent net income (loss), the most comparable U.S. GAAP measure, as an indicator of operating performance, and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, revenue from renewable energy credits, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin is not a measure calculated in accordance with U.S. GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with U.S. GAAP. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Adjusted EBITDA represents net income (loss) attributable to Calpine before net (income) attributable to the noncontrolling interest, interest, taxes, depreciation and amortization, adjusted for certain non-cash and non-recurring items as detailed in the following reconciliation. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. We believe Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase, modification or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any 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 (loss) 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. Net Income (Loss), As Adjusted Reconciliation The following table reconciles our Net Income, As Adjusted, to its U.S. GAAP results for the three months and years ended December 31, 2016 and 2015 (in millions): __________ (1) Assumes 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 include hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. Commodity Margin Reconciliation The following tables reconcile our Commodity Margin to its U.S. GAAP results for the three months and years ended December 31, 2016 and 2015 (in millions): Income (loss) from operations Income (loss) from operations Income (loss) from operations Income (loss) from operations _________ (1) Includes nil and $(1) million of lease levelization and $43 million and $9 million of amortization expense for the three months ended December 31, 2016 and 2015, respectively. (2) Includes $(2) million and $(2) million of lease levelization and $122 million and $20 million of amortization expense for the years ended December 31, 2016 and 2015, respectively. Consolidated Adjusted EBITDA Reconciliation In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our net income attributable to Calpine for the three months and years ended December 31, 2016 and 2015, as reported under U.S. GAAP (in millions): (76 ) _________ (1) Excludes depreciation and amortization expense attributable to the non-controlling interest. (2) 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, 2016 and 2015. (3) Includes $66 million and $257 million in major maintenance expense for the three months and year ended December 31, 2016, respectively, and $28 million and $148 million in maintenance capital expenditures for the three months and year ended December 31, 2016, respectively. Includes $74 million and $272 million in major maintenance expense for the three months and year ended December 31, 2015, respectively, and $57 million and $189 million in maintenance capital expenditures for the three months and year ended December 31, 2015, respectively. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (5) Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance. Consolidated Adjusted EBITDA Reconciliation 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, 2016 and 2015. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. Amounts below are shown exclusive of the noncontrolling interest (in millions): _________ (1) Shown net of major maintenance expense, stock-based compensation expense, non-cash loss on dispositions of assets and other costs. (2) Shown net of stock-based compensation expense and other costs. (3) Shown net of operating lease expense, amortization and other costs. Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance (in millions) _________ (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 $315 million and maintenance capital expenditures of $120 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: 7,432 ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us. (2) Generation, average availability and steam adjusted heat rate exclude power plants and units that are inactive.

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE: CPN): Summary of Third Quarter 2016 Financial Results (in millions): % % % Weighted Average Shares Outstanding (diluted) Narrowing 2016 Guidance and Providing 2017 Full Year Guidance (in millions): Recent Achievements: Power and Commercial Operations:— Generated record 34 million MWh3 in the third quarter of 2016— Achieved top quartile4 safety metrics: 0.56 total recordable incident rate through third quarter— Delivered strong third quarter fleetwide starting reliability: 98.3%— Champion Energy ranked highest in customer satisfaction among Texas retail electric providers by J.D. Power for sixth time in past seven years— Entered into a new five-year steam agreement, subject to certain conditions precedent, with a wholly owned subsidiary of The Dow Chemical Company to provide steam from our Texas City Power Plant through 2021— Entered into a new five-year PPA with USS-POSCO Industries to provide 50 MW of energy and steam from our Los Medanos Energy Center commencing in January 2017, which also provides for yearly extensions through 2024— Completed repairs on our Geysers assets to generate renewable power for our customers at pre-fire capacity levels Portfolio and Balance Sheet Management:— Announced accretive acquisition of leading commercial and industrial retail electricity provider Noble Americas Energy Solutions, LLC for $800 million plus approximately $100 million of estimated net working capital at closing— Announced and closed on the sale of our Mankato Power Plant to Southern Power Company for $396 million5— Received approval from ERCOT to economically retire our 400 MW Clear Lake Power Plant by February 2017 Calpine Corporation (NYSE: CPN) today reported Net Income1 of $295 million, or $0.83 per diluted share, for the third quarter of 2016 compared to $273 million, or $0.76 per diluted share, in the prior year period. Net Income for the first nine months of 2016 was $68 million, or $0.19 per diluted share, compared to $282 million, or $0.77 per diluted share, in the prior year period. The increase in Net Income during the third quarter was primarily due to an increase in mark-to-market gains and lower income tax expense, offset by lower commodity revenue, net of commodity expense. The decrease in Net Income during the first nine months of 2016 was primarily due to lower commodity revenue, net of commodity expense. Adjusted EBITDA2 for the third quarter was $632 million compared to $791 million in the prior year period, and Adjusted Free Cash Flow2 was $383 million compared to $576 million in the prior year period. The decreases in Adjusted EBITDA and Adjusted Free Cash Flow were primarily due to lower Commodity Margin2, largely driven by lower energy margins due to decreased contribution from hedges. Net Income, As Adjusted2, for the third quarter of 2016 was $186 million compared to $347 million in the prior year period. The decrease in Net Income, As Adjusted, was primarily due to lower commodity revenue, net of commodity expense, as previously discussed. Adjusted EBITDA in the first nine months of 2016 was $1,458 million, compared to $1,586 million in the prior year period, and Adjusted Free Cash Flow was $643 million compared to $745 million in the prior year period. The decreases in Adjusted EBITDA and Adjusted Free Cash Flow were largely due to lower Commodity Margin, driven primarily by lower energy margins due to decreased contribution from hedges. Net Income, As Adjusted, for the first nine months of 2016 was $104 million compared to $318 million in the prior year period. The decrease in Net Income, As Adjusted, was primarily due to lower commodity revenue, net of commodity expense, as previously discussed. “Calpine’s wholesale power generation fleet continued to demonstrate its operational excellence during the third quarter, producing a record 34 million MWh with 98% fleetwide starting reliability and zero OSHA recordable events,” said Thad Hill, Calpine’s President and Chief Executive Officer. “In addition, we are accretively recycling capital from non-core wholesale assets into Noble Americas Energy Solutions, the nation’s best-in-class independent supplier of power to large commercial and industrial retail customers. “Noble’s geographic footprint and direct-sales approach complement our existing Champion Energy retail platform. Strategically, this acquisition increases our retail scale, further diversifies our company and moves us closer to customers in our core deregulated markets of California, Texas and the Northeast. “Also today, we are narrowing our 2016 Adjusted EBITDA guidance range to $1.8 billion to $1.85 billion. While we anticipated lower 2016 summer hedge pricing relative to 2015, actual summer liquidations disappointed relative to expectations. As we look toward next year, we introduce our 2017 Adjusted EBITDA guidance of $1.8 billion to $1.95 billion and Adjusted Free Cash Flow of $710 million to $860 million, growing Adjusted Free Cash Flow by approximately 7% over 2016, based on the midpoint. In 2017, the accretive retail acquisition of Noble will triple the Adjusted EBITDA and Free Cash Flow derived from the facilities for which we have previously announced divestitures - Mankato, Osprey and South Point. And now our focus will be to integrate Noble, close on remaining non-core portfolio sales and complete the York 2 expansion project, while controlling costs and operating safely and effectively. “Ultimately, we believe our unique wholesale power generation portfolio, complemented by a growing retail business, will generate strong cash flow returns for years to come. Moreover, we expect that more than 65% of our current market capitalization will be available over the next three years for deployment towards growth, debt reduction or return to shareholders.” ________ 1 Reported as Net Income attributable to Calpine on our Consolidated Condensed Statements of Operations. 2 Non-GAAP financial measure, see “Regulation G Reconciliations” for further details. 3 Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants. 4 According to EEI Safety Survey (2015). 5 Excluding working capital and other adjustments. SUMMARY OF FINANCIAL PERFORMANCE Third Quarter Results Adjusted EBITDA for the third quarter of 2016 was $632 million compared to $791 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to a $154 million decrease in Commodity Margin, reflecting: lower energy margins due to decreased contribution from wholesale hedges across our segments and lower realized spark spreads in our Texas segment, the impact of our portfolio management activities, including a full quarter of energy and capacity revenue associated with the operation of our 695 MW Granite Ridge Energy Center, which was acquired on February 5, 2016. Adjusted Free Cash Flow was $383 million in the third quarter of 2016 compared to $576 million in the prior year period. Adjusted Free Cash Flow decreased during the period primarily due to lower Adjusted EBITDA, as previously discussed, as well as higher major maintenance costs associated with our scheduled maintenance. Year-to-Date Results Adjusted EBITDA for the nine months ended September 30, 2016, was $1,458 million compared to $1,586 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to a $109 million decrease in Commodity Margin and a $14 million increase in plant operating expense6 that was largely driven by portfolio changes. The decrease in Commodity Margin was primarily due to: lower energy margins due to decreased contribution from wholesale hedges across our segments and lower realized spark spreads in our Texas segment lower regulatory capacity revenue, primarily in the West, partially offset by Adjusted Free Cash Flow was $643 million for the nine months ended September 30, 2016, compared to $745 million in the prior year period. Adjusted Free Cash Flow decreased during the period primarily due to lower Adjusted EBITDA, as previously discussed, partially offset by lower major maintenance costs associated with our maintenance schedule. REGIONAL SEGMENT REVIEW OF RESULTS Table 1: Commodity Margin by Segment (in millions) West Region Third Quarter: Commodity Margin in our West segment decreased by $87 million in the third quarter of 2016 compared to the prior year period. Primary drivers were: Year-to-Date: Commodity Margin in our West segment decreased by $94 million for the nine months ended September 30, 2016, compared to the prior year period. Primary drivers were: Texas Region Third Quarter: Commodity Margin in our Texas segment decreased by $66 million in the third quarter of 2016 compared to the prior year period. Primary drivers were: Year-to-Date: Commodity Margin in our Texas segment decreased by $72 million for the nine months ended September 30, 2016, compared to the prior year period. Primary drivers were: East Region Third Quarter: Commodity Margin in our East segment was relatively unchanged in the third quarter of 2016 compared to the prior year period. Primary drivers were: Year-to-Date: Commodity Margin in our East segment increased by $57 million for the nine months ended September 30, 2016, compared to the prior year period. Primary drivers were: ___________ 6 Increase in plant operating expense excludes changes in major maintenance expense, stock-based compensation expense, non-cash loss on disposition of assets and other costs. See the table titled “Consolidated Adjusted EBITDA Reconciliation” for the actual amounts of these items for the three and nine months ended September 30, 2016 and 2015. LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES Table 2: Liquidity (in millions) ____________ (1) Includes $30 million and $35 million of margin deposits posted with us by our counterparties at September 30, 2016, and December 31, 2015, respectively. (2) 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. Our ability to use availability under our Corporate Revolving Facility is unrestricted. (3) Our ability to use corporate cash and cash equivalents is unrestricted. Our $300 million CDHI letter of credit facility is restricted to support certain obligations under PPAs, power transmission and natural gas transportation agreements. Liquidity was approximately $2.2 billion as of September 30, 2016. Cash and cash equivalents decreased during the first nine months of 2016 primarily due to the acquisition of Granite Ridge Energy Center, capital expenditures on construction projects and outages, repayments of project financing, notes payable and financing costs, partially offset by cash provided by operating activities. Table 3: Cash Flow Activities (in millions) Cash provided by operating activities in the nine months ended September 30, 2016, was $667 million compared to $559 million in the prior year period. The increase in cash provided by operating activities was primarily due to a decrease in working capital, a reduction in cash paid for interest due to our refinancing activities and a reduction in debt modification and extinguishment payments, partially offset by a decrease in income from operations, adjusted for non-cash items. Cash used in investing activities was $841 million during the nine months ended September 30, 2016, compared to $450 million in the prior year period. The increase was primarily related to the purchase of Granite Ridge Energy Center for $526 million, partially offset by a decrease in capital expenditures on construction projects and outages. Cash used in financing activities was $171 million during the nine months ended September 30, 2016, which was primarily related to scheduled repayments of debt and the repayment of our 2019 and 2020 First Lien Term Loans with the proceeds from the issuance of our new 2023 First Lien Term Loan and 2026 First Lien Notes. CAPITAL ALLOCATION Our capital allocation philosophy seeks to maximize levered cash returns to equity while maintaining a strong balance sheet. We strive to enhance shareholder value through the combination of investing for growth at attractive returns, managing the balance sheet through debt pay down and returning capital to shareholders. We view our stock as an attractive investment opportunity, and we use the projected returns from share repurchases as the benchmark against which all other investment decisions are measured. We are committed to remaining fiscally disciplined and balanced in our capital allocation decisions. Acquisition of Noble Americas Energy Solutions, LLC On October 9, 2016, we announced that we entered into an agreement to purchase Noble Americas Energy Solutions, LLC (NAES) and a swap contract for approximately $800 million plus approximately $100 million of net working capital estimated at closing. We expect to recover approximately $200 million through collateral synergies and the runoff of acquired legacy hedges, substantially within the first year. NAES is a commercial and industrial retail electricity provider with customers in 18 states in the U.S., including California, Texas, the Mid-Atlantic and Northeast, where our wholesale power generation fleet is primarily concentrated. The acquisition of this best-in-class direct energy sales platform is consistent with our stated goal of getting closer to our end-use customers and expands our retail customer base, complementing our existing retail business while providing us a valuable sales channel for reaching a much greater portion of the load we seek to serve. The transaction is expected to close in the fourth quarter of 2016, subject to federal regulatory approval and approval of the shareholders of Noble Group Limited, and will be funded with a combination of cash on hand and debt financing. Growth and Portfolio Management East: York 2 Energy Center: York 2 Energy Center is an 828 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 is now under construction and the initial 760 MW of capacity cleared PJM’s last three base residual auctions with 68 MW of incremental capacity clearing the last two base residual auctions. Due to construction delays, we are now targeting COD in late 2017. Mankato Power Plant: On October 26, 2016, we, through our indirect, wholly owned subsidiaries New Steamboat Holdings, LLC and Mankato Holdings, LLC, completed the sale of our Mankato Power Plant, a 375 MW natural gas-fired, combined-cycle power plant and 345 MW expansion project under advanced development located in Minnesota, to Southern Power Company, a subsidiary of Southern Company, for $396 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration. We expect to use the proceeds from the sale to fund pending acquisitions and for other corporate purposes. We expect to record a gain on sale of assets, net of approximately $160 million, during the fourth quarter of 2016, and our federal and state NOLs will almost entirely offset the projected taxable gain from the sale. Osprey Energy Center: We executed an asset sale agreement in the fourth quarter of 2014 for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments, which will be consummated in January 2017 upon the conclusion of a PPA with a term of 27 months. The sale has received FERC and state regulatory approvals and represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities. PJM and ISO-NE Development Opportunities: We continue to evaluate development projects in the PJM and ISO-NE market areas that feature cost-advantages, such as existing infrastructure and favorable transmission queue positions. These projects continue to advance entitlements (such as permits, zoning and transmission) for potential future development when/if economic as compared to purchasing existing power plants in the region. Texas: Clear Lake Power Plant: During the third quarter of 2016, we filed with ERCOT to retire our 400 MW Clear Lake Power Plant. Built in 1985, Clear Lake is an older technology. Due to growing maintenance costs and lack of adequate compensation in Texas, we have chosen to retire the power plant. ERCOT has approved our plan to cease operations. We are working together with the facility’s bilateral counterparty to mutually agree on a date to cease commercial operations, which is expected no later than February 2017. The book value associated with our Clear Lake Power Plant is immaterial. Guadalupe Peaking Energy Center: In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) that will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center. Under the terms of the agreement, construction of the Guadalupe Peaking Energy Center (“GPEC”) may commence at our discretion, so long as the power plant reaches commercial operation by June 1, 2019. When the power plant begins commercial operation, GVEC will purchase a 50% ownership interest in GPEC. Once built, GPEC will feature two fast-ramping combustion turbines capable of responding to peaks in power demand. This project represents a mutually beneficial response to our customer’s desire to have direct access to peaking generation resources, as it leverages the benefits of our existing site and development rights and our construction and operating expertise, as well as our customer’s ability to fund its investment at attractive rates, all while affording us the flexibility of timing the plant’s construction in response to market pricing signals. West: South Point Energy Center: On April 1, 2016, we entered into an asset sale agreement for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy for approximately $76 million plus the assumption by the purchaser of existing transmission capacity contracts with a future net present value payment obligation of approximately $112 million, approximately $9 million in remaining tribal lease costs and approximately $21 million in near-term repairs, maintenance and capital improvements to restore the power plant to full capacity. The sale is subject to certain conditions precedent, as well as federal and state regulatory approvals, and is expected to close no later than the first quarter of 2017. The natural gas-fired, combined-cycle plant is located on the Fort Mojave Indian Reservation in Mohave Valley, Arizona, and features a summer peak capacity of 504 MW. This transaction supports our effort to divest non-core assets outside our strategic concentration. OPERATIONS UPDATE Third Quarter Power Operations Achievements: Safety Performance:— Maintained top quartile4 safety metrics: 0.56 total recordable incident rate year to date Availability Performance:— Achieved low fleetwide forced outage factor: 1.2%— Delivered strong fleetwide starting reliability: 98.3% Power Generation:— Nine gas-fired plants with third quarter capacity factors greater than 80%: West: Hermiston, Pastoria Texas: Bosque, Freestone, Hidalgo, Pasadena East: Fore River, Kennedy, Morgan West: Hermiston, Pastoria Texas: Bosque, Freestone, Hidalgo, Pasadena East: Fore River, Kennedy, Morgan Geysers Wildfire Impact In September 2015, a wildfire spread to our Geysers assets in Lake and Sonoma counties, California. The wildfire affected several of our geothermal power plants in the region, which sustained damage to ancillary structures such as cooling towers and communication/electric deliverability infrastructure. Repairs have been completed and our Geysers assets are currently generating renewable power for our customers at pre-fire levels. We believe the repair and replacement costs, as well as our net revenue losses relating to the wildfire, will be limited to our insurance deductibles of approximately $36 million, all of which was recognized in 2015. Any losses incurred in 2016 related to the wildfire will be primarily offset by insurance proceeds, when such proceeds are realizable. We record insurance proceeds in the same financial statement line as the related loss is incurred and recorded approximately $9 million and $17 million in business interruption proceeds in operating revenues during the three and nine months ended September 30, 2016, respectively. We do not anticipate the wildfire or timing of insurance proceeds recovery to have a material impact on our financial condition, results of operations or cash flows. Third Quarter Commercial Operations Achievements: Customer Relationships:— We entered into a new five-year steam agreement, subject to certain conditions precedent, with a wholly owned subsidiary of The Dow Chemical Company to provide steam from our Texas City Power Plant through 2021.— We entered into a new five-year PPA with USS-POSCO Industries to provide 50 MW of energy and steam from our Los Medanos Energy Center commencing in January 2017, which also provides for yearly extensions through 2024.— Champion was ranked highest in customer satisfaction among Texas retail electric providers according to the J.D. Power 2016 Electric Provider Retail Customer Satisfaction Study. This is the sixth time Champion Energy has received the top ranking in the past seven years. 2016 & 2017 FINANCIAL OUTLOOK (200 ____________ (1) Includes projected major maintenance expense of $270 million and maintenance capital expenditures of $140 million in 2016 and major maintenance expense of $315 million and maintenance capital expenditures of $105 million in 2017. Capital expenditures exclude major construction and development projects. (2) Includes commitment, letter of credit and other fees from consolidated and unconsolidated investments, net of capitalized interest and interest income. (3) 2016 amount includes $210 million of recurring amortization, as well as $120 million of callable 7 7/8% 2023 Senior Secured Notes and buyout of Pasadena lessor interest. 2017 amount includes $200 of recurring amortization. As detailed above, today we are narrowing our 2016 guidance range. We now expect Adjusted EBITDA of $1.8 billion to $1.85 billion and Adjusted Free Cash Flow of $710 million to $760 million. We expect to invest $285 million in our growth projects throughout 2016, primarily the construction of York 2 Energy Center. We are also initiating guidance for 2017. We expect Adjusted EBITDA of $1.8 billion to $1.95 billion and Adjusted Free Cash Flow of $710 million to $860 million. We expect to invest $250 million in our ongoing growth-related projects during 2017, primarily the construction of York 2 Energy Center. INVESTOR CONFERENCE CALL AND WEBCAST We will host a conference call to discuss our financial and operating results for the third quarter on Friday, October 28, 2016, at 10 a.m. Eastern time / 9 a.m. Central time. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing (800) 446-1671 in the U.S. or (847) 413-3362 outside the U.S. The confirmation code is 43406531. A 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 43406531. Presentation materials to accompany the conference call will be on our website on October 28, 2016. ABOUT CALPINE Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources. Our fleet of 82 power plants in operation or under construction represents nearly 27,000 megawatts of generation capacity. Through wholesale power operations and our retail business, Champion Energy, we serve customers in 20 states and Canada. We specialize in developing, constructing, owning and operating natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our clean, efficient, modern and flexible fleet is uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. Please visit www.calpine.com to learn more about why Calpine is a generation ahead - today, or visit www.championenergyservices.com for details on Champion’s award-winning retail electric services. Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016, has been filed with the Securities and Exchange Commission (SEC) and is available on the SEC’s website at www.sec.gov. FORWARD-LOOKING INFORMATION In addition to historical information, this release contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this release. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to: Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability and extent to which we hedge risks; Laws, regulations and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate; Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our Senior Unsecured Notes, First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, 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 from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, and other risks associated with marketing and selling power in the evolving energy markets; Structural changes in the supply and demand of power resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies); The expiration or early termination of our PPAs and the related results on revenues; Future capacity revenue may not occur at expected levels; Natural disasters, such as hurricanes, earthquakes, droughts, wildfires and floods, acts of terrorism or cyber-attacks that may impact our power plants or the markets our power plants or retail operations serve and our corporate headquarters; Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power; Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions; Our ability to attract, motivate and retain key employees; Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and Other risks identified in this press release, in our Annual Report on Form 10-K for the year ended December 31, 2015, in our Quarterly Report on Form 10-Q for the three months ended September 30, 2016, and in other reports filed by us with the SEC. Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise. CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (Unaudited) CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) Net income Shares withheld for tax obligations on share-based awards __________ (1) Includes amortization recorded in Commodity Revenue and Commodity Expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts. REGULATION G RECONCILIATIONS In addition to disclosing financial results in accordance with U.S. GAAP, the accompanying third quarter 2016 earnings release contains non-GAAP financial measures. Net Income, As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These non-GAAP measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance, and the financial results calculated in accordance with U.S. GAAP and reconciliations from these results should be carefully evaluated. Net Income, As Adjusted, represents net income attributable to Calpine, adjusted for certain non-cash and non-recurring items, including mark-to-market (gain) loss on derivatives, debt modification and extinguishment costs and other adjustments. Net Income, 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, As Adjusted, is not intended to represent net income, the most comparable U.S. GAAP measure, as an indicator of operating performance, and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, revenue from renewable energy credits, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Adjusted EBITDA represents net income attributable to Calpine before net (income) 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 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, modification or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any 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, the most directly comparable U.S. GAAP measure, or liquidity and is not necessarily comparable to similarly titled measures reported by other companies. Net Income, As Adjusted Reconciliation The following table reconciles our Net Income, As Adjusted, to its U.S. GAAP results for the three and nine months ended September 30, 2016 and 2015 (in millions): Mark-to-market (gain) loss on derivatives(1)(2) __________ (1) Assumes 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 include hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. Commodity Margin Reconciliation The following tables reconcile our Commodity Margin to its U.S. GAAP results for the three and nine months ended September 30, 2016 and 2015 (in millions): _________ (1) Includes $40 million and $41 million of lease levelization and $25 million and $4 million of amortization expense for the three months ended September 30, 2016 and 2015, respectively. (2) Includes $(2) million and $(1) million of lease levelization and $79 million and $11 million of amortization expense for the nine months ended September 30, 2016 and 2015, respectively. Consolidated Adjusted EBITDA Reconciliation In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our net income attributable to Calpine for the three and nine months ended September 30, 2016 and 2015, as reported under U.S. GAAP (in millions): Weighted Average Shares Outstanding (diluted) 356 358 356 368 _________ (1) Excludes depreciation and amortization expense attributable to the non-controlling interest. (2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for each of the three and nine months ended September 30, 2016 and 2015. (3) Includes $45 million and $191 million in major maintenance expense for the three and nine months ended September 30, 2016, respectively, and $39 million and $120 million in maintenance capital expenditures for the three and nine months ended September 30, 2016, respectively. Includes $29 million and $198 million in major maintenance expense for the three and nine months ended September 30, 2015, respectively, and $22 million and $132 million in maintenance capital expenditures for the three and nine months ended September 30, 2015, respectively. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (5) Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance. In the following table, we have reconciled our Adjusted EBITDA to our Commodity Margin, both of which are non-GAAP measures, for the three and nine months ended September 30, 2016 and 2015. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. Amounts below are shown exclusive of the noncontrolling interest (in millions): Other _________ (1) Shown net of major maintenance expense, stock-based compensation expense, non-cash loss on dispositions of assets and other costs. (2) Shown net of stock-based compensation expense and other costs. (3) Shown net of operating lease expense, amortization and other costs. Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance (in millions) _________ (1) For purposes of Net Income guidance reconciliation, mark-to-market adjustments are assumed to be nil. (2) Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, income tax expense and other items. (3) Includes projected major maintenance expense of $270 million and maintenance capital expenditures of $140 million. Capital expenditures exclude major construction and development projects. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance (in millions) _________ (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 $315 million and maintenance capital expenditures of $105 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: ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us. (2) Generation, average availability and steam adjusted heat rate exclude power plants and units that are inactive.

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE: CPN): Summary of Second Quarter 2016 Financial Results (in millions, except per share amounts): % % % % % 2016 Full Year Guidance (in millions, except per share amounts): (as of April 29, 2016) Recent Achievements: Power and Commercial Operations:— Generated approximately 27 million MWh3 in the second quarter of 2016— Achieved top quartile4 safety metrics: 0.86 total recordable incident rate through second quarter— Delivered strong second quarter fleetwide starting reliability: 97.4%— Texas fleet set a record for highest second quarter capacity factor of 62%— Northern California peaker fleet set a record for most starts in a second quarter— Received approval from California Public Utilities Commission for our ten-year PPA with Southern California Edison for 50 MW of capacity and renewable energy from our Geysers assets commencing in January 2018— Geysers wildfire recovery on track for full capacity with insurance proceeds throughout the year Portfolio and Balance Sheet Management:— Announcing plan to file with ERCOT for retirement of our 400 MW Clear Lake Power Plant no later than summer of 2018, and possibly sooner depending on negotiations with the facility's bilateral counterparties— Continued construction of our 760 MW York 2 Energy Center in PJM, targeting COD in the third quarter of 2017— Advanced development of 345 MW contracted expansion of our Mankato Power Plant in Minnesota, targeting COD by June 2019— Successfully refinanced approximately $1.2 billion of term loans, ensuring no corporate maturities until 2022 Calpine Corporation (NYSE: CPN) today reported a Net Loss1 of $29 million, or $0.08 per diluted share, for the second quarter of 2016 compared to Net Income of $19 million, or $0.05 per diluted share, in the prior year period. Net Loss for the first half of 2016 was $227 million, or $0.64 per diluted share, compared to Net Income of $9 million, or $0.02 per diluted share, in the prior year period. The increase in Net Loss during the second quarter and first half of 2016 was primarily due to net mark-to-market losses driven by increases in forward power and natural gas prices. Adjusted EBITDA2 for the second quarter was $452 million, roughly consistent with $457 million in the prior year period. Adjusted Free Cash Flow2 was $158 million compared to $144 million in the prior year period. The increase in Adjusted Free Cash Flow was primarily driven by a decrease in major maintenance expense and capital expenditures. Net Income, As Adjusted2, for the second quarter of 2016 was $22 million compared to $33 million in the prior year period. The decrease in Net Income, As Adjusted, was primarily due to a decrease in commodity revenue, net of commodity expense, partially offset by an increase in income tax benefit associated with an increase in pre-tax losses. Adjusted EBITDA in the first half of 2016 was $826 million, compared to $795 million in the prior year period, and Adjusted Free Cash Flow was $260 million compared to $169 million in the prior year period. The increase in Adjusted EBITDA was largely due to higher Commodity Margin2 driven primarily by a gas transportation credit and portfolio changes, partially offset by higher plant operating expenses5, largely driven by portfolio changes. The increase in Adjusted Free Cash Flow was primarily driven by higher Commodity Margin, as discussed, and a decrease in major maintenance expense and capital expenditures. Net Loss, As Adjusted, for the first half of 2016 was $82 million compared to $29 million in the prior year period. The increase in Net Loss, As Adjusted, was primarily due to an increase in depreciation and amortization expense and an increase in estimated income tax expense in state jurisdictions where we do not have net operating losses. “I am proud to report solid second quarter results as our business continues to perform well on all fronts,” said Thad Hill, Calpine’s President and Chief Executive Officer. “Supported by strong operational performance, our second quarter Adjusted EBITDA of $452 million was in line with last year, and we delivered 10% growth in Adjusted Free Cash Flow. These results demonstrate the benefits of our strategic portfolio changes, as well as the strength of our assets and our team. “With this performance, we’ve had a very strong first half of the year, which combined with a good hedging program, has enabled us to remain within our original guidance range, despite weak summer liquidations. Today, we are narrowing our guidance range for this year to $1.8 billion to $1.9 billion of Adjusted EBITDA and $710 million to $810 million of Adjusted Free Cash Flow. “Longer term, our portfolio of reliable, flexible assets and, as importantly, our people are responding to the secular trends of our industry. Baseload resources continue to be threatened by a combination of lower gas prices, increasingly stringent environmental regulations and further penetration of renewables. Our flexible assets are rising to the challenge of meeting our customers’ needs for reliable, clean energy in an evolving landscape. In Texas, our fleet achieved a record second quarter capacity factor, and in California, our peaker fleet set a second quarter record for number of starts. Our assets clearly continue to be critical for reliability of the grid. We are also taking steps to enhance value over the long term by evolving our portfolio, leveraging our customer relationships, actively advocating to be fairly compensated and maintaining best-in-class operations.” _________ 1 Reported as Net Income (Loss) attributable to Calpine on our Consolidated Condensed Statements of Operations. 2 Non-GAAP financial measure, see “Regulation G Reconciliations” for further details. 3 Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants. 4 According to EEI Safety Survey (2015). SUMMARY OF FINANCIAL PERFORMANCE Second Quarter Results Adjusted EBITDA for the second quarter of 2016 was $452 million, roughly consistent with $457 million in the prior year period. Commodity Margin was flat year over year, reflecting: lower energy margins due to a decrease in generation and lower realized spark spreads, primarily in the West segment resulting from an increase in hydroelectric generation in the region, partially offset by an increase in generation in the Texas segment driven by higher market spark spreads and lower natural gas prices. Adjusted Free Cash Flow was $158 million in the second quarter of 2016 compared to $144 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to a decrease in major maintenance expense and capital expenditures resulting from our plant outage schedule. Year-to-Date Results Adjusted EBITDA for the six months ended June 30, 2016, was $826 million compared to $795 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily related to a $45 million increase in Commodity Margin, partially offset by an $11 million increase in plant operating expense5 that was largely driven by portfolio changes. The increase in Commodity Margin was primarily due to: the impact of our portfolio management activities, including approximately five months of energy and capacity revenue associated with both our 695 MW Granite Ridge Energy Center, which was acquired on February 5, 2016, and our 309 MW Garrison Energy Center, which commenced commercial operations in June 2015, and lower energy margins due to a decrease in generation and lower realized spark spreads, primarily in the West segment resulting from an increase in hydroelectric generation in the region, partially offset by increased contribution from hedging activity, including retail. Adjusted Free Cash Flow was $260 million for the six months ended June 30, 2016, compared to $169 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to higher Commodity Margin, as previously discussed, and a decrease in major maintenance expense and capital expenditures. ___________ 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 and six months ended June 30, 2016 and 2015. REGIONAL SEGMENT REVIEW OF RESULTS Table 1: Commodity Margin by Segment (in millions) West Region Second Quarter: Commodity Margin in our West segment increased by $14 million in the second quarter of 2016 compared to the prior year period. Primary drivers were: Year-to-Date: Commodity Margin in our West segment decreased by $7 million for the six months ended June 30, 2016, compared to the prior year period. Primary drivers were: Texas Region Second Quarter: Commodity Margin in our Texas segment decreased by $10 million in the second quarter of 2016 compared to the prior year period. Primary drivers were: an increase in generation driven by higher spark spreads and lower natural gas prices. Year-to-Date: Commodity Margin in our Texas segment decreased by $6 million for the six months ended June 30, 2016, compared to the prior year period. Primary drivers were: East Region Second Quarter: Commodity Margin in our East segment decreased by $4 million in the second quarter of 2016 compared to the prior year period. Primary drivers were: Year-to-Date: Commodity Margin in our East segment increased by $58 million for the six months ended June 30, 2016, compared to the prior year period. Primary drivers were: LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES Table 2: Liquidity (in millions) June 30, 2016 ____________ (1) Includes $9 million and $35 million of margin deposits posted with us by our counterparties at June 30, 2016, and December 31, 2015, respectively. (2) Cash and cash equivalents decreased during the six months ended June 30, 2016, primarily resulting from the acquisition of Granite Ridge Energy Center, payments to fund growth projects and other seasonal variations in working capital, which cause fluctuations in our cash and cash equivalents. (3) 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. Our ability to use availability under our Corporate Revolving Facility is unrestricted. (4) Our ability to use corporate cash and cash equivalents is unrestricted. Our $300 million CDHI letter of credit facility is restricted to support certain obligations under PPAs, power transmission and natural gas transportation agreements. Liquidity was approximately $1.8 billion as of June 30, 2016. Cash and cash equivalents decreased during the first half of 2016 primarily due to the acquisition of Granite Ridge Energy Center, payments to fund growth projects and other seasonal variations in working capital. Table 3: Cash Flow Activities (in millions) Cash provided by operating activities was $120 million in the first half of 2016 compared to $19 million in the prior year. The increase in cash provided by operating activities was primarily due to an increase in income from operations, adjusted for non-cash items, a reduction in cash paid for interest due to our refinancing activities and a reduction in debt modification and extinguishment payments, partially offset by an increase in working capital largely associated with net margining requirements. Cash used in investing activities was $676 million in the first half of 2016 compared to $246 million in the prior year period. The increase was primarily related to the purchase of Granite Ridge Energy Center for $526 million, partially offset by a $56 million decrease in capital expenditures on construction projects and outages. Cash used in financing activities was $135 million during the first half of 2016 and was primarily related to scheduled repayments of debt and the repayment of our 2019 and 2020 First Lien Term Loans with the proceeds from the issuance of our new 2023 First Lien Term Loan and 2026 First Lien Notes. CAPITAL ALLOCATION Our capital allocation philosophy seeks to maximize levered cash returns to equity while maintaining a strong balance sheet. We strive to enhance shareholder value through the combination of investing for growth at attractive returns, managing the balance sheet through debt pay down and returning capital to shareholders. We view our stock as an attractive investment opportunity, and we use the projected returns from share repurchases as the benchmark against which all other investment decisions are measured. We are committed to remaining fiscally disciplined and balanced in our capital allocation decisions. Term Loan Refinancing On May 31, 2016, we issued $625 million in aggregate principal amount of 5.25% senior secured notes due 2026 in a private placement. We concurrently entered into a $562 million first lien senior secured term loan which bears interest at LIBOR plus 3.00% per annum (with no LIBOR floor) and matures on May 31, 2023. We used the proceeds from these issuances to repay our 2019 and 2020 First Lien Term Loans. Growth and Portfolio Management East: 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 last three base residual auctions. The project is now under construction, and we are targeting COD during the third 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 last two base residual auctions and we expect to receive the final air permit in the third quarter of 2016. 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 satisfied final regulatory approval requirements in March 2016. Commercial operation of the expanded capacity is expected by June 1, 2019. PJM and ISO-NE Development Opportunities: We continue to evaluate development projects in the PJM and ISO-NE market areas that feature cost-advantages, such as existing infrastructure and favorable transmission queue positions. These projects continue to advance entitlements (such as permits, zoning and transmission) for potential future development when/if economic as compared to purchasing existing power plants in the region. Osprey Energy Center: We executed an asset sale agreement in the fourth quarter of 2014 for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments, which will be consummated in January 2017 upon the conclusion of a PPA with a term of 27 months. The sale has received FERC and state regulatory approvals and represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities. Texas: Clear Lake Power Plant: We plan to file with ERCOT to retire our 400-MW Clear Lake Power Plant. Built in 1985, Clear Lake is an older technology. Due to growing maintenance costs and lack of adequate compensation in Texas, we have chosen to retire the power plant. We are working together with the facility's bilateral counterparties to mutually agree on a date to cease commercial operations, which will take place no later than the summer of 2018. Guadalupe Peaking Energy Center: In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) that will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center. Under the terms of the agreement, construction of the Guadalupe Peaking Energy Center (“GPEC”) may commence at our discretion, so long as the power plant reaches commercial operation by June 1, 2019. When the power plant begins commercial operation, GVEC will purchase a 50% ownership interest in GPEC. Once built, GPEC will feature two fast-ramping combustion turbines capable of responding to peaks in power demand. This project represents a mutually beneficial response to our customer’s desire to have direct access to peaking generation resources, as it leverages the benefits of our existing site and development rights and our construction and operating expertise, as well as our customer’s ability to fund its investment at attractive rates, all while affording us the flexibility of timing the plant’s construction in response to market pricing signals. West: South Point Energy Center: On April 1, 2016, we entered into an asset sale agreement for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy for approximately $76 million plus the assumption by the purchaser of existing transmission capacity contracts with a future net present value payment obligation of approximately $112 million, approximately $9 million in remaining tribal lease costs and approximately $21 million in near-term repairs, maintenance and capital improvements to restore the power plant to full capacity. The sale is subject to certain conditions precedent, as well as federal and state regulatory approvals, and is expected to close no later than the first quarter of 2017. The natural gas-fired, combined-cycle plant is located on the Fort Mojave Indian Reservation in Mohave Valley, Arizona, and features a summer peak capacity of 504 MW. This transaction supports our effort to divest non-core assets outside our strategic concentration. OPERATIONS UPDATE Second Quarter Power Operations Achievements: Safety Performance:— Maintained top quartile4 safety metrics: 0.86 total recordable incident rate year to date Availability Performance:— Northern California peaker fleet set a record for most starts (232) in a second quarter— Delivered strong fleetwide starting reliability: 97.4% Power Generation:— Texas fleet set a second quarter generation record of 12.6 million MWh3— Three Texas merchant plants achieved greater than 75% net capacity factor: Pasadena, Freestone and Bosque Geysers Wildfire Impact In September 2015, a wildfire spread to our Geysers assets in Lake and Sonoma counties, California. The wildfire affected five of our 14 power plants in the region, which sustained damage to ancillary structures such as cooling towers and communication/electric deliverability infrastructure. Our Geysers assets are currently generating renewable power for our customers at approximately 95% of the normal operating capacity and should be restored to pre-fire levels by the end of 2016. We believe the repair and replacement costs, as well as our net revenue losses relating to the wildfire, will be limited to our insurance deductibles of approximately $36 million, all of which was recognized in 2015. Any losses incurred in 2016 related to the wildfire will be primarily offset by insurance proceeds, when such proceeds are realizable. We record insurance proceeds in the same financial statement line as the related loss is incurred and recorded approximately $8 million in business interruption proceeds as operating revenues during the three and six months ended June 30, 2016. We do not anticipate the wildfire or timing of insurance proceeds recovery to have a material impact on our financial condition, results of operations or cash flows. Second Quarter Commercial Operations Achievements: Customer Relationships:— Our ten-year PPA with Southern California Edison for 50 MW of capacity and renewable energy from our Geysers assets commencing in January 2018 was approved by the CPUC in the second quarter of 2016. 2016 FINANCIAL OUTLOOK(in millions, except per share amounts) Other 5 ____________ (1) Includes projected major maintenance expense of $270 million and maintenance capital expenditures of $140 million in 2016. Capital expenditures exclude major construction and development projects. (2) Includes commitment, letter of credit and other fees from consolidated and unconsolidated investments, net of capitalized interest and interest income. (3) Includes $210 million of recurring amortization, as well as $225 million of proceeds from our 2023 First Lien Term Loan that we intend to use to repay project and corporate debt. Today we are narrowing our 2016 guidance range. We expect Adjusted EBITDA of $1.8 billion to $1.9 billion and Adjusted Free Cash Flow of $710 million to $810 million. We expect to invest $285 million in our growth projects throughout 2016, primarily the construction of York 2 Energy Center. INVESTOR CONFERENCE CALL AND WEBCAST We will host a conference call to discuss our financial and operating results for the second quarter on Friday, July 29, 2016, at 10 a.m. Eastern time / 9 a.m. Central time. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing (800) 446-1671 in the U.S. or (847) 413-3362 outside the U.S. The confirmation code is 42863696. 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 42863696. Presentation materials to accompany the conference call will be available on our website on July 29, 2016. ABOUT CALPINE Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources. Our fleet of 84 power plants in operation or under construction represents more than 27,000 megawatts of generation capacity. Through wholesale power operations and our retail business, Champion Energy, we serve customers in 21 states and Canada. We specialize in developing, constructing, owning and operating natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our clean, efficient, modern and flexible fleet is uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. Please visit www.calpine.com to learn more about why Calpine is a generation ahead - today, or visit www.championenergyservices.com for details on Champion’s award-winning retail electric services. Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, has been filed with the Securities and Exchange Commission (SEC) and is available on the SEC’s website at www.sec.gov. FORWARD-LOOKING INFORMATION In addition to historical information, this release contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this release. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to: Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability and extent to which we hedge risks; Laws, regulations and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate; Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our Senior Unsecured Notes, First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, 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 from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, and other risks associated with marketing and selling power in the evolving energy markets; Structural changes in the supply and demand of power resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies); The expiration or early termination of our PPAs and the related results on revenues; Future capacity revenue may not occur at expected levels; Natural disasters, such as hurricanes, earthquakes, droughts, wildfires and floods, acts of terrorism or cyber-attacks that may impact our power plants or the markets our power plants or retail operations serve and our corporate headquarters; Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power; Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions; Our ability to attract, motivate and retain key employees; Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and Other risks identified in this press release, in our Annual Report on Form 10-K for the year ended December 31, 2015, in our Quarterly Report on Form 10-Q for the three months ended June 30, 2016, and in other reports filed by us with the SEC. Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise. CALPINE CORPORATION AND SUBSIDIARIESCONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (Unaudited) 542 CALPINE CORPORATION AND SUBSIDIARIESCONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) June 30, CALPINE CORPORATION AND SUBSIDIARIESCONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) __________ (1) Includes amortization recorded in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts. REGULATION G RECONCILIATIONS In addition to disclosing financial results in accordance with U.S. GAAP, the accompanying second quarter 2016 earnings release contains non-GAAP financial measures. Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These non-GAAP measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance and the financial results calculated in accordance with U.S. GAAP and reconciliations from these results should be carefully evaluated. Net Income (Loss), As Adjusted, represents net income (loss) attributable to Calpine, adjusted for certain non-cash and non-recurring items, including mark-to-market (gain) loss on derivatives, debt modification and extinguishment costs and other adjustments. Net Income (Loss), As Adjusted, is presented because we believe it is a useful tool for assessing the operating performance of our company in the current period. Net Income (Loss), As Adjusted, is not intended to represent net income (loss), the most comparable U.S. GAAP measure, as an indicator of operating performance, and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, revenue from renewable energy credits, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Adjusted EBITDA represents net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization, adjusted for certain non-cash and non-recurring items as detailed in the following reconciliation. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. We believe Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase, modification or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any 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. Net Income (Loss), As Adjusted Reconciliation The following table reconciles our Net Income (Loss), As Adjusted, to its U.S. GAAP results for the three and six months ended June 30, 2016 and 2015 (in millions): __________ (1) Assumes 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 include hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. Commodity Margin Reconciliation The following tables reconcile our Commodity Margin to its U.S. GAAP results for the three and six months ended June 30, 2016 and 2015 (in millions): _________ (1) Includes $(20) million and $(18) million of lease levelization and $27 million and $3 million of amortization expense for the three months ended June 30, 2016 and 2015, respectively. (2) Includes $(42) million and $(42) million of lease levelization and $54 million and $7 million of amortization expense for the six months ended June 30, 2016 and 2015, 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 and six months ended June 30, 2016 and 2015, as reported under U.S. GAAP (in millions): _________ (1) Excludes depreciation and amortization expense attributable to the non-controlling interest. (2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for each of the three and six months ended June 30, 2016 and 2015. (3) Includes $81 million and $146 million in major maintenance expense for the three and six months ended June 30, 2016, respectively, and $41 million and $81 million in maintenance capital expenditures for the three and six months ended June 30, 2016, respectively. Includes $90 million and $169 million in major maintenance expense for the three and six months ended June 30, 2015, respectively, and $46 million and $110 million in maintenance capital expenditures for the three and six months ended June 30, 2015, respectively. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (5) Excludes increases in working capital of $69 million and $127 million for the three and six months ended June 30, 2016, respectively, and increases in working capital of $165 million and $251 million for the three and six months ended June 30, 2015, respectively. Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance. In the following table, we have reconciled our Adjusted EBITDA to our Commodity Margin, both of which are non-GAAP measures, for the three and six months ended June 30, 2016 and 2015. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. Amounts below are shown exclusive of the noncontrolling interest (in millions): _________ (1) Shown net of major maintenance expense, stock-based compensation expense, non-cash loss on dispositions of assets and other costs. (2) Shown net of stock-based compensation expense and other costs. (3) Shown net of operating lease expense, amortization and other costs. Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance (in millions) Low High 70 170 Debt extinguishment costs 15 15 655 655 130 130 _________ (1) For purposes of Net Income guidance reconciliation, mark-to-market adjustments are assumed to be nil. (2) Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, income tax expense and other items. (3) Includes projected major maintenance expense of $270 million and maintenance capital expenditures of $140 million. Capital expenditures exclude major construction and development projects. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. OPERATING PERFORMANCE METRICS The table below shows the operating performance metrics for the periods presented: ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us. (2) Generation, average availability and steam adjusted heat rate exclude power plants and units that are inactive.

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE: CPN): Summary of First Quarter 2016 Financial Results (in millions, except per share amounts): % % % % Reaffirming 2016 Full Year Guidance (in millions, except per share amounts): Recent Achievements: Power Operations:— Generated approximately 25 million MWh3 in the first quarter of 2016— Achieved top quartile4 safety metrics: 0.79 total recordable incident rate in the first quarter of 2016— Delivered strong first quarter fleetwide starting reliability: 97.6%— Geysers wildfire recovery on track for full capacity with insurance proceeds later this year Customer-Oriented Origination Efforts:— Expanded Champion Energy’s New England service territory to commercial and industrial customers in Maine and Connecticut— Satisfied final regulatory approval requirements for the 20-year PPA that will facilitate a 345 MW expansion of our Mankato Power Plant— Entered into a new five-year PPA to provide 50 MW of capacity from our RockGen Energy Center commencing in June 2017, which increases to 100 MW of capacity commencing in June 2019 Portfolio and Balance Sheet Management:— Reached an agreement for the sale of South Point Energy Center to Nevada Power Company, subject to certain conditions, as well as federal and state regulatory approvals; expected to close no later than first quarter of 2017— Corporate Family Rating upgraded by Moody’s Investors Service to Ba3 Calpine Corporation (NYSE: CPN) today reported a first quarter 2016 Net Loss of $198 million, or $0.56 per diluted share, compared to $10 million, or $0.03 per diluted share, in the prior year period. The year-over-year increase in Net Loss was primarily due to net non-cash mark-to-market losses driven by decreases in forward power and natural gas prices during the first quarter of 2016. Adjusted EBITDA for the first quarter was $374 million, compared to $338 million in the prior year period, and Adjusted Free Cash Flow was $102 million, or $0.29 per diluted share, compared to $25 million, or $0.07 per diluted share, in the prior year period. The increase in Adjusted EBITDA was primarily due to higher Commodity Margin driven by higher contribution from hedges (including retail), higher regulatory capacity revenue in PJM and ISO-New England and changes in our power plant portfolio. The increase in Adjusted Free Cash Flow was primarily driven by a decrease in major maintenance expense associated with our plant outage schedule, as well as an increase in Adjusted EBITDA, as previously discussed. Net Loss, As Adjusted, for the first quarter of 2016 was $104 million compared to $62 million in the prior year period. The increase in Net Loss, As Adjusted, was primarily due to an increase in estimated income tax expense in state jurisdictions where we do not have net operating losses, and an increase in depreciation and amortization expense driven largely by power plant portfolio changes, partially offset by an increase in Commodity Margin, as previously discussed. “I am pleased to report that first quarter Adjusted EBITDA increased $36 million year-over-year, despite mild winter weather across much of the country,” said Thad Hill, Calpine’s President and Chief Executive Officer. “This performance was due to solid operations and effective hedging, and has kept us on track to reaffirm our full year guidance. “Our first quarter results demonstrate the continued benefits of our geographically diverse, flexible and clean generation fleet. These modern, natural gas-fired power generation resources allow us to be resilient to low natural gas prices in the near term, while favorably positioning us for the long term. “We also remain focused on building and developing our customer relationships. Over time, we think our customer focus, through both our Champion Energy retail business and our wholesale origination efforts, will deliver better results than simply being a price-taker. Since our last call, we have signed a new five-year contract in the East, expanded our retail service territory in New England and reached an agreement to sell our South Point Energy Center in Arizona to a local utility. This is in addition to the new ten-year toll of our Morgan plant with the Tennessee Valley Authority that we announced in February. “The sale of our South Point Energy Center represents progress toward our stated goal of divesting non-core assets through accretive transactions,” added Hill. “Subject to certain conditions and regulatory approvals, we expect this transaction to close no later than the first quarter of 2017. I would like to recognize the South Point employees for their dedication and professionalism as members of the Calpine team. “The South Point sale proceeds, along with proceeds from our previously announced sale of Osprey Energy Center at the end of this year, will further enhance our capital allocation flexibility as we continue to pursue a well-balanced program consisting of growth, capital return and debt reduction.” _________ 1 Non-GAAP financial measure, see “Regulation G Reconciliations” for further details. 2 Reported as Net Loss attributable to Calpine on our Consolidated Condensed Statements of Operations. 3 Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants. 4 According to EEI Safety Survey (2014). SUMMARY OF FINANCIAL PERFORMANCE First Quarter Results Adjusted EBITDA for the first quarter of 2016 was $374 million compared to $338 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily related to a $45 million increase in Commodity Margin, partially offset by an $8 million increase in plant operating expense5 primarily related to portfolio changes. The increase in Commodity Margin was primarily due to: the net impact of our portfolio management activities, including approximately two months of operation of our 695 MW Granite Ridge Energy Center, which was acquired on February 5, 2016, and a full quarter of operation of our 309 MW Garrison Energy Center, which commenced commercial operation in June 2015, partially offset by the expiration of the operating lease related to the Greenleaf power plants in June 2015, Adjusted Free Cash Flow was $102 million in the first quarter of 2016 compared to $25 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to an increase in Adjusted EBITDA, as previously discussed, and a decrease in major maintenance expense resulting from our plant outage schedule. ___________ 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 ended March 31, 2016 and 2015. REGIONAL SEGMENT REVIEW OF RESULTS Table 1: Commodity Margin by Segment (in millions) West Region First Quarter: Commodity Margin in our West segment decreased by $21 million in the first quarter of 2016 compared to the prior year period. Primary drivers were: Texas Region First Quarter: Commodity Margin in our Texas segment increased by $4 million in the first quarter of 2016 compared to the prior year period. Primary drivers were: East Region First Quarter: Commodity Margin in our East segment increased by $62 million in the first quarter of 2016 compared to the prior year period. Primary drivers were: LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES Table 2: Liquidity (in millions) ____________ (1) Includes $22 million and $35 million of margin deposits posted with us by our counterparties at March 31, 2016, and December 31, 2015, respectively. (2) On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 2020 and increasing the capacity by an additional $178 million to $1.678 billion through June 2018, reverting back to $1.520 billion through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 2020. Our ability to use availability under our Corporate Revolving Facility is unrestricted. (3) Our ability to use corporate cash and cash equivalents is unrestricted. Our $300 million CDHI letter of credit facility is restricted to support certain obligations under PPAs, transmission and natural gas transportation agreements. Liquidity was approximately $1.8 billion as of March 31, 2016. Cash and cash equivalents decreased during the first quarter of 2016 primarily due to the acquisition of Granite Ridge Energy Center, payments to fund growth projects and other seasonal variations in working capital. Table 3: Cash Flow Activities (in millions) Cash provided by operating activities was $26 million in the first quarter of 2016 compared to cash used in operating activities of $17 million in the prior year. The increase in cash provided by operating activities was primarily due to an increase in income from operations, adjusted for non-cash items, and a reduction in debt extinguishment payments, partially offset by an increase in working capital largely associated with an increase in net accounts receivable/accounts payable balances resulting from higher Commodity Margin in the first quarter of 2016. Cash used in investing activities was $611 million in the first quarter of 2016 compared to $128 million in the prior year period. The increase was primarily related to the purchase of Granite Ridge Energy Center for $527 million, partially offset by a $29 million decrease in capital expenditures on construction projects and outages. Cash used in financing activities was $77 million during the first quarter of 2016 and was primarily related to scheduled repayments of debt. CAPITAL ALLOCATION Our capital allocation philosophy seeks to maximize levered cash returns to equity on a per share basis while maintaining a strong balance sheet. We strive to enhance shareholder value through the combination of investing for growth at attractive returns, managing the balance sheet through debt pay down and returning capital to shareholders. We view our stock as an attractive investment opportunity, and we use the projected returns from share repurchases as the benchmark against which all other investment decisions are measured. We are committed to remaining fiscally disciplined and balanced in our capital allocation decisions. Acquisition of Granite Ridge Energy Center In February 2016, we completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), for approximately $500 million, excluding working capital and other adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant meaningfully increased our capacity in the constrained New England market. The power plant features two combustion turbines, two heat recovery steam generators and one steam turbine. We funded the acquisition with a combination of cash on hand and financing obtained in the fourth quarter of 2015. Corporate Revolver Extension and Expansion On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 27, 2020, and increasing the capacity by an additional $178 million to $1.678 billion through June 27, 2018, reverting back to $1.520 billion through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 27, 2020. Growth and Portfolio Management East: Garrison Energy Center: We are in the early stages of development of a second phase of the Garrison Energy Center that will add approximately 450 MW of dual-fuel, combined-cycle capacity. PJM has completed the project’s system impact study and the facilities study is underway. York 2 Energy Center: York 2 Energy Center is a 760 MW dual-fuel, combined-cycle project that will be co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. The project’s capacity cleared PJM’s 2017/2018 and 2018/2019 base residual auctions. The project is now under construction, and we expect commercial operations to commence during the second quarter of 2017. PJM has completed the interconnection study process for an additional 68 MW of planned capacity at the York 2 Energy Center. This incremental 68 MW of planned capacity cleared the 2018/19 base residual auction. Mankato Power Plant Expansion: By order dated February 5, 2015, the Minnesota Public Utilities Commission concluded a competitive resource acquisition proceeding and selected a 345 MW expansion of our Mankato Power Plant, authorizing execution of a 20-year PPA between Calpine and Xcel Energy. The PPA was executed in April 2015 and satisfied final regulatory approval requirements in March 2016. Commercial operation of the expanded capacity is expected by June 1, 2019. PJM and ISO-NE Development Opportunities: We are currently evaluating opportunities to develop additional projects in the PJM and ISO-NE market areas that feature cost-advantages, such as existing infrastructure and favorable transmission queue positions. These projects are continuing to advance entitlements (such as permits, zoning and transmission) for their potential future development when economical. Osprey Energy Center: We executed an asset sale agreement in the fourth quarter of 2014 for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments, which will be consummated in January 2017 upon the conclusion of a 27-month PPA. The sale has received FERC and state regulatory approvals and represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities. Texas: Guadalupe Peaking Energy Center: In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) that will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center. Under the terms of the agreement, construction of the Guadalupe Peaking Energy Center (“GPEC”) may commence at our discretion, so long as the power plant reaches commercial operation by June 1, 2019. When the power plant begins commercial operation, GVEC will purchase a 50% ownership interest in GPEC. Once built, GPEC will feature two fast-ramping combustion turbines capable of responding to peaks in power demand. This project represents a mutually beneficial response to our customer’s desire to have direct access to peaking generation resources, as it leverages the benefits of our existing site and development rights and our construction and operating expertise, as well as our customer’s ability to fund its investment at attractive rates, all while affording us the flexibility of timing the plant’s construction in response to market pricing signals. West: South Point Energy Center: On April 1, 2016, we entered into an asset sale agreement for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy. The sale is subject to certain conditions precedent, as well as federal and state regulatory approvals, and is expected to close no later than the first quarter of 2017. The natural gas-fired, combined-cycle plant is located on the Fort Mojave Indian Reservation in Mohave Valley, Arizona, and features a summer peak capacity of 504 MW. This transaction supports our effort to divest non-core assets outside our strategic concentration. Financial terms are not being provided at this time due to confidentiality terms specified in the agreement. All Segments: Turbine Modernization: We continue to move forward with our turbine modernization program. Through March 31, 2016, we have completed the upgrade of 13 Siemens and eight GE turbines totaling approximately 210 MW and have committed to upgrade three additional turbines. In addition, we have begun a program to update our dual-fueled turbines at certain of our East Region power plants. OPERATIONS UPDATE First Quarter Power Operations Achievements: Safety Performance:— Maintained top quartile4 safety metrics: 0.79 total recordable incident rate Availability Performance:— Delivered strong fleetwide starting reliability: 97.6% Power Generation:— Four gas-fired plants with first quarter capacity factors greater than 70%: Hermiston, Pasadena, Pine Bluff and Stony Brook Geysers Wildfire Impact In September 2015, a wildfire spread to our Geysers assets in Lake and Sonoma counties, California. The wildfire affected five of our 14 power plants in the region, which sustained damage to ancillary structures such as cooling towers and communication/electric deliverability infrastructure. Our Geysers assets are currently generating renewable power for our customers at more than 80% of the normal operating capacity and will be restored to pre-fire levels once repairs are completed, which is expected during the third quarter of 2016. We believe the repair and replacement costs, as well as our net revenue losses relating to the wildfire, will be limited to our insurance deductibles of approximately $36 million, all of which was recognized in 2015. Any losses incurred in 2016 related to the wildfire will be primarily offset by insurance proceeds, when such proceeds are realizable. We record insurance proceeds in the same financial statement line as the related loss is incurred. We do not anticipate the impact of the wildfire or timing of insurance proceeds recovery will have a material impact on our financial condition, results of operations or cash flows. First Quarter Commercial Operations Achievements: Customer Relationships:East:— We entered into a new ten-year PPA with Tennessee Valley Authority to provide 615 MW of energy and capacity from our Morgan Energy Center commencing in February 2016.— Champion Energy expanded its New England service territory and now offers electricity service to commercial and industrial customers in Maine and Connecticut.— We satisfied final regulatory approval requirements for our 20-year PPA with Xcel Energy, which will facilitate a 345 MW expansion of our Mankato Power Plant.— We entered into a new five-year PPA with a third party to provide 50 MW of capacity from our RockGen Energy Center commencing in June 2017, which increases to 100 MW of capacity commencing in June 2019. 2016 FINANCIAL OUTLOOK (in millions, except per share amounts) ____________ (1) Includes projected major maintenance expense of $270 million and maintenance capital expenditures of $140 million in 2016. Capital expenditures exclude major construction and development projects. (2) Includes commitment, letter of credit and other fees from consolidated and unconsolidated investments, net of capitalized interest and interest income. (3) Includes $210 million of recurring amortization, as well as $225 million of proceeds from our 2023 First Lien Term Loan that we intend to use to repay project and corporate debt. As detailed above, today we are reaffirming our 2016 guidance. We expect Adjusted EBITDA of $1.8 billion to $1.95 billion and Adjusted Free Cash Flow of $710 million to $860 million, or $2.00 to $2.40 per share. We expect to invest $285 million in our growth projects throughout 2016, primarily the construction of York 2 Energy Center. INVESTOR CONFERENCE CALL AND WEBCAST We will host a conference call to discuss our financial and operating results for the first quarter on Friday, April 29, 2016, at 10 a.m. Eastern time / 9 a.m. Central time. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing (800) 446-1671 in the U.S. or (847) 413-3362 outside the U.S. The confirmation code is 42124995. 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 42124995. Presentation materials to accompany the conference call will be available on our website on April 29, 2016. ABOUT CALPINE Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources. Our fleet of 84 power plants in operation or under construction represents more than 27,000 megawatts of generation capacity. Through wholesale power operations and our retail business, Champion Energy, we serve customers in 21 states and Canada. We specialize in developing, constructing, owning and operating natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our clean, efficient, modern and flexible fleet is uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. Please visit www.calpine.com to learn more about why Calpine is a generation ahead - today, or visit www.championenergyservices.com for details on Champion’s award-winning retail electric services. Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, has been filed with the Securities and Exchange Commission (SEC) and is available on the SEC’s website at www.sec.gov. FORWARD-LOOKING INFORMATION In addition to historical information, this release contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this release. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to: Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability and extent to which we hedge risks; Laws, regulations and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate; Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our First Lien Notes, Senior Unsecured Notes, Corporate Revolving Facility, First Lien Term Loans, CCFC Term Loans and other existing financing obligations; Risks associated with the operation, construction and development of power plants, including unscheduled outages or delays and plant efficiencies; Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of water to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources; Competition, including from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, and other risks associated with marketing and selling power in the evolving energy markets; Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies); The expiration or early termination of our PPAs and the related results on revenues; Future capacity revenue may not occur at expected levels; Natural disasters, such as hurricanes, earthquakes, droughts, wildfires and floods, acts of terrorism or cyber-attacks that may impact our power plants or the markets our power plants or retail operations serve and our corporate headquarters; Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power; Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions; Our ability to attract, motivate and retain key employees; Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and Other risks identified in this press release, in our Annual Report on Form 10-K for the year ended December 31, 2015, in our Quarterly Report on Form 10-Q for the three months ended March 31, 2016, and in other reports filed by us with the SEC. Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise. CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (Unaudited) CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) __________ (1) Includes depreciation and amortization included in commodity revenue, commodity expense and interest expense on our Consolidated Condensed Statements of Operations. REGULATION G RECONCILIATIONS In addition to disclosing financial results in accordance with U.S. GAAP, the accompanying first quarter 2016 earnings release contains non-GAAP financial measures. Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These non-GAAP measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance and the financial results calculated in accordance with U.S. GAAP and reconciliations from these results should be carefully evaluated. Net Income (Loss), As Adjusted, represents net income (loss) attributable to Calpine, adjusted for certain non-cash and non-recurring items, including mark-to-market (gain) loss on derivatives, debt modification and extinguishment costs and other adjustments. Net Income (Loss), As Adjusted, is presented because we believe it is a useful tool for assessing the operating performance of our company in the current period. Net Income (Loss), As Adjusted, is not intended to represent net income (loss), the most comparable U.S. GAAP measure, as an indicator of operating performance, and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, revenue from renewable energy credits, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Adjusted EBITDA represents net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization, adjusted for certain non-cash and non-recurring items as detailed in the following reconciliation. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. We believe Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase, modification or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any extraordinary, unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends. In summary, our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance. Adjusted Free Cash Flow represents net income before interest, taxes, depreciation and amortization, as adjusted, less operating lease payments, major maintenance expense and maintenance capital expenditures, net cash interest, cash taxes and other adjustments, including non-recurring items. Adjusted Free Cash Flow is presented because we believe it is a useful tool for assessing the financial performance of our company in the current period. Adjusted Free Cash Flow is a performance measure and is not intended to represent net income (loss), the most directly comparable U.S. GAAP measure, or liquidity and is not necessarily comparable to similarly titled measures reported by other companies. Net Loss, As Adjusted Reconciliation The following table reconciles our Net Loss, As Adjusted, to its U.S. GAAP results for the three months ended March 31, 2016 and 2015 (in millions): __________ (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 hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. Commodity Margin Reconciliation The following tables reconcile our Commodity Margin to its U.S. GAAP results for the three months ended March 31, 2016 and 2015 (in millions): _________ (1) Includes $(22) million and $(24) million of lease levelization and $27 million and $4 million of amortization expense for the three months ended March 31, 2016 and 2015, 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 ended March 31, 2016 and 2015, as reported under U.S. GAAP (in millions): _________ (1) Depreciation and amortization expense in the income from operations calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets. (2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for the three months ended March 31, 2016 and 2015. (3) Includes $65 million and $79 million in major maintenance expense for the three months ended March 31, 2016 and 2015, respectively, and $40 million and $64 million in maintenance capital expenditures for the three months ended March 31, 2016 and 2015, respectively. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (5) Excludes increases in working capital of $58 million and $86 million for the three months ended March 31, 2016 and 2015, 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 ended March 31, 2016 and 2015. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. Amounts below are shown exclusive of the noncontrolling interest (in millions): _________ (1) Shown net of major maintenance expense, stock-based compensation expense, non-cash loss on dispositions of assets and other costs. (2) Shown net of stock-based compensation expense and other costs. (3) Shown net of operating lease expense, amortization and other costs. Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance (in millions) _________ (1) For purposes of Net Income guidance reconciliation, mark-to-market adjustments are assumed to be nil. (2) Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, income tax expense and other items. (3) Includes projected major maintenance expense of $270 million and maintenance capital expenditures of $140 million. Capital expenditures exclude major construction and development projects. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. OPERATING PERFORMANCE METRICS The table below shows the operating performance metrics for the periods presented: ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us. (2) Generation, average availability and steam adjusted heat rate exclude power plants and units that are inactive.

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE: CPN): Summary of 2015 Financial Results (in millions, except per share amounts): % % % % % % % % Reaffirming 2016 Full Year Guidance (in millions, except per share amounts): Recent Achievements: Power Operations:— Generated approximately 115 million MWh3 in 2015— Achieved top quartile4 safety metrics: 0.73 total recordable incident rate in 2015— Delivered strong fleetwide starting reliability: 98.3% Customer-Oriented Origination Efforts:— Entered into new ten-year contract with the Tennessee Valley Authority to provide 615 MW of energy and capacity from our Morgan Energy Center commencing in February 2016— Extended contract by ten years beyond 2021 to provide South Texas Electric Cooperative with approximately 500 MW of energy annually— Entered into new three-year contract with the San Francisco Public Utilities Commission to provide, on average, approximately 43 MW of energy and renewable energy annually, commencing in May 2016 Portfolio and Balance Sheet Management:— Completed acquisition of Granite Ridge Energy Center for $500 million5— Entered into $550 million First Lien Term Loan due 2023, intended to fund a portion of Granite Ridge acquisition, to repay project and corporate debt and for general corporate purposes— Redeemed approximately $120 million of our 7.875% First Lien Notes due 2023 at a price of 103— Extended revolver maturity by two years to 2020; increased capacity by $178 million to $1.678 billion into 2018 Calpine Corporation (NYSE: CPN) today reported fourth quarter 2015 Adjusted EBITDA of $390 million, compared to $345 million in the prior year period, and Adjusted Free Cash Flow of $97 million, or $0.27 per diluted share, compared to $95 million, or $0.24 per diluted share, in the prior year period. The increases in Adjusted EBITDA and Adjusted Free Cash Flow were primarily due to higher Commodity Margin driven by higher contribution from hedges and hedging through our retail subsidiary acquired in October 2015, the acquisition of our Fore River Energy Center in November 2014, the commencement of operations at our Garrison Energy Center in June 2015 and higher regulatory capacity revenue in PJM. Net Loss1 for the fourth quarter of 2015 was $47 million, or $0.13 per diluted share, compared to Net Income1 of $210 million, or $0.54 per diluted share, in the prior year period. The decrease in Net Income1 was primarily due to lower unrealized gains on power hedges in the fourth quarter of 2015 compared to the prior year period. Net Income, As Adjusted2, for the fourth quarter of 2015 was $67 million compared to Net Loss, As Adjusted2, of $50 million in the prior year period. The increase in Net Income, As Adjusted2, was largely driven by an income tax benefit in the fourth quarter of 2015 primarily related to a legal entity restructuring and the recognition of a future tax benefit related to a tax credit. Full year 2015 Adjusted EBITDA was $1,976 million, compared to $1,949 million in the prior year, and Adjusted Free Cash Flow was $842 million, or $2.31 per diluted share, compared to $830 million, or $2.03 per diluted share, in the prior year. The increases in Adjusted EBITDA and Adjusted Free Cash Flow were primarily due to higher Commodity Margin mainly driven by higher contribution from hedges and increased generation. Net Income1 in 2015 was $235 million, or $0.64 per diluted share, compared to $946 million, or $2.31 per diluted share, in the prior year. The decrease in Net Income1 was primarily driven by a gain on the sale of six power plants in July 2014 that did not recur in 2015. Net Income, As Adjusted2, was $385 million in 2015 compared to $309 million in the prior year. The increase in Net Income, As Adjusted2, was largely driven by an income tax benefit in 2015 associated primarily with a legal entity restructuring and a tax credit, as previously discussed, as well as higher Commodity Margin, as previously discussed, partially offset by an increase in plant operating expense related to higher major maintenance expense resulting from our plant outage schedule. “Calpine has become known for delivering on its financial commitments, and I am pleased to report that 2015 was no exception,” said Thad Hill, Calpine’s President and Chief Executive Officer. “Despite the most volatile commodity markets in recent memory, in 2015 we achieved record Adjusted EBITDA and Adjusted Free Cash Flow Per Share, successfully meeting our guidance for the year. We did this by reinforcing our commitment to our longstanding values of operational excellence, customer focus and financial discipline. I could not be prouder of the Calpine team for its efforts. “With respect to our capital allocation program, we continue to make progress. Since October, we have balanced our expenditures between funding growth, including the acquisitions of Champion Energy and Granite Ridge Energy Center, and repaying debt, including the redemption of $120 million of our higher-interest notes. Overall, our capital allocation philosophy remains intact and will continue to include a mix of growth, share repurchases and debt reduction, the balance of which will vary over time depending upon the opportunity set. Fortunately, our strong cash flows continue to provide us with capital allocation flexibility as we consider the current environment and the opportunities it may present. “Power markets are evolving more today than at any point since deregulation, primarily due to sustained low natural gas prices, continued subsidization of renewable generation, a growing focus on resource reliability and the proliferation of environmental regulations. This evolution has weighed upon the public equity markets as investors consider its impacts. Our message in that debate is clear: a modern, flexible and clean fleet like Calpine’s is essential in each of our markets today and will be even more so in the power generation sector of the future. As a team, we are intently focused on capitalizing on the opportunities before us. “Looking at our 2016 financial guidance, we expect to achieve Adjusted EBITDA of $1.8 - $1.95 billion and Adjusted Free Cash Flow of $2.00 - $2.40 per share. I believe that our efforts in 2016 will further differentiate Calpine from the rest of the sector through the higher generation levels we are able to achieve in low gas price scenarios, the unparalleled quality of our assets which are capable of serving our markets for decades to come and the exercise of financial discipline.” __________ 1 Reported as Net Income (Loss) attributable to Calpine on our Consolidated Statements of Operations. 2 Refer to Table 1 for further detail of Net Income (Loss), As Adjusted. 3 Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants. 4 According to EEI Safety Survey (2014). 5 Excluding working capital adjustments. SUMMARY OF FINANCIAL PERFORMANCE Fourth Quarter Results Adjusted EBITDA for the fourth quarter of 2015 was $390 million compared to $345 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily related to an $82 million increase in Commodity Margin, partially offset by a $34 million increase in plant operating expense6. The increase in plant operating expense was primarily related to costs associated with the wildfire that damaged our Geysers assets in September 2015. The increase in Commodity Margin was primarily due to: Net Loss1 was $47 million for the fourth quarter of 2015, compared to Net Income1 of $210 million in the prior year period. The year-over-year decline in Net Income1 was primarily due to a decrease in unrealized gains on power hedges compared to the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $67 million in the fourth quarter of 2015 compared to a Net Loss, As Adjusted2, of $50 million in the prior year period. The year-over-year improvement in Net Income, As Adjusted2, was primarily driven by an income tax benefit related to a legal entity restructuring that resulted in a partial release of our valuation allowance associated with our net operating losses, as well as the recognition of a future tax benefit related to a tax credit associated with our capital expenditures. Adjusted Free Cash Flow was $97 million in the fourth quarter of 2015 compared to $95 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to an increase in Adjusted EBITDA, as previously discussed, partially offset by an increase in major maintenance expense resulting from our plant outage schedule. Full Year Results Adjusted EBITDA in 2015 was $1,976 million compared to $1,949 million in the prior year. The year-over-year increase in Adjusted EBITDA was primarily related to a $27 million increase in Commodity Margin. The increase in Commodity Margin was primarily due to: lower regulatory capacity revenue in PJM during the first five months of 2015, partially offset by higher regulatory capacity revenue in PJM during the remaining seven months of 2015. Net Income1 was $235 million in 2015, compared to $946 million in the prior year. The year-over-year decrease in Net Income1 was primarily due to a gain on the previously mentioned sale of the six power plants in our East region in July 2014 that did not recur in 2015. As detailed in Table 1, Net Income, As Adjusted2, was $385 million in 2015, compared to $309 million in the prior year. The year-over-year increase was driven largely by: Adjusted Free Cash Flow was $842 million in 2015, compared to $830 million in the prior year. Adjusted Free Cash Flow increased during the period primarily due to an increase in Adjusted EBITDA and a decrease in interest expense, partially offset by higher major maintenance expense, as previously discussed. __________ 6 Increase in plant operating expense excludes changes in major maintenance expense, stock-based compensation expense, non-cash loss on disposition of assets and other costs. See the table titled "Consolidated Adjusted EBITDA Reconciliation" for the actual amounts of these items for the three months ended December 31, 2015 and 2014. Table 1: Net Income (Loss), As Adjusted (in millions) __________ (1) Shown net of tax, assuming a 0% effective tax rate for these items. (2) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market (gain) loss also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. (3) Non-GAAP financial measure, see “Regulation G Reconciliations” for further discussion of Net Income (Loss), As Adjusted. REGIONAL SEGMENT REVIEW OF RESULTS Table 2: Commodity Margin by Segment (in millions) West Region Fourth Quarter: Commodity Margin in our West segment increased by $4 million in the fourth quarter of 2015 compared to the prior year period. Primary drivers were: Full Year: Commodity Margin in our West segment increased by $56 million in 2015, compared to the prior year. Primary drivers were: Texas Region Fourth Quarter: Commodity Margin in our Texas segment increased by $37 million in the fourth quarter of 2015 compared to the prior year period. Primary drivers were: Full Year: Commodity Margin in our Texas segment decreased by $24 million in 2015, compared to the prior year. Primary drivers were: East Region Fourth Quarter: Commodity Margin in our East segment increased by $41 million in the fourth quarter of 2015 compared to the prior year period. Primary drivers were: higher regulatory capacity revenue in PJM and a decrease in generation from our Mid-Atlantic power plants, partially offset by an increase in generation from our power plants in New England and the Southeast. Full Year: Commodity Margin in our East segment increased by $76 million in 2015, compared to the prior year period, after excluding a decrease of $81 million resulting from the sale of six power plants with a total capacity of 3,498 MW on July 3, 2014. Primary drivers were: + lower regulatory capacity revenue in PJM during the first five months of 2015, partially offset by higher regulatory capacity revenue in PJM during the remaining seven months of 2015. LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES Table 3: Liquidity (in millions) ____________ (1) Includes $35 million and $47 million of margin deposits posted with us by our counterparties at December 31, 2015 and 2014, respectively. (2) On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 2020 and increasing the capacity by an additional $178 million to $1.678 billion through June 2018, reverting back to $1.520 billion through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 2020. (3) Subsequent to year-end, we used $500 million of liquidity to complete the acquisition of Granite Ridge Energy Center, excluding working capital adjustments. Liquidity was approximately $2.4 billion as of December 31, 2015. Cash and cash equivalents increased during 2015 primarily due to $842 million of Adjusted Free Cash Flow earned in 2015, as well as the receipt of proceeds related to our 2023 First Lien Term Loan and 2024 Senior Unsecured Notes. These inflows were partially offset by repurchases of our common stock, ongoing investments in announced growth projects, the acquisition of Champion Energy and the repurchase and redemption of a portion of our 2023 First Lien Notes. Table 4: Cash Flow Activities (in millions) Cash provided by operating activities was $863 million in 2015 compared to $854 million in the prior year. The increase in cash provided by operating activities was primarily due to an increase in income from operations, adjusted for non-cash items, and a reduction in debt modification and extinguishment payments, partially offset by an increase in working capital largely associated with changes in margining requirements. Cash used in investing activities was $841 million during 2015, compared to $84 million in the prior year. In 2014, we received approximately $1.57 billion of proceeds from the sale of six power plants in our East region, partially offset by approximately $1.2 billion used to purchase our Fore River and Guadalupe Energy Centers. Corresponding 2015 activity included the purchase of Champion Energy for approximately $240 million plus working capital adjustments and an increase in capital expenditures for construction projects and outages. Cash provided by financing activities was $167 million during 2015 and was primarily related to proceeds from the issuances of our 2024 Senior Unsecured Notes, 2022 First Lien Term Loan and 2023 First Lien Term Loan. These inflows were substantially offset by payments associated with the execution of our share repurchase program, the repayment of our 2018 First Lien Term Loan, and the repurchase and redemption of a portion of our 2023 First Lien Notes. CAPITAL ALLOCATION Share Repurchase Program Returning capital to our shareholders by repurchasing shares of our common stock is an integral component of our capital allocation program. We view our stock as an attractive investment opportunity, and we use the projected returns from share repurchases as the benchmark against which all other investment decisions are measured. Since 2011, we have repurchased approximately $2.8 billion of our common stock, representing approximately 29% of shares outstanding.7 In 2015, we repurchased a total of 26.6 million shares of our common stock for approximately $529 million at an average price of $19.87 per share. Acquisition of Granite Ridge Energy Center In February 2016, we completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), for approximately $500 million, excluding working capital adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant meaningfully increases our capacity in the constrained New England market. The power plant features two combustion turbines, two heat recovery steam generators and one steam turbine. We funded the acquisition with a combination of cash on hand and financing. Acquisition of Champion Energy In October 2015, we acquired Champion Energy for approximately $240 million, excluding working capital adjustments. The addition of this well-established retail sales organization is consistent with our stated goal of getting closer to our end-use customers and provides us a valuable sales channel for directly reaching a much greater portion of the load we seek to serve. 2023 First Lien Notes In December 2015, we used cash on hand to redeem 10% of the original aggregate principal amount of our 7.875% First Lien Notes due 2023, plus accrued and unpaid interest. The remaining principal on these notes was $573 million as of December 31, 2015. 2023 First Lien Term Loan In December 2015, we entered into a $550 million First Lien Term Loan due 2023 and utilized $325 million of the proceeds received, together with cash on hand, to purchase Granite Ridge Energy Center. We intend to use the remaining proceeds to repay project and corporate debt and for general corporate purposes. 2022 First Lien Term Loan In May 2015, we repaid our 2018 First Lien Term Loans with the proceeds from a newly issued 2022 First Lien Term Loan which extended the maturity and reduced the interest rate on approximately $1.6 billion of corporate debt. 2024 Senior Unsecured Notes In February 2015, we issued $650 million of 5.5% Senior Unsecured Notes due 2024 to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase approximately $147 million of our 7.785% First Lien Notes due 2023 and for general corporate purposes. Corporate Revolver Extension and Expansion On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 27, 2020, and increasing the capacity by an additional $178 million to $1.678 billion through June 27, 2018, reverting back to $1.520 billion through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 27, 2020. Project Debt In November 2015, we refinanced and upsized our Steamboat project debt, which lowered the interest rate and extended the maturity by two years to November 2019. In December 2015, we entered into an agreement with one of the two lessors of our Pasadena Power Plant to purchase their 50% interest, which will result in a reduction of our project debt of approximately $50 million. The transaction is expected to close during the second quarter of 2016. ___________ 7 Based upon 490.6 million shares outstanding as of June 30, 2011, immediately prior to announcement of our repurchase program. Growth and Portfolio Management East: Garrison Energy Center: Garrison Energy Center commenced commercial operations in June 2015, bringing online approximately 309 MW of combined-cycle, natural gas-fired capacity with dual-fuel capability. The power plant features one combustion turbine, one heat recovery steam generator and one steam turbine. We are in the early stages of development of a second phase of the Garrison Energy Center that will add approximately 430 MW of dual-fuel, combined-cycle capacity. PJM has completed its feasibility study of the project and the system impact study is underway. York 2 Energy Center: York 2 Energy Center is a 760 MW dual-fuel, combined-cycle project that will be co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. The project’s capacity cleared PJM’s 2017/2018 and 2018/2019 base residual auctions. The project is now under construction, and we expect commercial operations to commence during the second quarter of 2017. PJM has completed the interconnection study process for an additional 68 MW of planned capacity at the York 2 Energy Center. This incremental 68 MW of planned capacity cleared the 2018/19 base residual auction. Mankato Power Plant Expansion: By order dated February 5, 2015, the Minnesota Public Utilities Commission concluded a competitive resource acquisition proceeding and selected a 345 MW expansion of our Mankato Power Plant, authorizing execution of a 20-year PPA between Calpine and Xcel Energy. The PPA was executed in April 2015 and remains subject to approval by the North Dakota Public Service Commission. Commercial operation of the expanded capacity may commence as early as 2019, subject to requisite regulatory approvals and applicable contract conditions. PJM and ISO-NE Development Opportunities: We are currently evaluating opportunities to develop additional projects in the PJM and ISO-NE market areas that feature cost advantages such as existing infrastructure and favorable transmission queue positions. These projects are continuing to advance entitlements (such as permits, zoning and transmission) for their potential future development when economical. Osprey Energy Center: During the fourth quarter of 2014,we executed an asset sale agreement for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. In accordance with the asset sale agreement, the sale will be consummated in January 2017 upon the conclusion of a 27-month PPA. In July 2015, the transaction was approved by the FERC and the Florida Public Service Commission. This sale represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities. Texas: Guadalupe Peaking Energy Center: In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) that will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center. Under the terms of the agreement, construction of the Guadalupe Peaking Energy Center (“GPEC”) may commence at our discretion, so long as the power plant reaches commercial operation by June 1, 2019. When the power plant begins commercial operation, GVEC will purchase a 50% ownership interest in GPEC. Once built, GPEC will feature two fast-ramping combustion turbines capable of responding to peaks in power demand. This project represents a mutually beneficial response to our customer’s desire to have direct access to peaking generation resources, as it leverages the benefits of our existing site and development rights and our construction and operating expertise, as well as our customer’s ability to fund its investment at attractive rates, all while affording us the flexibility of timing the plant’s construction in response to market pricing signals. All Segments: Turbine Modernization: We continue to move forward with our turbine modernization program. Through December 31, 2015, we have completed the upgrade of 13 Siemens and eight GE turbines totaling approximately 210 MW and have committed to upgrade three additional turbines. In addition, we have begun a program to update our dual-fueled turbines at certain of our East Region power plants. OPERATIONS UPDATE 2015 Power Operations Achievements Safety Performance:— Maintained top quartile8 safety metrics: 0.73 total recordable incident rate Availability Performance:— Achieved low fleetwide forced outage factor: 2.3%— Delivered exceptional fleetwide starting reliability: 98.3% Power Generation:— Seven gas-fired plants with full-year capacity factors greater than 70%: Channel, Hermiston, Morgan, Pasadena, Pastoria, Pine Bluff and Stony Brook— Texas Region: Highest full year generation volume on record— King City Cogeneration Plant: 100% starting reliability and 0% forced outage factor in 2015 Geysers Wildfire Impact In September 2015, a wildfire spread to our Geysers assets in Lake and Sonoma counties, California, affecting five of our 14 power plants in the region which sustained damage to ancillary structures such as cooling towers and communication/electric deliverability infrastructure. The wildfire was subsequently contained, and our Geysers assets are generating renewable power for our customers at approximately three-quarters of the normal operating capacity. We expect our insurance program to cover the repair and replacement costs as well as our net revenue losses after deductibles are met. As a result, we do not anticipate that the wildfire will have a material impact on our financial condition, results of operations or cash flows. Further, once repairs are completed, we expect generation capacity at our Geysers assets to be restored to pre-fire levels.Our 2015 financial results reflect an impact of approximately $36 million associated with the wildfire, including approximately $20 million in net revenue losses and approximately $16 million of plant operating expense related to property damage. We expect economic impact in 2016, if any, to be minimal. 2015 Commercial Operations Achievements: Champion Energy: In October 2015, we acquired retail electric provider Champion Energy, consistent with our stated goal of getting closer to our end-use customers. In 2015, Champion Energy served approximately 22 million MWh of customer load consisting of approximately 2.1 million annualized residential customer equivalents at December 31, 2015, concentrated in Texas, the Northeast and Mid-Atlantic where Calpine has a substantial power generation presence. Customer Relationships: During 2015, we entered into the following:West:— A PPA with Marin Clean Energy to provide up to 65 MW of power from our Delta Energy Center and other northern California power plants commencing in April 2015 and extending through December 2017— A ten-year PPA with Southern California Edison for 50 MW of capacity and renewable energy from our Geysers assets commencing in January 2018; the PPA remains subject to approval by the California Public Utilities Commission (CPUC)— Our ten-year PPA with Southern California Edison for 225 MW of capacity and renewable energy from our Geysers assets commencing in June 2017 was approved by the CPUC— A one-year resource adequacy contract with Southern California Edison for 238 MW from our Pastoria Energy Center commencing in January 2018— A three-year PPA with the San Francisco Public Utilities Commission to provide, on average, approximately 43 MW of energy and renewable energy annually, commencing in May 2016Texas:— A three-year PPA with Brazos Electric Power Cooperative to provide 300 MW of energy from our Texas power plant fleet commencing in January 2016— A three-year PPA with Pedernales Electric Cooperative to provide approximately 140 MW of energy from our Texas power plant fleet commencing in January 2017— A two-year PPA with Guadalupe Valley Electric Cooperative to provide approximately 270 MW of energy from our Texas power plant fleet commencing in June 2017. The execution of this PPA will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center— We extended our existing PPA with the South Texas Electric Cooperative to supply the Magic Valley Electric Cooperative’s full load requirements for ten years beyond 2021. Magic Valley Electric Cooperative’s peak summer load in 2015 was 490 MWEast:— A 20-year PPA with Xcel Energy to provide up to 345 MW of capacity and energy from our Mankato Power Plant expansion when commercial operations commence and transmission-related upgrades have been completed— A ten-year PPA with Tennessee Valley Authority for 615 MW of energy and capacity from our Morgan Energy Center commencing in February 2016 ___________ 8 According to EEI Safety Survey (2014). 2016 FINANCIAL OUTLOOK Debt amortization and repayment(3) (435 (1) Includes projected major maintenance expense of $270 million and maintenance capital expenditures of $140 million in 2016. Capital expenditures exclude major construction and development projects. (2) Includes commitment, letter of credit and other fees from consolidated and unconsolidated investments, net of capitalized interest and interest income. (3) Includes $210 million of recurring amortization, as well as $225 million of proceeds from our 2023 First Lien Term Loan that we intend to use to repay project and corporate debt. (4) Excluding working capital adjustments. As detailed above, today we are reaffirming our 2016 guidance. We expect Adjusted EBITDA of $1.8 billion to $1.95 billion and Adjusted Free Cash Flow of $710 million to $860 million, or $2.00 to $2.40 per share. We expect to invest $285 million in our growth projects throughout 2016, primarily the construction of York 2 Energy Center. INVESTOR CONFERENCE CALL AND WEBCAST We will host a conference call to discuss our financial and operating results for the fourth quarter and full year 2015 on Friday, February 12, 2016, at 10 a.m. Eastern time / 9 a.m. Central time. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing (800) 446-1671 in the U.S. or (847) 413-3362 outside the U.S. The confirmation code is 41578892. An archived recording of the call will be made available for a limited time on our website or by dialing (888) 843-7419 in the U.S. or (630) 652-3042 outside the U.S. and providing confirmation code 41578892. Presentation materials to accompany the conference call will be available on our website on February 12, 2016. ABOUT CALPINE Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources. Our fleet of 84 power plants in operation or under construction represents more than 27,000 megawatts of generation capacity. Through wholesale power operations and our retail business, Champion Energy, we serve customers in 20 states and Canada. We specialize in developing, constructing, owning and operating natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our clean, efficient, modern and flexible fleet is uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. Please visit www.calpine.com to learn more about why Calpine is a generation ahead - today, or visit www.championenergyservices.com for details on Champion’s award-winning retail electric services. Calpine’s Annual Report on Form 10-K for the year ended December 31, 2015, has been filed with the Securities and Exchange Commission (SEC) and is available on the SEC’s website at www.sec.gov. FORWARD-LOOKING INFORMATION In addition to historical information, this release contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this release. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to: Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability and extent to which we hedge risks; Laws, regulations and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate; Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our First Lien Notes, Senior Unsecured Notes, Corporate Revolving Facility, First Lien Term Loans, CCFC Term Loans and other existing financing obligations; Risks associated with the operation, construction and development of power plants, including unscheduled outages or delays and plant efficiencies; Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of water to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources; Competition, including renewable sources of power and risks associated with marketing and selling power in the evolving energy markets; Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies); The expiration or early termination of our PPAs and the related results on revenues; Future capacity revenue may not occur at expected levels; Natural disasters, such as hurricanes, earthquakes, droughts, wildfires and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants or retail operations serve and our corporate headquarters; Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power; Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions; Our ability to attract, motivate and retain key employees; Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and Other risks identified in this press release, in our Annual Report on Form 10-K for the year ended December 31, 2015, and in other reports filed by us with the SEC. Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise. CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS December 31, 2015 and 2014 (in millions, except share and per share amounts) CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2015 and 2014 (in millions) Additions to property, plant and equipment through capital leases __________ (1) Includes depreciation and amortization included in commodity revenue, commodity expense and interest expense on our Consolidated Statements of Operations. REGULATION G RECONCILIATIONS In addition to disclosing financial results in accordance with U.S. GAAP, the accompanying fourth quarter 2015 earnings release contains non-GAAP financial measures. Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These non-GAAP measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance and the financial results calculated in accordance with U.S. GAAP and reconciliations from these results should be carefully evaluated. Net Income (Loss), As Adjusted, represents net income (loss) attributable to Calpine, adjusted for certain non-cash and non-recurring items as previously detailed in Table 1, including mark-to-market (gain) loss on derivatives, debt modification and extinguishment costs and other adjustments. Net Income (Loss), As Adjusted, is presented because we believe it is a useful tool for assessing the operating performance of our company in the current period. Net Income (Loss), As Adjusted, is not intended to represent net income (loss), the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, revenue from renewable energy credits, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Adjusted EBITDA represents net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization, adjusted for certain non-cash and non-recurring items as detailed in the following reconciliation. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. We believe Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase, modification or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any extraordinary, unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends. In summary, our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance. Adjusted Free Cash Flow represents net income before interest, taxes, depreciation and amortization, as adjusted, less operating lease payments, major maintenance expense and maintenance capital expenditures, net cash interest, cash taxes and other adjustments, including non-recurring items. Adjusted Free Cash Flow is presented because we believe it is a useful tool for assessing the financial performance of our company in the current period. Adjusted Free Cash Flow is a performance measure and is not intended to represent net income (loss), the most directly comparable U.S. GAAP measure, or liquidity and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin Reconciliation The following tables reconcile our Commodity Margin to its U.S. GAAP results for the three months ended December 31, 2015 and 2014 (in millions): The following tables reconcile our Commodity Margin to its U.S. GAAP results for the years ended December 31, 2015 and 2014 (in millions): _________ (1) Includes $(1) million and $2 million of lease levelization and $9 million and $3 million of amortization expense for the three months ended December 31, 2015 and 2014, respectively. (2) Our East segment includes Commodity Margin of $81 million for the year ended December 31, 2014, related to the six power plants in our East segment that were sold in July 2014. (3) Includes $(2) million and $(5) million of lease levelization and $20 million and $14 million of amortization expense for the years ended December 31, 2015 and 2014, respectively. Consolidated Adjusted EBITDA Reconciliation In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our net income attributable to Calpine for the three months and years ended December 31, 2015 and 2014, as reported under U.S. GAAP (in millions): _________ (1) Depreciation and amortization expense in the income from operations calculation on our Consolidated Statements of Operations excludes amortization of other assets. (2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for the three months and years ended December 31, 2015 and 2014. (3) Includes $74 million and $272 million in major maintenance expense for the three months and year ended December 31, 2015, respectively, and $57 million and $189 million in maintenance capital expenditures for the three months and year ended December 31, 2015, respectively. Includes $47 million and $242 million in major maintenance expense for the three months and year ended December 31, 2014, respectively, and $37 million and $168 million in maintenance capital expenditures for the three months and year ended December 31, 2014, respectively. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (5) Excludes a decrease in working capital of $115 million and an increase of $129 million for the three months and year ended December 31, 2015, respectively, and a decrease in working capital of $136 million and $118 million for the three months and year ended December 31, 2014, respectively. Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance. (6) Adjusted EBITDA related to the six power plants sold in our East segment on July 3, 2014, was nil and $43 million for the three months and year ended December 31, 2014, respectively. In the following table, we have reconciled our Adjusted EBITDA to our Commodity Margin, both of which are non-GAAP measures, for the three months and years ended December 31, 2015 and 2014. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. Amounts below are shown exclusive of the noncontrolling interest (in millions): _________ (1) Shown net of major maintenance expense, stock-based compensation expense, non-cash loss on dispositions of assets and other costs. (2) Shown net of stock-based compensation expense and other costs. (3) Shown net of operating lease expense, amortization and other costs. Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance (in millions) _________ (1) For purposes of Net Income guidance reconciliation, mark-to-market adjustments are assumed to be nil. (2) Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, income tax expense and other items. (3) Includes projected major maintenance expense of $270 million and maintenance capital expenditures of $140 million. Capital expenditures exclude major construction and development projects. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. OPERATING PERFORMANCE METRICS The table below shows the operating performance metrics for the periods presented: ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us.

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE: CPN): Summary of Third Quarter 2015 Financial Results (in millions, except per share amounts): ) % ) % ) % ) % Narrowing 2015 and Providing 2016 Full Year Guidance (in millions, except per share amounts): Recent Achievements: Power Operations:— Generated a third quarter record of more than 33 million MWh3— Achieved low third quarter fleetwide forced outage factor: 1.8%— Delivered strong fleetwide starting reliability: 98.6% Customer-Oriented Origination Efforts:— Completed acquisition of leading retail provider Champion Energy for $240 million4— Executed a 238 MW one-year resource adequacy contract with Southern California Edison for our Pastoria Energy Center Capital Allocation Progress:— Announced acquisition of Granite Ridge Energy Center, a combined-cycle power plant in New Hampshire with a nameplate capacity of 745 MW, for $500 million4, or approximately $671/kW— Completed approximately $529 million of share repurchases year-to-date, reducing our share count by approximately 7%; an incremental $54 million since last call— Issued notice of intent to redeem 10% of our 2023 First Lien Notes Calpine Corporation (NYSE: CPN) today reported third quarter 2015 Adjusted EBITDA of $791 million, compared to $745 million in the prior year period, and Adjusted Free Cash Flow of $576 million, or $1.61 per diluted share, compared to $506 million, or $1.26 per diluted share, in the prior year period. Net Income1 for the third quarter of 2015 was $273 million, or $0.76 per diluted share, compared to $614 million, or $1.52 per diluted share, in the prior year period. Net Income, As Adjusted2, for the third quarter of 2015 was $347 million compared to $306 million in the prior year period. The increases in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted2, were primarily due to higher Commodity Margin driven by the acquisition of our Fore River Energy Center in November 2014 and the commencement of operations at our Garrison Energy Center in June 2015, as well as higher regulatory capacity revenue in PJM. Year-to-date 2015 Adjusted EBITDA was $1,586 million, compared to $1,604 million in the prior year period, and Adjusted Free Cash Flow was $745 million, or $2.02 per diluted share, compared to $735 million, or $1.77 per diluted share, in the prior year period. Net Income1 for the first nine months of 2015 was $282 million, or $0.77 per diluted share, compared to $736 million, or $1.77 per diluted share, in the prior year period. Net Income, As Adjusted2, for the first nine months of 2015 was $318 million compared to $359 million in the prior year period. The decreases in Adjusted EBITDA and Net Income, As Adjusted2, were primarily due to lower Commodity Margin driven largely by a significant decrease in power and natural gas prices in our East region in the first quarter of 2015, given the unusually high price levels experienced during the polar vortex events in the prior year period, as well as net portfolio changes and lower regulatory capacity revenue in PJM. The increase in Adjusted Free Cash Flow was due to lower interest expense compared to the prior year period, which more than offset the decline in Adjusted EBITDA. “I am pleased to report another solid quarter, with record generation volume of 33 million MWh, top quartile safety performance and continued commercial success,” said Thad Hill, Calpine’s President and Chief Executive Officer. “As a result, we are narrowing our 2015 Adjusted EBITDA guidance to a range of $1.965 billion to $2.0 billion. This is within our prior guidance range and reflects an adjustment for the projected impact of the Valley wildfire in Northern California on The Geysers geothermal facilities, which we previously announced. I would like to recognize our team at The Geysers whose extraordinary efforts have resulted in production already reaching approximately 575 net MW, or nearly 80% of full capacity. “With respect to capital allocation, during the past quarter we completed the acquisition of retailer Champion Energy, announced the acquisition of the Granite Ridge Energy Center in New England, and continued to return capital to shareholders through share repurchases. These are further examples of our ability to source and execute accretive transactions. “Looking to next year, we are pleased to introduce 2016 Adjusted EBITDA of $1.8 billion to $1.95 billion. Despite a decrease in year-over-year hedge value and lower capacity prices, through diligent cost control and operational excellence, we expect to deliver $2.00 to $2.40 of Adjusted Free Cash Flow Per Share. Based on the midpoint of our 2016 guidance range, our Free Cash Flow yield of approximately 15% at the current share price is attractive by comparison to the past three years’ average of 9%. While the Free Cash Flow yield is ultimately subject to market forces outside of our control, we believe that as macro commodity concerns ease and investors differentiate between companies, our currently high yield should return to the norm, making today an attractive entry point. “I believe that the Calpine value proposition is even more compelling when taking into account our outlook over the next several years and the evolution of our business. First, there is as much as $250 million of known favorable drivers on the horizon between 2016 and 2018, without taking into account changes in natural gas and power markets – including a recovery in the Texas market – or new hedges. Secondly, our increased production this quarter affirms a clear trend over the near- to mid-term toward greater need for and utilization of our flexible and reliable natural gas-fired fleet. This trend is supported by abundant natural gas and penetration of renewables putting pressure on coal and nuclear baseload generation, increasingly stringent environmental regulation further challenging coal generation, the need to maintain reliability of supply to support the integration of intermittent renewables, and the emergence of pay-for-performance initiatives like the PJM Capacity Performance reform. In conclusion, as I look at the opportunities before us, I am excited about the outlook for Calpine and its shareholders as we continue to create value.” 1 Reported as Net Income attributable to Calpine on our Consolidated Condensed Statements of Operations. 2 Refer to Table 1 for further detail of Net Income, As Adjusted. 3 Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants. 4 Excluding working capital adjustments. SUMMARY OF FINANCIAL PERFORMANCE Third Quarter Results Adjusted EBITDA for the third quarter of 2015 was $791 million compared to $745 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily related to a $30 million increase in Commodity Margin, as well as an $11 million decrease in plant operating expense5. The increase in Commodity Margin was primarily due to: Net Income1 was $273 million for the third quarter of 2015, compared to $614 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $347 million in the third quarter of 2015 compared to $306 million in the prior year period. The year-over-year improvement in Net Income, As Adjusted, was driven largely by higher Commodity Margin and lower plant operating expense, as previously discussed. Adjusted Free Cash Flow was $576 million in the third quarter of 2015 compared to $506 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to the increase in Adjusted EBITDA, as previously discussed. Year-to-Date Results Adjusted EBITDA for the nine months ended September 30, 2015, was $1,586 million compared to $1,604 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to a $55 million decrease in Commodity Margin, partially offset by a $29 million decrease in plant operating expense5 as a result of net portfolio changes as well as lower equipment failure costs related to outages. The decrease in Commodity Margin was primarily due to: Net Income1 was $282 million for the nine months ended September 30, 2015, compared to $736 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $318 million in the nine months ended September 30, 2015, compared to $359 million in the prior year period. The year-over-year decline was driven largely by: higher depreciation and amortization expense driven primarily by portfolio changes, partially offset by lower plant operating expense as a result of portfolio changes, as well as a decrease in equipment failure costs related to outages and Adjusted Free Cash Flow was $745 million for the nine months ended September 30, 2015, compared to $735 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to lower interest expense, which more than offset the decrease in Adjusted EBITDA. 5 Decrease 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 and nine months ended September 30, 2015 and 2014. Table 1: Net Income, As Adjusted (in millions) __________ (1) Shown net of tax, assuming a 0% effective tax rate for these items. (2) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market (gain) loss also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. (3) Non-GAAP financial measure, see “Regulation G Reconciliations” for further discussion of Net Income, As Adjusted. REGIONAL SEGMENT REVIEW OF RESULTS Table 2: Commodity Margin by Segment (in millions) West Region Third Quarter: Commodity Margin in our West segment increased by $24 million in the third quarter of 2015 compared to the prior year period. Primary drivers were: Year-to-date: Commodity Margin in our West segment increased by $52 million for the nine months ended September 30, 2015, compared to the prior year period. Primary drivers were: Texas Region Third Quarter: Commodity Margin in our Texas segment decreased by $82 million in the third quarter of 2015 compared to the prior year period. Primary drivers were: Year-to-date: Commodity Margin in our Texas segment decreased by $61 million for the nine months ended September 30, 2015, compared to the prior year period. Primary drivers were: East Region Third Quarter: Commodity Margin in our East segment increased by $88 million in the third quarter of 2015 compared to the prior year period. Primary drivers were: Year-to-date: Commodity Margin in our East segment increased by $35 million for the nine months ended September 30, 2015, compared to the prior year period, after excluding a decrease of $81 million resulting from the sale of six power plants with a total capacity of 3,498 MW on July 3, 2014. Primary drivers were: a significant decrease in power and natural gas prices in the first quarter of 2015 compared to the prior year period, given the unusually high price levels experienced during the polar vortex events in the first quarter of 2014, and LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES Table 3: Liquidity (in millions) ____________ (1) Includes $15 million and $47 million of margin deposits posted with us by our counterparties at September 30, 2015, and December 31, 2014, respectively. Liquidity was approximately $2.3 billion as of September 30, 2015. Cash and cash equivalents decreased during the first nine months of 2015 primarily due to repurchases of our common stock, ongoing investments in announced growth projects and the repurchase of a portion of our outstanding 2023 First Lien Notes, partially offset by the receipt of proceeds related to the issuance of our 5.5% Senior Unsecured Notes due 2024 in February 2015. Table 4: Cash Flow Activities (in millions) Cash provided by operating activities in the nine months ended September 30, 2015, was $548 million compared to $504 million in the prior year period. The increase in cash provided by operating activities was primarily due to a decrease in cash paid for debt modification and extinguishment due to a lower amount of refinancing and repayment activities in the first nine months of 2015. In addition, cash paid for interest decreased, primarily due to refinancing activity and the timing of interest payments. The increase in cash provided by operating activities was partially offset by an increase in working capital employed primarily due to net margin requirements and greater purchases of environmental allowances. Cash used in investing activities was $450 million during the nine months ended September 30, 2015, compared to cash provided by investing activities of $550 million provided in the prior year period. The decrease was primarily due to $1.57 billion of proceeds from the July 2014 sale of six of our power plants in the East segment, partially offset by the $656 million purchase of our Guadalupe Energy Center in February 2014, for which there were no corresponding activities in the first nine months of 2015. Cash used in financing activities was $156 million during the nine months ended September 30, 2015, and were primarily related to payments associated with the execution of our share repurchase program, the repurchase of a portion of our 2023 First Lien Notes and the repayment of our 2018 First Lien Term Loan. These outflows were substantially offset by proceeds from the issuance of our 2024 Senior Unsecured Notes and the issuance of our 2022 First Lien Term Loan. CAPITAL ALLOCATION Acquisition of Granite Ridge Energy Center In October 2015, we entered into an agreement to purchase Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW, for approximately $500 million, excluding working capital adjustments. The addition of this clean, modern, efficient, natural gas combined-cycle plant in Londonderry, New Hampshire, meaningfully increases our capacity in the tightening New England market. The power plant features two combustion turbines, two heat recovery steam generators and one steam turbine. We expect the transaction to close in the first quarter of 2016, with our guidance reflecting a February 1, 2016, close date. We expect to fund the purchase with a combination of cash on hand and financing. Acquisition of Champion Energy In October 2015, we completed the acquisition of Champion Energy for approximately $240 million, excluding working capital adjustments. Champion Energy, a leading retail electric provider, is expected to serve approximately 22 million MWh of commercial, industrial and residential customer load in 2015, concentrated in Texas, PJM and the Northeast U.S. where Calpine has a substantial power generation presence. The addition of this well-established retail sales organization is expected to provide us an important outlet for directly reaching a much greater portion of the load we serve. 2023 First Lien Notes In October 2015, we issued notice to the holders of our 2023 First Lien Notes of our intent to redeem 10% of the original aggregate principal amount, plus accrued and unpaid interest. We intend to use cash on hand to fund the redemption. Share Repurchase Program Returning capital to our shareholders by repurchasing shares of our common stock is an integral component of our capital allocation program. We view our stock as an attractive investment opportunity, and we use the projected returns from share repurchases as the benchmark against which all other investment decisions are measured. Since 2011, we have repurchased approximately $2.8 billion of our common stock, representing approximately 29% of shares outstanding.6 In 2015, through the issuance of this release, we have repurchased a total of 26.6 million shares of our common stock for approximately $529 million at an average price of $19.87 per share. 6 Based upon 490.6 million shares outstanding as of June 30, 2011, immediately prior to announcement of our repurchase program. Growth and Portfolio Management Texas: Guadalupe Peaking Energy Center: In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) that will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center. Under the terms of the agreement, construction of the Guadalupe Peaking Energy Center (“GPEC”) may commence at our discretion, so long as the power plant reaches commercial operation between the dates of June 1, 2017, and 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. East: Garrison Energy Center: Garrison Energy Center commenced commercial operations in June 2015, bringing online approximately 309 MW of combined-cycle, natural gas-fired capacity. The power plant features one combustion turbine, one heat recovery steam generator and one steam turbine and is expected to be dual fuel capable by this winter. We are in the early stages of development of a second phase of the Garrison Energy Center. York 2 Energy Center: York 2 Energy Center is a 760 MW dual fuel combined-cycle project that will be co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. The project’s capacity cleared PJM’s 2017/2018 and 2018/2019 base residual auctions. The project is now under construction, and we expect commercial operations to commence during the second quarter of 2017. PJM has completed the interconnection study process for an additional 70 MW of planned capacity at the York 2 Energy Center. This incremental 70 MW of planned capacity cleared the 2018/2019 base residual auction. Mankato Power Plant Expansion: By order dated February 5, 2015, the Minnesota Public Utilities Commission concluded a competitive resource acquisition proceeding and selected a 345 MW expansion of our Mankato Power Plant, authorizing execution of a 20-year PPA between Calpine and Xcel Energy. The PPA was executed in April 2015 and remains subject to approval by the North Dakota Public Service Commission. Commercial operation of the expanded capacity may commence as early as 2019, subject to requisite regulatory approvals and applicable contract conditions. PJM and ISO-NE Development Opportunities: We are currently evaluating opportunities to develop additional projects in the PJM and ISO-NE market areas that feature cost advantages such as existing infrastructure and favorable transmission queue positions. These projects are continuing to advance entitlements (such as permits, zoning and transmission) for their potential future development when economical. Osprey Energy Center: During the first quarter of 2014, we executed an asset sale agreement for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. In accordance with the asset sale agreement, the sale will be consummated in January 2017 upon the conclusion of a 27-month PPA. In July 2015, the transaction was approved by the FERC and the Florida Public Service Commission. This sale represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities. All Segments: Turbine Modernization: We continue to move forward with our turbine modernization program. Through September 30, 2015, 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. OPERATIONS UPDATE Third Quarter 2015 Power Operations Achievements Safety Performance:— Maintained top quartile7 safety metrics: 0.54 total recordable incident rate Availability Performance:— Achieved low fleetwide forced outage factor: 1.8%— Delivered exceptional fleetwide starting reliability: 98.6% Power Generation:— Seven gas-fired plants with third quarter capacity factors greater than 80%: Bosque, Hermiston, Morgan, Otay Mesa, Pasadena, Pastoria, Stony Brook— Hermiston: 0% forced outage factor, 0 starts, 93% capacity factor Geysers Wildfire Impact In September 2015, a wildfire spread to our Geysers assets in Lake and Sonoma Counties, California, affecting five of our 14 power plants in the region which sustained damage to ancillary structures such as cooling towers and communication/electric deliverability infrastructure. The wildfire has since been contained, and our Geysers assets are generating renewable power for our customers at approximately three-quarters of the normal operating capacity. We expect our insurance program to cover the repair and replacement costs as well as our net revenue losses after deductibles are met. As a result, we do not anticipate that the wildfire will have a material impact on our financial condition, results of operations or cash flows. Third Quarter 2015 Commercial Operations Achievements: Customer-oriented Growth:— Closed accretive acquisition of retail electric provider Champion Energy for $240 million4, consistent with our stated goal of getting closer to our end-use customers— Entered into a new one-year resource adequacy contract with Southern California Edison for 238 MW from our Pastoria Energy Center commencing in January 2018 7 According to EEI Safety Survey (2014). 2015 & 2016 FINANCIAL OUTLOOK (in millions, except per share amounts) (1) Includes projected major maintenance expense of $280 million and maintenance capital expenditures of $180 million in 2015 and major maintenance expense of $270 million and maintenance capital expenditures of $140 million in 2016. Capital expenditures exclude major construction and development projects. (2) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (3) 2015 amount includes scheduled amortization of approximately $193 million, the repurchase of approximately $147 million of our 2023 First Lien Notes in February 2015 and expected exercise of 10% call feature on 2023 First Lien Notes of approximately $120 million. (4) Subject to working capital adjustments. Acquisition of Granite Ridge assumed to close on February 1, 2016, for purposes of guidance. As detailed above, today we are narrowing our 2015 guidance. After incorporating the impacts of the wildfire in Northern California that affected our Geysers assets, we now expect Adjusted EBITDA of $1.965 billion to $2.0 billion and Adjusted Free Cash Flow of $825 million to $860 million, or $2.25 to $2.35 per share. We also expect to invest $355 million in our ongoing growth-related projects during the year, having now completed construction of our Garrison Energy Center and commenced construction of our York 2 Energy Center. We are also initiating guidance for 2016. We expected Adjusted EBITDA of $1.8 billion to $1.95 billion and Adjusted Free Cash Flow of $710 million to $860 million, or $2.00 to $2.40 per share. We expect to invest $285 million in our ongoing growth-related projects throughout 2016, primarily the construction of our York 2 Energy Center. INVESTOR CONFERENCE CALL AND WEBCAST We will host a conference call to discuss our financial and operating results for the third quarter of 2015 on Friday, October 30, 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 40715785. 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 40715785. Presentation materials to accompany the conference call will be available on our website on October 30, 2015. ABOUT CALPINE Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources. Our fleet of 83 power plants in operation or under construction represents nearly 27,000 megawatts of generation capacity. Through wholesale power operations and our retail business, Champion Energy, we serve customers in 19 states and Canada. We specialize in developing, constructing, owning and operating natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our clean, efficient, modern and flexible fleet is uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. Please visit www.calpine.com to learn more about why Calpine is a generation ahead - today, or visit www.championenergyservices.com for details on Champion's award-winning retail electric services. Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, 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 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, droughts, wildfires and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants or retail operations serve and our corporate headquarters; Disruptions in or limitations on the transportation of natural gas, 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, in our 2014 Form 10-K, our Quarterly Report on Form 10Q for the quarter ended September 30, 2015, and in other reports filed by us with the SEC. Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise. CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (Unaudited) CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) 1,592 420 __________ (1) Includes depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated Condensed Statements of Operations. REGULATION G RECONCILIATIONS In addition to disclosing financial results in accordance with U.S. GAAP, the accompanying second quarter 2015 earnings release contains non-GAAP financial measures. Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These non-GAAP measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance and the financial results calculated in accordance with U.S. GAAP and reconciliations from these results should be carefully evaluated. Net Income (Loss), As Adjusted, represents net income (loss) attributable to Calpine, adjusted for certain non-cash and non-recurring items as previously detailed in Table 1, including mark-to-market (gain) loss on derivatives, debt modification and extinguishment costs and other adjustments. Net Income (Loss), As Adjusted, is presented because we believe it is a useful tool for assessing the operating performance of our company in the current period. Net Income (Loss), As Adjusted, is not intended to represent net income (loss), the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, revenue from renewable energy credits, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Adjusted EBITDA represents net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization, adjusted for certain non-cash and non-recurring items as detailed in the following reconciliation. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. We believe Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase, modification or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any extraordinary, unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends. In summary, our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance. Adjusted Free Cash Flow represents net income before interest, taxes, depreciation and amortization, as adjusted, less operating lease payments, major maintenance expense and maintenance capital expenditures, net cash interest, cash taxes and other adjustments, including non-recurring items. Adjusted Free Cash Flow is presented because we believe it is a useful tool for assessing the financial performance of our company in the current period. Adjusted Free Cash Flow is a performance measure and is not intended to represent net income (loss), the most directly comparable U.S. GAAP measure, or liquidity and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin Reconciliation The following tables reconcile our Commodity Margin to its U.S. GAAP results for the three months ended September 30, 2015 and 2014 (in millions): The following tables reconcile our Commodity Margin to its U.S. GAAP results for the nine months ended September 30, 2015 and 2014 (in millions): _________ (1) Includes $41 million and $49 million of lease levelization and $4 million and $4 million of amortization expense for the three months ended September 30, 2015 and 2014, respectively. (2) Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was not significant for the three months ended September 30, 2014. The Commodity Margin related to those power plants was $81 million for the nine months ended September 30, 2014. (3) Includes $(1) million and $(7) million of lease levelization and $11 million and $11 million of amortization expense for the nine months ended September 30, 2015 and 2014, respectively. Consolidated Adjusted EBITDA Reconciliation In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our net income attributable to Calpine for the three and nine months ended September 30, 2015 and 2014, as reported under U.S. GAAP (in millions): _________ (1) Depreciation and amortization expense in the income from operations calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets. (2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for the three and nine months ended September 30, 2015 and 2014. (3) Includes $29 million and $198 million in major maintenance expense for the three and nine months ended September 30, 2015, respectively, and $22 million and $132 million in maintenance capital expenditure for the three and nine months ended September 30, 2015, respectively. Includes $39 million and $195 million in major maintenance expense for the three and nine months ended September 30, 2014, respectively, and $28 million and $131 million in maintenance capital expenditure for the three and nine months ended September 30, 2014, respectively. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (5) Excludes a decrease in working capital of $7 million and an increase of $244 million for the three and nine months ended September 30, 2015, respectively, and an decrease in working capital of $24 million and an increase of $18 million for the three and nine months ended September 30, 2014, respectively. Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance. (6) Adjusted EBITDA related to the six power plants sold in our East segment on July 3, 2014, was nil and $43 million for the three and nine months ended September 30, 2014, respectively. In the following table, we have reconciled our Adjusted EBITDA to our Commodity Margin, both of which are non-GAAP measures, for the three and nine months ended September 30, 2015 and 2014. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. Amounts below are shown exclusive of the noncontrolling interest (in millions): _________ (1) Shown net of major maintenance expense, stock-based compensation expense, non-cash loss on dispositions of assets and other costs. (2) Shown net of stock-based compensation expense and other costs. (3) Shown net of operating lease expense, amortization and other costs. Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance (in millions) 165 315 265 265 _________ (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 $280 million and maintenance capital expenditures of $180 million. Capital expenditures exclude major construction and development projects. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance (in millions) _________ (1) For purposes of Net Income guidance reconciliation, mark-to-market adjustments are assumed to be nil. (2) Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, income tax expense and other items. (3) Includes projected major maintenance expense of $270 million and maintenance capital expenditures of $140 million. Capital expenditures exclude major construction and development projects. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. OPERATING PERFORMANCE METRICS The table below shows the operating performance metrics for the periods presented: ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us.

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE: CPN): Summary of Second Quarter 2015 Financial Results (in millions, except per share amounts): % Narrowing 2015 Full Year Guidance (in millions, except per share amounts): Recent Achievements: Power and Commercial Operations:— Generated a second quarter record of approximately 28 million MWh3— Achieved low second quarter fleetwide forced outage factor: 1.9%— Delivered strong fleetwide starting reliability: 98%— Executed 50 MW ten-year PPA with Southern California Edison from our Geysers assets Capital Allocation:— Announced accretive acquisition of leading retail provider Champion Energy for $240 million4— Completed approximately $475 million of share repurchases year-to-date, an incremental $239 million since last call— Refinanced approximately $1.6 billion of First Lien Term Loans, reducing interest expense and extending maturity Portfolio Management:— Commenced commercial operation of 309 MW Garrison Energy Center in June 2015— Commenced construction of York 2 Energy Center; commercial operations expected during second quarter of 2017— Received FERC approval for January 2017 sale of Osprey Energy Center Calpine Corporation (NYSE: CPN) today reported second quarter 2015 Adjusted EBITDA of $457 million, compared to $413 million in the prior year period, and Adjusted Free Cash Flow of $144 million, or $0.39 per diluted share, compared to $99 million, or $0.23 per diluted share, in the prior year period. Net Income1 for the second quarter of 2015 was $19 million, or $0.05 per diluted share, compared to $139 million, or $0.33 per diluted share, in the prior year period. Net Income, As Adjusted2, for the second quarter of 2015 was $33 million compared to Net Loss, As Adjusted2, of $3 million in the prior year period. The increases in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted2, were primarily due to higher Commodity Margin driven largely by increased generation across all segments resulting from lower natural gas prices in the East and Texas and stronger market conditions in the West during June, as well as higher contribution from hedges across all of our regions. Year-to-date 2015 Adjusted EBITDA was $795 million, compared to $859 million in the prior year period, and Adjusted Free Cash Flow was $169 million, or $0.45 per diluted share, compared to $229 million, or $0.54 per diluted share, in the prior year period. Net Income1 for the first half of 2015 was $9 million, or $0.02 per diluted share, compared to $122 million, or $0.29 per diluted share, in the prior year period. Net Loss, As Adjusted2, for the first half of 2015 was $29 million compared to Net Income, As Adjusted2, of $53 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 a significant decrease in power and natural gas prices in our East region in the first quarter of 2015, given the unusually high price levels experienced during the polar vortex events in the prior year period, as well as net portfolio changes and lower regulatory capacity revenue in PJM. “We are proud to report solid operational and financial results, driven by strong execution by the Calpine team on all fronts,” said Thad Hill, Calpine’s President and Chief Executive Officer. “For the second consecutive quarter, we achieved record high generation volume, reflecting the ability of our fleet to thrive in a low natural gas price environment while more broadly highlighting the industry shift away from traditional baseload resources and the increasing need for our flexible natural gas fleet to help integrate growing renewable capacity. Specifically, our Texas and East fleets displaced uneconomic coal-fired generation, while our California fleet demonstrated the value of dispatchable electricity by helping maintain grid reliability during the historic drought. “On the strategic front, last week we announced the acquisition of Champion Energy, the nation’s largest independent retail electric provider, primarily concentrated in Texas and the Mid-Atlantic. Champion represents an ideal platform to expand our customer channels given its significant geographic overlap with Calpine’s wholesale fleet. Champion’s award-winning customer service mirrors Calpine’s focus on operational excellence. We expect to close this highly accretive transaction by the fourth quarter. “I am also pleased to report that we remain on track to deliver on our 2015 financial commitments to our shareholders and today are tightening our Adjusted EBITDA and Free Cash Flow Per Share guidance ranges while maintaining the midpoints,” added Hill. “While commodity markets have sold off, including the Texas power market, we remain optimistic about the next several years, given structural improvement in capacity markets and the continuation of the trend toward more reliance on gas-fired generation. We also plan to continue adding value through disciplined and balanced capital allocation and active management of our portfolio. As the industry evolves, we are confident that the benefits of our strategically aligned fleet will continue to generate significant free cash flow for the foreseeable future.” 1 Reported as Net Income attributable to Calpine on our Consolidated Condensed Statements of Operations. 2 Refer to Table 1 for further detail of Net Income (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 Subject to working capital adjustments. SUMMARY OF FINANCIAL PERFORMANCE Second Quarter Results Adjusted EBITDA for the second quarter of 2015 was $457 million compared to $413 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily related to a $25 million increase in Commodity Margin, as well as a $14 million decrease in plant operating expense5. The lower plant operating expense largely resulted from net portfolio changes. The increase in Commodity Margin was primarily due to: Net Income1 was $19 million for the second quarter of 2015, compared to $139 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $33 million in the second quarter of 2015 compared to Net Loss, As Adjusted2, of $3 million in the prior year period. The year-over-year improvement in Net Income, As Adjusted was driven largely by higher Commodity Margin, as previously discussed. Adjusted Free Cash Flow was $144 million in the second quarter of 2015 compared to $99 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to the increase in Adjusted EBITDA, as previously discussed. Year-to-Date Results Adjusted EBITDA for the six months ended June 30, 2015, was $795 million compared to $859 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to an $85 million decrease in Commodity Margin, partially offset by an $18 million decrease in plant operating expense5. The plant operating expense decline was largely the result of net portfolio changes. The decrease in Commodity Margin was primarily due to: Net Income1 was $9 million for the six months ended June 30, 2015, compared to $122 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted2, was $29 million in the six months ended June 30, 2015, compared to Net Income, As Adjusted2, of $53 million in the prior year period. The year-over-year decline was driven largely by lower Commodity Margin, as previously discussed. Adjusted Free Cash Flow was $169 million for the six months ended June 30, 2015, compared to $229 million in the prior year period. Adjusted Free Cash Flow decreased during the period primarily due to the decrease in Adjusted EBITDA, as previously discussed. 5 Decrease 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 six months ended June 30, 2015 and 2014. Table 1: Net Income (Loss), As Adjusted (in millions) __________ (1) Shown net of tax, assuming a 0% effective tax rate for these items. (2) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market (gain) loss also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. (3) Non-GAAP financial measure, see “Regulation G Reconciliations” for further discussion of Net Income (Loss), As Adjusted. REGIONAL SEGMENT REVIEW OF RESULTS Table 2: Commodity Margin by Segment (in millions) West Region Second Quarter: Commodity Margin in our West segment increased by $12 million in the second quarter of 2015 compared to the prior year period. Primary drivers were: Year-to-date: Commodity Margin in our West segment increased by $28 million for the six months ended June 30, 2015, compared to the prior year period. Primary drivers were: Texas Region Second Quarter: Commodity Margin in our Texas segment decreased by $7 million in the second quarter of 2015 compared to the prior year period. Primary drivers were: Year-to-date: Commodity Margin in our Texas segment increased by $21 million for the six months ended June 30, 2015, compared to the prior year period. Primary drivers were: East Region Second Quarter: Commodity Margin in our East segment increased by $62 million in the second quarter of 2015 compared to the prior year period, after excluding a decrease of $42 million resulting from the sale of six power plants with a total capacity of 3,498 MW on July 3, 2014. Primary drivers were: Year-to-date: Commodity Margin in our East segment decreased by $53 million for the six months ended June 30, 2015, compared to the prior year period, after excluding a decrease of $81 million resulting from the sale of six power plants with a total capacity of 3,498 MW on July 3, 2014. Primary drivers were: LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES Table 3: Liquidity (in millions) ____________ (1) Includes $53 million and $47 million of margin deposits posted with us by our counterparties at June 30, 2015, and December 31, 2014, respectively. Liquidity was approximately $2 billion as of June 30, 2015. Cash and cash equivalents decreased during the first half of 2015 primarily due to the repurchases of our common stock, ongoing investments in announced growth projects and the repurchase of a portion of our outstanding 2023 First Lien Notes, partially offset by the receipt of proceeds related to the issuance of our 5.5% Senior Unsecured Notes due 2024 in February 2015. Table 4: Cash Flow Activities (in millions) Cash flows provided by operating activities in the six months ended June 30, 2015, were $19 million compared to $349 million in the prior year period. The decrease in cash provided by operating activities was primarily due to lower income from operations (adjusted for non-cash items) primarily as a result of lower Commodity Margin in our East region in the first quarter of 2015, as previously discussed. In addition, working capital employed related to cash used in operating activities increased during the period primarily due to net margin requirements and greater purchases of environmental allowances. Lastly, cash paid for interest increased, primarily due to our refinancing activity and the related timing of interest payments. Cash flows used in investing activities were $246 million during the six months ended June 30, 2015, compared to $900 million in the prior year period. The decrease was primarily due to the $656 million purchase of our Guadalupe Energy Center in February 2014, for which there was no corresponding activity in the first half of 2015. Cash flows used in financing activities were $68 million during the six months ended June 30, 2015, and were primarily related to payments associated with the execution of our share repurchase program, the repurchase of a portion of our 2023 First Lien Notes and the repayment of our 2018 First Lien Term Loan. These were partially offset by proceeds from the issuance of our 2024 Senior Unsecured Notes and the issuance of our 2022 First Lien Term Loan. CAPITAL ALLOCATION Acquisition of Champion Energy In July 2015, we entered into an agreement to purchase Champion Energy for approximately $240 million, excluding working capital adjustments. Champion Energy, a leading retail electric provider, is expected to serve approximately 22 million MWh of commercial, industrial and residential customer load in 2015, concentrated in Texas, the Mid-Atlantic and the Northeast U.S. where Calpine has a substantial power generation presence. The addition of this well-established retail sales organization is expected to provide us an important outlet for directly reaching a much greater portion of the load we serve. Share Repurchase Program Returning capital to our shareholders by repurchasing shares of our common stock is an integral component of our capital allocation program. We view our stock as an attractive investment opportunity, and we use the projected returns from share repurchases as the benchmark against which all other investment decisions are measured. Since 2011, we have repurchased approximately $2.8 billion of our common stock, representing approximately 28% of shares outstanding.6 In 2015, through the issuance of this release, we have repurchased a total of 23.3 million shares of our common stock for approximately $475 million at an average price of $20.42 per share. 2022 First Lien Term Loan In May 2015, we repaid our 2018 First Lien Term Loans with the proceeds from a newly issued 2022 First Lien Term Loan which extended the maturity and reduced the interest rate on approximately $1.6 billion of corporate debt. Growth and Portfolio Management Texas: Guadalupe Peaking Energy Center: In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) that will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center. Under the terms of the agreement, construction of the Guadalupe Peaking Energy Center (“GPEC”) may commence at our discretion, so long as the power plant reaches commercial operation between the dates of June 1, 2017, and 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. East: Garrison Energy Center: Garrison Energy Center commenced commercial operations in June 2015, bringing online approximately 309 MW of combined-cycle, natural gas-fired capacity. The power plant features one combustion turbine, one heat recovery steam generator and one steam turbine and is expected to be dual fuel capable by this winter. We are in the early stages of development of a second phase of the Garrison Energy Center. 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. The project is now under construction, and we expect commercial operations to commence during the second quarter of 2017. PJM has completed the feasibility study for increasing York 2 Energy Center’s planned capacity by 70 MW, and the queue position has entered the system impact study stage. 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 the summer of 2018, subject to requisite regulatory approvals and applicable contract conditions. PJM and ISO-NE Development Opportunities: We are currently evaluating opportunities to develop additional projects in the PJM and ISO-NE market areas that feature cost advantages such as existing infrastructure and favorable transmission queue positions. These projects are continuing to advance entitlements (such as permits, zoning and transmission) for their potential future development when economical. Osprey Energy Center: 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. for approximately $166 million, excluding working capital and other adjustments. In accordance with the asset sale agreement, the sale will be consummated in January 2017 upon the conclusion of a 27-month PPA. In July 2015, the transaction was approved by the FERC, and the Florida Public Service Commission voted to approve the Florida Commission Hearing Officer’s Recommended Order approving the transaction. This sale represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities. All Segments: Turbine Modernization: We continue to move forward with our turbine modernization program. Through June 30, 2015, 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. 6 Based upon 490.6 million shares outstanding as of June 30, 2011, immediately prior to announcement of our repurchase program. OPERATIONS UPDATE Second Quarter 2015 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% Power Generation:— Seven gas-fired plants with capacity factors greater than 70%: Channel, Hermiston, Kennedy, Morgan, Pasadena, Pine Bluff, Russell City— Pine Bluff Energy Center: 100% starting reliability and 0% forced outage factor Second Quarter 2015 Commercial Operations Achievements: Customer-oriented Growth:— Announced accretive acquisition of retail electric provider Champion Energy for $240 million,4 consistent with our stated goal of getting closer to our end-use customers— 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. 7 According to EEI Safety Survey (2014). 2015 FINANCIAL OUTLOOK (in millions, except per share amounts) (1) Includes projected major maintenance expense of $250 million and maintenance capital expenditures of $165 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 scheduled amortization of approximately $193 million, the repurchase of approximately $147 million of our 2023 First Lien Notes in February 2015 and expected exercise of 10% call feature on 2023 First Lien Notes of approximately $120 million (4) Subject to working capital adjustments. As detailed above, today we are narrowing our 2015 guidance. We expect Adjusted EBITDA of $1.95 billion to $2.05 billion, Adjusted Free Cash Flow of $840 million to $940 million and Adjusted Free Cash Flow Per Share of $2.20 to $2.50. We also expect to invest $355 million in our ongoing growth-related projects during the year, having now completed construction of our Garrison Energy Center and commenced 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 second quarter of 2015 on Thursday, July 30, 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 (888) 895-5271 in the U.S. or (847) 619-6547 outside the U.S. The confirmation code is 40141927. 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 40141927. Presentation materials to accompany the conference call will be available on our website on July 30, 2015. ABOUT CALPINE Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources. Our fleet of 83 power plants in operation or under construction represents approximately 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 Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, 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 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, droughts 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, in our 2014 Form 10-K and in other reports filed by us with the SEC. Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise. (in millions, except share and per share amounts) Net cash provided by (used in) financing activities Additions to property, plant and equipment through capital lease __________ (1) Includes depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated Condensed Statements of Operations. REGULATION G RECONCILIATIONS In addition to disclosing financial results in accordance with U.S. GAAP, the accompanying second quarter 2015 earnings release contains non-GAAP financial measures. Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These non-GAAP measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance and the financial results calculated in accordance with U.S. GAAP and reconciliations from these results should be carefully evaluated. Net Income (Loss), As Adjusted, represents net income (loss) attributable to Calpine, adjusted for certain non-cash and non-recurring items as previously detailed in Table 1, including mark-to-market (gain) loss on derivatives, debt modification and extinguishment costs and other adjustments. Net Income (Loss), As Adjusted, is presented because we believe it is a useful tool for assessing the operating performance of our company in the current period. Net Income (Loss), As Adjusted, is not intended to represent net income (loss), the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, revenue from renewable energy credits, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Adjusted EBITDA represents net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization, adjusted for certain non-cash and non-recurring items as detailed in the following reconciliation. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. We believe Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase, modification or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any extraordinary, unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends. In summary, our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance. Adjusted Free Cash Flow represents net income before interest, taxes, depreciation and amortization, as adjusted, less operating lease payments, major maintenance expense and maintenance capital expenditures, net cash interest, cash taxes and other adjustments, including non-recurring items. Adjusted Free Cash Flow is presented because we believe it is a useful tool for assessing the financial performance of our company in the current period. Adjusted Free Cash Flow is a performance measure and is not intended to represent net income (loss), the most directly comparable U.S. GAAP measure, or liquidity and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin Reconciliation The following tables reconcile our Commodity Margin to its U.S. GAAP results for the three months ended June 30, 2015 and 2014 (in millions): The following tables reconcile our Commodity Margin to its U.S. GAAP results for the six months ended June 30, 2015 and 2014 (in millions): _________ (1) Includes $(18) million and $(27) million of lease levelization and $3 million and $3 million of amortization expense for the three months ended June 30, 2015 and 2014, respectively. (2) Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was $42 million and $81 million for the three and six months ended June 30, 2014, respectively. (3) Includes $(42) million and $(56) million of lease levelization and $7 million and $7 million of amortization expense for the six months ended June 30, 2015 and 2014, respectively. Consolidated Adjusted EBITDA Reconciliation In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our net income (loss) attributable to Calpine for the three and six months ended June 30, 2015 and 2014, as reported under U.S. GAAP (in millions): (1) Depreciation and amortization expense in the income from operations calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets. (2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for the three and six months ended June 30, 2015 and 2014. (3) Includes $90 million and $169 million in major maintenance expense for the three and six months ended June 30, 2015, respectively, and $46 million and $110 million in maintenance capital expenditure for the three and six months ended June 30, 2015, respectively. Includes $73 million and $156 million in major maintenance expense for the three and six months ended June 30, 2014, respectively, and $53 million and $103 million in maintenance capital expenditure for the three and six months ended June 30, 2014, respectively. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (5) Excludes an increase in working capital of $165 million and $251 million for the three and six months ended June 30, 2015, respectively, and an increase in working capital of $36 million and $42 million for the three and six months ended June 30, 2014, respectively. Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance. (6) Adjusted EBITDA related to the six power plants sold in our East segment on July 3, 2014, was $23 million and $43 million for the three and six months ended June 30, 2014, respectively. In the following table, we have reconciled our Adjusted EBITDA to our Commodity Margin, both of which are non-GAAP measures, for the three and six months ended June 30, 2015 and 2014. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. Amounts below are shown exclusive of the noncontrolling interest (in millions): _________ (1) Shown net of major maintenance expense, stock-based compensation expense, non-cash loss on dispositions of assets and other costs. (2) Shown net of stock-based compensation expense and other costs. (3) Shown net of operating lease expense, amortization and other costs. Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance (in millions) 298 398 _________ (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 $250 million and maintenance capital expenditures of $165 million. Capital expenditures exclude major construction and development projects. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. OPERATING PERFORMANCE METRICS The table below shows the operating performance metrics for the periods presented: ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us.

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE:CPN): Summary of First Quarter 2015 Financial Results (in millions, except per share amounts): (16.2) % (17.1) % (24.2) % (80.8) % (77.4) % Reaffirming 2015 Full Year Guidance (in millions, except per share amounts): Recent Achievements: Power Operations:— Generated record high 26 million MWh3 of electricity in first quarter of 2015— Achieved low first quarter fleetwide forced outage factor: 1.4%— Delivered strong fleetwide starting reliability: 98% Customer-Oriented Origination Efforts:— Originated 710 MW of public power PPAs from our Texas power plant fleet, one of which will facilitate construction of 418 MW peaking facility in partnership with our customer— Executed 65 MW PPA with Marin Clean Energy from our Delta Energy Center and northern California fleet— Executed 20-year PPA for 345 MW expansion of our Mankato Energy Center Capital Allocation and Portfolio Management Progress:— Completed approximately $236 million of share repurchases year-to-date, an incremental $111 million since last call— Nearing completion of Garrison Energy Center: commercial operations expected during second quarter of 2015— Advanced development of York 2 Energy Center: commercial operations expected during second quarter of 2017— Filed with FERC to approve pending sale of Osprey Energy Center in January 2017 Calpine Corporation (NYSE: CPN) today reported first quarter 2015 Adjusted EBITDA of $338 million, compared to $446 million in the prior year period, and Adjusted Free Cash Flow of $25 million, or $0.07 per diluted share, compared to $130 million, or $0.31 per diluted share, in the prior year period. Net Loss1 for the first quarter of 2015 was $10 million, or $0.03 per diluted share, compared to $17 million, or $0.04 per diluted share, in the prior year period. Net Loss, As Adjusted2, for the first quarter of 2015 was $62 million compared to Net Income, As Adjusted2, of $56 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 impacts of the polar vortex in the first quarter of 2014, which resulted in significantly higher power and natural gas prices in our East region during that period, as well as by the sale of six power plants in July 2014 and lower regulatory capacity revenue in PJM. “This year’s first quarter financial results are in line with our expectations and represent the benefits of a geographically diverse fleet,” said Thad Hill, Calpine’s President and Chief Executive Officer. “Our financial performance improved year-over-year in Texas and the West and, as expected, declined in the East given lower capacity revenue in PJM, the divestiture of six assets in the region last summer and our unusually strong first quarter results last year due to elevated power and natural gas prices during polar vortex events. “Looking at the full year, we are reaffirming our 2015 financial guidance. In short, we expect the balance of the year to outperform, particularly the second half, as a result of portfolio additions, higher regulatory capacity payments and the nature of our hedges. In addition it is worth noting that we achieved record high generation volume in the first quarter, due in large part to lower natural gas prices. “On the commercial front, I am very encouraged by our successful origination efforts during the quarter. We sourced more than 700 MW of new PPAs with Texas public power customers, including one for 270 MW with Guadalupe Valley Electric Cooperative that will not only allow us to serve them from our existing fleet but will also facilitate the construction of a 418 MW natural gas-fired peaking power plant. We expect this jointly owned project to allow us to capture significant value from our development efforts and existing site, while providing us the flexibility to begin operations at our election over a three-summer period from 2017-2019, to better coincide with market pricing signals. In addition, we executed a 20-year PPA with Xcel Energy for a 345 MW expansion of our Mankato Power Plant in Minnesota. Our persistent focus on customer relationships continues to enhance the value of our portfolio. “Meanwhile, we remain committed to enhancing shareholder value through capital allocation, having this year already completed a successful financing transaction, returned $236 million of capital to our shareholders through share repurchases, and invested in growth, including advancing our Garrison Energy Center to its final stages of construction. Our continued focus on operational excellence, balanced capital allocation and active portfolio management form the pillars of Calpine’s success, and our flexible natural gas and geothermal fleet remains well positioned to meet the needs of America's power generation future.” 1 Reported as Net Loss attributable to Calpine on our Consolidated Condensed 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. SUMMARY OF FINANCIAL PERFORMANCE First Quarter Results Adjusted EBITDA for the first quarter of 2015 was $338 million compared to $446 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to a $110 million decrease in Commodity Margin, which was largely due to: Net Loss1 was $10 million for the first quarter of 2015, compared to $17 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted2, was $62 million in the first quarter of 2015 compared to Net Income, As Adjusted2, of $56 million in the prior year period. The year-over-year decline was driven largely by lower Commodity Margin, as previously discussed. Adjusted Free Cash Flow was $25 million in the first quarter of 2015 compared to $130 million in the prior year period. Adjusted Free Cash Flow decreased during the period primarily due to the decrease in Adjusted EBITDA, as previously discussed. Table 1: Net Income (Loss), As Adjusted (in millions) __________ (1) Shown net of tax, assuming a 0% effective tax rate for these items. (2) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market (gain) loss also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. (3) Non-GAAP financial measure, see “Regulation G Reconciliations” for further discussion of Net Income (Loss), As Adjusted. REGIONAL SEGMENT REVIEW OF RESULTS Table 2: Commodity Margin by Segment (in millions) West Region First Quarter: Commodity Margin in our West segment increased by $16 million in the first quarter of 2015 compared to the prior year period. Primary drivers were: lower market spark spreads driven by lower natural gas prices and an increase in hydroelectric generation in the Pacific Northwest, despite relatively unchanged market heat rates. Texas Region First Quarter: Commodity Margin in our Texas segment increased by $28 million in the first quarter of 2015 compared to the prior year period. Primary drivers were: East Region First Quarter: Commodity Margin in our East segment decreased by $115 million in the first quarter of 2015 compared to the prior year period, after excluding a decrease of $39 million resulting from the sale of six power plants with a total capacity of 3,498 MW on July 3, 2014. Primary drivers were: LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES Table 3: Liquidity (in millions) __________ (1) Includes $40 million and $47 million of margin deposits posted with us by our counterparties at March 31, 2015, and December 31, 2014, respectively. Liquidity was approximately $2.4 billion as of March 31, 2015. Cash and cash equivalents increased during the first quarter of 2015 primarily due to the receipt of proceeds related to the issuance of our 5.5% Senior Unsecured Notes due 2024 in February 2015, partially offset by repurchases of our common stock, the repurchase of a portion of our outstanding 2023 First Lien Notes and ongoing investments in announced growth projects. Table 4: Cash Flow Activities (in millions) Cash flows used in operating activities in the first quarter of 2015 resulted in net outflows of $17 million compared to net inflows of $123 million in the prior year period. The decrease in cash provided by operating activities was primarily due to lower income from operations (adjusted for non-cash items) primarily as a result of lower Commodity Margin in our East region, as previously discussed. Lower Commodity Margin also contributed to an increase in working capital related to cash used in operating activities, which further contributed to the year-over-year decline. These items were partially offset by a decrease in cash paid for interest as a result of our refinancing activity. Cash flows used in investing activities were $128 million in the first quarter of 2015 compared to $769 million in the prior year period. The decrease was primarily due to the $656 million purchase of our Guadalupe Energy Center during the first quarter of 2014, for which there was no corresponding activity in the first quarter of 2015. Cash flows provided by financing activities in the first quarter of 2015 were $224 million and were primarily related to the issuance of our 2024 Senior Unsecured Notes, partially offset by payments associated with the execution of our share repurchase program and the repurchase of a portion of our 2023 First Lien Notes. CAPITAL ALLOCATION Share Repurchase Program Returning capital to our shareholders by repurchasing shares of our common stock is an integral component of our capital allocation program. We view our stock as an attractive investment opportunity, and we use the projected returns from share repurchases as the benchmark against which all other investment decisions are measured. Since 2011, we have repurchased approximately $2.5 billion of our common stock, representing approximately 26% of shares outstanding.4 In 2015, through the issuance of this release, we have repurchased a total of 10.8 million shares of our common stock for approximately $236 million at an average price of $21.73 per share. 2024 Senior Unsecured Notes In February 2015, we issued $650 million of 5.5% Senior Unsecured Notes due 2024 to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase approximately $147 million of our 7.875% First Lien Notes due 2023 and for general corporate purposes. 4 Based upon 490.6 million shares outstanding as of June 30, 2011, immediately prior to announcement of our repurchase program. Growth and Portfolio Management Texas: Guadalupe Peaking Energy Center: In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) that will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center. Under the terms of the agreement, construction of the Guadalupe Peaking Energy Center (“GPEC”) may commence at our discretion, so long as the power plant reaches commercial operation between the dates of June 1, 2017, and 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. East: Garrison Energy Center: Garrison Energy Center is a 309 MW dual fuel 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 commercial operations to commence during the second quarter of 2015. The project’s capacity has cleared each of PJM’s three most recent base residual auctions. We are in the early stages of development of a second phase of the Garrison Energy Center. 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 has completed the feasibility study for increasing York 2 Energy Center’s planned capacity by 120 MW, and the queue position has entered the system impact study stage. 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 June 2018, subject to requisite regulatory approvals and applicable contract conditions. PJM and ISO-NE Development Opportunities: We are currently evaluating opportunities to develop additional projects in the PJM and ISO-NE market areas that feature cost advantages such as existing infrastructure and favorable transmission queue positions. These projects are continuing to advance entitlements (such as permits, zoning and transmission) for their potential future development when economical. Osprey Energy Center: 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. for approximately $166 million, excluding working capital and other adjustments. In accordance with the asset sale agreement, the sale will be consummated in January 2017 upon the conclusion of a 27-month PPA. 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. During the first quarter of 2015, we made the appropriate filings with FERC requesting approval of the asset sale. All Segments: Turbine Modernization: We continue to move forward with our turbine modernization program. Through March 31, 2015, 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. OPERATIONS UPDATE First Quarter 2015 Power Operations Achievements Safety Performance:— Maintained top quartile5 safety metrics: 0.66 total recordable incident rate Availability Performance:— Achieved low fleetwide forced outage factor: 1.4%— Delivered exceptional fleetwide starting reliability: 98% Power Generation:— Morgan Energy Center: 90% capacity factor— Four Texas plants with capacity factors above 70%: Bosque, Brazos Valley, Channel and Deer Park Energy Centers— Hermiston, Otay Mesa, Pastoria and Russell City Energy Centers: 100% starting reliability First Quarter 2015 Commercial Operations Achievements: Customer-oriented Growth: During the first quarter of 2015, we entered into the following new contracts:West:— A three-year 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— 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 California Public Utilities CommissionTexas:— A new three-year PPA with Brazos Electric Power Cooperative to provide 300 MW of power from our Texas power plant fleet commencing in January 2016— A new three-year PPA with Pedernales Electric Cooperative to provide approximately 140 MW of power from our Texas power plant fleet commencing in January 2017— A new two-year PPA with Guadalupe Valley Electric Cooperative to provide approximately 270 MW of power 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 CenterEast:— 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 ___________ 5 According to EEI Safety Survey (2013). 2015 FINANCIAL OUTLOOK (in millions, except per share amounts) ________ (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 $147 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 $1.9 billion to $2.1 billion, 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 first quarter of 2015 on Friday, May 1, 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 39347559. 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 39347559. Presentation materials to accompany the conference call will be available on our website on May 1, 2015. ABOUT CALPINE Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources. Our fleet of 87 power plants in operation or under construction represents 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 Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, 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, droughts 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, in our 2014 Form 10-K and in other reports filed by us with the SEC. Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise. CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (Unaudited) (in millions, except share and per share amounts) 1,638 Total operating expenses CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) Purchase of Guadalupe Energy Center Net cash used in investing activities 420 Proceeds from exercises of stock options __________ (1) Includes depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated Condensed Statements of Operations. REGULATION G RECONCILIATIONS In addition to disclosing financial results in accordance with U.S. GAAP, the accompanying Q1 2015 earnings release contains non-GAAP financial measures. Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These non-GAAP measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance and the financial results calculated in accordance with U.S. GAAP and reconciliations from these results should be carefully evaluated. Net Income (Loss), As Adjusted, represents net income (loss) attributable to Calpine, adjusted for certain non-cash and non-recurring items as previously detailed in Table 1, including mark-to-market (gain) loss on derivatives, debt extinguishment costs and other adjustments. Net Income (Loss), As Adjusted, is presented because we believe it is a useful tool for assessing the operating performance of our company in the current period. Net Income (Loss), As Adjusted, is not intended to represent net income (loss), the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, revenue from renewable energy credits, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Adjusted EBITDA represents net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization, adjusted for certain non-cash and non-recurring items as detailed in the following reconciliation. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. We believe Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any extraordinary, unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends. In summary, our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance. Adjusted Free Cash Flow represents net income before interest, taxes, depreciation and amortization, as adjusted, less operating lease payments, major maintenance expense and maintenance capital expenditures, net cash interest, cash taxes and other adjustments, including non-recurring items. Adjusted Free Cash Flow is presented because we believe it is a useful tool for assessing the financial performance of our company in the current period. Adjusted Free Cash Flow is a performance measure and is not intended to represent net income (loss), the most directly comparable U.S. GAAP measure, or liquidity and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin Reconciliation The following tables reconcile our Commodity Margin to its U.S. GAAP results for the three months ended March 31, 2015 and 2014 (in millions): _________ (1) Includes $(24) million and $(29) million of lease levelization and $4 million and $4 million of amortization expense for the three months ended March 31, 2015 and 2014, respectively. (2) Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was $39 million for the three months ended March 31, 2014. 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 ended March 31, 2015 and 2014, as reported under U.S. GAAP (in millions): 2014(6) _________ (1) Depreciation and amortization expense in the income from operations calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets. (2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for the three months ended March 31, 2015 and 2014. (3) Includes $79 million and $83 million in major maintenance expense for the three months ended March 31, 2015 and 2014, respectively, and $64 million and $50 million in maintenance capital expenditure for the three months ended March 31, 2015 and 2014, respectively. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (5) Excludes an increase in working capital of $86 million and $6 million for the three months ended March 31, 2015 and 2014, respectively. Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance. (6) Adjusted EBITDA related to the six power plants sold in our East segment on July 3, 2014, was $20 million for the three months ended March 31, 2014. 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 ended March 31, 2015 and 2014. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. Amounts below are shown exclusive of the noncontrolling interest (in millions): _________ (1) Shown net of major maintenance expense, stock-based compensation expense, non-cash loss on dispositions of assets and other costs. (2) Shown net of stock-based compensation expense and other costs. (3) Shown net of operating lease expense, amortization and other costs. Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance (in millions) _________ (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: ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us.

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE:CPN): Summary of 2014 Financial Results (in millions, except per share amounts): Reaffirming 2015 Full Year Guidance (in millions, except per share amounts): 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.” __________ 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: 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: 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 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 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: 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) __________ (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) 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: Full Year: Commodity Margin in our West segment increased by $30 million in 2014, compared to the prior year period. Primary drivers were: 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: Full Year: Commodity Margin in our Texas segment increased by $128 million in 2014, compared to the prior year period. Primary drivers were: 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: 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: LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES Table 3: Liquidity __________ (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 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. ___________ 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 2017Texas:— 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 2016East:— 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) ________ (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 ) — ) 12 ) (30 ) 1 ) (113 ) (7 ) 45 ) (575 ) — ) (593 __________ (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): The following tables reconcile our Commodity Margin to its U.S. GAAP results for the years ended December 31, 2014 and 2013 (in millions): _________ (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. 2014 _________ (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. _________ (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 Adjusted EBITDA _________ (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: ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us.

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE: CPN) Summary of Third Quarter 2014 Financial Results (in millions, except per share amounts): (4.2) % (7.1) % Narrowing 2014 and Providing 2015 Full Year Guidance (in millions, except per share amounts): GrowthRate3 Recent Achievements: Power and Commercial Operations:— Generated approximately 29 million MWh4 of electricity in third quarter of 2014— Achieved low year-to-date fleetwide forced outage factor: 2.1%— Successfully originated several new contracts, including those related to our Geysers assets, Delta, Pastoria and Osprey power plants and our Texas power plant fleet Portfolio Management:— Announced acquisition of Fore River Energy Center, a nameplate 809 MW combined-cycle and dual-fuel capable power plant in Massachusetts, for approximately $530 million, or $655/kW Capital Allocation Progress:— Deployed approximately $3.1 billion of capital year-to-date toward share repurchase, balance sheet management, organic growth and acquisitions— Completed approximately $308 million of share repurchases since last earnings announcement, bringing total 2014 repurchases to approximately $949 million— Issued notice to call approximately $120 million of our 7.875% First Lien Notes due 2023 at a price of 103 during the fourth quarter Calpine Corporation (NYSE: CPN) today reported third quarter 2014 Adjusted EBITDA of $745 million, compared to $802 million in the prior year period, and Adjusted Free Cash Flow of $506 million, or $1.26 per diluted share, compared to $556 million, or $1.27 per diluted share, in the prior year period. The decreases in Adjusted EBITDA and Adjusted Free Cash Flow were primarily due to lower Commodity Margin driven largely by the sale of six power plants in July 2014. Net Income1 for the third quarter of 2014 was $614 million, or $1.52 per diluted share, compared to $306 million, or $0.70 per diluted share, in the prior year period. The increase in Net Income1 was primarily due to a gain on the previously referenced asset sale, partially offset by higher debt extinguishment costs and impairment losses. Net Income, As Adjusted2, for the third quarter of 2014 was $306 million compared to $268 million in the prior year period. The increase in Net Income, As Adjusted2, was primarily due to a decrease in income tax expense associated with intraperiod tax allocations, which more than offset the previously discussed decrease in Adjusted EBITDA. Year-to-date 2014 Adjusted EBITDA was $1,604 million, compared to $1,431 million in the prior year period, and Adjusted Free Cash Flow was $735 million, or $1.77 per diluted share, compared to $551 million, or $1.23 per diluted share, in the prior year period. Net Income1 for the first nine months of 2014 was $736 million, or $1.77 per diluted share, compared to $111 million, or $0.25 per diluted share, in the prior year period. The increase in Net Income1 was primarily due to higher Commodity Margin, as well as those factors that drove comparative performance for the third quarter, as described above. Net Income, As Adjusted2, for the first nine months of 2014 was $359 million compared to $165 million in the prior year period. The increases in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted2, compared to the prior year period were primarily due to higher Commodity Margin resulting from stronger market conditions, net portfolio changes and higher regulatory capacity revenue. “Calpine delivered another strong quarter both operationally and commercially, especially considering the mild summer weather in much of the country,” said Thad Hill, Calpine’s President and Chief Executive Officer. “We benefited from timely hedging, new capacity and operational excellence throughout our fleet. Meanwhile, we also further positioned Calpine for the future, announcing the pending acquisition of Fore River Energy Center in New England, originating several new contracts in California and Texas, and advancing construction of Garrison Energy Center in Delaware and development of York 2 Energy Center in Pennsylvania. “Our clean, modern, efficient and flexible fleet is poised to benefit from the secular trends playing out in the U.S. power generation industry. In the East, our reliable operations and dual-fuel capabilities position us to take advantage of tighter markets given the significant upcoming capacity retirements and provide us the confidence to be a meaningful participant in capacity markets that will command a premium for performance. Our Texas fleet is poised to benefit from strong demand growth, pending environmental regulations and increasing volatility from the addition of intermittent wind. Finally, we continue to position our California fleet for long-term stability through contracts to support the integration of intermittent resources. “Calpine remains firmly committed to enhancing shareholder value through disciplined and accretive capital allocation. We are on track in 2014 to redeploy more than $3 billion of capital into attractive growth opportunities, debt repayment and share repurchases. Among these, we balance share repurchases with our ability to respond to other opportunities in the marketplace. Our foremost objective is to maximize levered cash-on-cash returns to equity, as measured by Adjusted Free Cash Flow Per Share, while being prudent with the balance sheet. We are pleased to provide 2015 guidance today, that, at the midpoint of the ranges, represents an increase in Adjusted Free Cash Flow Per Share of approximately 19% over 2014.” __________ 1 Reported as Net Income attributable to Calpine on our Consolidated Condensed Statements of Operations. 2 Refer to Table 1 for further detail of Net Income, As Adjusted. 3 Assuming midpoints of 2014 and 2015 guidance ranges. 4 Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants. SUMMARY OF FINANCIAL PERFORMANCE Third Quarter Results Adjusted EBITDA for the third quarter of 2014 was $745 million compared to $802 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to a $41 million decrease in Commodity Margin, which was largely due to: the expiration of a tolling contract associated with our Delta Energy Center in December 2013 and a previously existing PPA associated with our Osprey Energy Center in May 2014, partially offset by Net Income1 was $614 million for the third quarter of 2014, compared to $306 million in the prior year period. The year-over-year improvement in Net Income1 was primarily due to a gain on the previously referenced asset sale, partially offset by higher debt extinguishment costs and impairment losses related to our Osprey Energy Center. As detailed in Table 1, Net Income, As Adjusted2, was $306 million in the third quarter of 2014 compared to $268 million in the prior year period. The year-over-year improvement was driven largely by: Adjusted Free Cash Flow was $506 million in the third quarter of 2014 compared to $556 million in the prior year period. Adjusted Free Cash Flow decreased during the period primarily due to the decrease in Adjusted EBITDA, as previously discussed. Year-to-Date Results Adjusted EBITDA for the nine months ended September 30, 2014, was $1,604 million compared to $1,431 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily due to a $242 million increase in Commodity Margin which was primarily related to: higher regulatory capacity revenue in PJM during the first half of the year and the expiration of a tolling contract associated with our Delta Energy Center in December 2013 and a previously existing PPA associated with our Osprey Energy Center in May 2014. Net Income1 was $736 million for the nine months ended September 30, 2014, compared to $111 million in the prior year period. In addition to the previously mentioned factors that drove similar improvements in Net Income1 for the third quarter, Net Income1 for the nine months ended September 30, 2014, also increased as a result of higher Commodity Margin, as previously discussed. As detailed in Table 1, Net Income, As Adjusted2, was $359 million in the nine months ended September 30, 2014, compared to $165 million in the prior year period. The year-over-year improvement was driven largely by: Adjusted Free Cash Flow was $735 million for the nine months ended September 30, 2014, compared to $551 million in the prior year period. The increase in Adjusted Free Cash Flow during the period was primarily due to an increase in Adjusted EBITDA, as previously discussed. Table 1: Net Income, As Adjusted __________ (1) Shown net of tax, assuming a 0% effective tax rate for these items. (2) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market (gain) loss also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. (3) See “Regulation G Reconciliations” for further discussion of Net Income, As Adjusted. REGIONAL SEGMENT REVIEW OF RESULTS Table 2: Commodity Margin by Segment (in millions) West Region Third Quarter: Commodity Margin in our West segment increased by $24 million in the third quarter of 2014 compared to the prior year period. Primary drivers were: Year-to-Date: Commodity Margin in our West segment increased by $54 million for the nine months ended September 30, 2014, compared to the prior year period. The year-to-date results were largely impacted by the same factors that drove comparative performance for the third quarter, as previously discussed. Texas Region Third Quarter: Commodity Margin in our Texas segment increased by $18 million in the third quarter of 2014 compared to the prior year period. Primary drivers were: Year-to-Date: Commodity Margin in our Texas segment increased by $107 million for the nine months ended September 30, 2014, compared to the prior year period. Primary drivers were: East Region Third Quarter: Commodity Margin in our East segment decreased by $18 million in the third quarter of 2014 compared to the prior year period, after excluding a decrease of $65 million resulting from the sale of six power plants with a total capacity of 3,498 MW on July 3, 2014. Primary drivers were: Year-to-Date: Commodity Margin in our East segment increased by $122 million for the nine months ended September 30, 2014, compared to the prior year period, after excluding a decrease of $41 million resulting from the previously discussed sale of six power plants. Primary drivers were: higher margins resulting from stronger market conditions due to colder than normal weather during the first quarter of 2014 LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES Table 3: Liquidity __________ (1) Includes $67 million and $5 million of margin deposits posted with us by our counterparties at September 30, 2014, and December 31, 2013, respectively. (2) On July 30, 2014, we amended our Corporate Revolving Facility to increase the capacity by an additional $500 million to $1.5 billion. Liquidity grew to approximately $3.2 billion as of September 30, 2014. Cash and cash equivalents increased during the nine months ended September 30, 2014, primarily due to the receipt of proceeds from the sale of six power plants in our East segment in July 2014. Availability under our Corporate Revolving Facility increased primarily as a result of an amendment that raised its capacity by $500 million during the third quarter of 2014. Table 4: Cash Flow Activities Cash flows provided by operating activities in the nine months ended September 30, 2014, were $504 million compared to $415 million in the prior year period. The increase in cash provided by operating activities was primarily due to an increase in income from operations (adjusted for non-cash items). Also contributing to the increase was a decrease in working capital employed, largely due to lower net margin requirements partially offset by an increase in net accounts receivable/payable balances resulting from higher Commodity Margin. Partially offsetting these increases, debt extinguishment payments increased due to the refinancing of our First Lien Notes during the first nine months of 2014. Cash flows provided by investing activities during the nine months ended September 30, 2014, were $550 million compared to cash flows used in investing activities of $468 million in the prior year period. The increase was primarily due to $1.57 billion of proceeds received in 2014 from the sale of six power plants in our East segment, partially offset by $656 million used to purchase our Guadalupe Energy Center. Cash flows used in financing activities were $466 million and were primarily related to payments associated with execution of our share repurchase program, partially offset by the issuance of CCFC Term Loans used to fund a portion of the purchase price of our Guadalupe Energy Center. CAPITAL ALLOCATION Share Repurchase Program During 2014, we repurchased a total of 42,754,300 shares of our common stock for approximately $949 million at an average price of $22.19 per share. Included in the total 2014 activity is the repurchase of 13,213,372 shares of our common stock from a shareholder for approximately $311 million in a private transaction completed in July 2014 that was approved by our Board of Directors. Fore River Energy Center On August 22, 2014, we entered into an agreement to purchase Fore River Energy Center, a power plant with a nameplate capacity of 809 MW, for approximately $530 million, excluding working capital adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant located in North Weymouth, Massachusetts, will increase capacity in our East segment, specifically the constrained New England market. The plant features two combustion turbines, two heat recovery steam generators and one steam turbine. We expect the transaction to close in the fourth quarter of 2014 and expect to fund the acquisition with cash on hand or financing. Osprey Energy Center In August 2014, we executed a term sheet with Duke Energy Florida, Inc. related to our Osprey Energy Center for a new PPA with a term of up to 27 months, after which Duke Energy Florida, Inc. would purchase our Osprey Energy Center. Although a definitive asset sale agreement is still being negotiated, and any such agreement would be subject to regulatory approval, the potential sale of our Osprey Energy Center represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities. Sale of Six Southeast Power Plants On July 3, 2014, we completed the sale of six of our power plants in the East segment for a purchase price of approximately $1.57 billion in cash, excluding working capital and other adjustments. The divestiture of these power plants has better aligned our asset base with our strategic focus on competitive wholesale markets. Refinancing of First Lien Notes with Senior Unsecured Notes On July 22, 2014, we refinanced $2.8 billion of senior secured notes with an equivalent amount of senior unsecured notes. We issued $1.25 billion in aggregate principal amount of 5.375% senior unsecured notes due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior unsecured notes due 2025 in a public offering, representing the inaugural issuance of unsecured debt within our capital structure. We used the net proceeds, together with cash on hand, to repurchase our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes, which carried interest rates of 7.50% - 8.00%. In connection with this refinancing, we incurred approximately $350 million in early retirement premiums and fees, and we expect to achieve annual interest savings of approximately $60 million. 2023 First Lien Notes In November 2014, we issued notice to the holders of our 2023 First Lien Notes of our intent to redeem 10% of the original aggregate principal amount, plus accrued and unpaid interest. We intend to use cash on hand to fund the redemption. PLANT DEVELOPMENT Texas: Channel and Deer Park Expansions: In June of 2014, we completed construction to expand the baseload capacity of our Deer Park and Channel Energy Centers by approximately 260 MW5 each. Each power plant featured an oversized steam turbine that, along with existing plant infrastructure, allowed us to add capacity and improve the power plant’s overall efficiency at a meaningful discount to the market cost of building new capacity. Guadalupe Energy Center: On February 26, 2014, we completed the purchase of a 1,050 MW nameplate capacity power plant for approximately $625 million, excluding working capital adjustments. We funded the acquisition with $425 million of incremental CCFC Term Loans and cash on hand. The addition of this modern, natural gas-fired, combined-cycle power plant increased capacity in our Texas segment, which is one of our core markets. We also paid $15 million to acquire the rights to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker. Development efforts are ongoing and we are continuing to advance entitlements (such as permits, zoning and transmission). East: Garrison Energy Center: Garrison Energy Center is a 309 MW combined-cycle project located in Delaware on a site secured by a long-term lease with the City of Dover. Once complete, the power plant will feature one combustion turbine, one heat recovery steam generator and one steam turbine. Construction commenced in April 2013, and we expect commercial operations to commence during the second quarter of 2015. The project’s capacity has cleared each of PJM’s three most recent base residual auctions. We are in the early stages of development of a second phase (309 MW) of this project. PJM has completed the feasibility and system impact studies for this phase, and the facilities study is currently underway. Mankato Power Plant Expansion: We are proposing a 345 MW expansion of the Mankato Power Plant in response to a competitive resource acquisition process established by the Minnesota Public Utilities Commission (“MPUC”) to acquire up to approximately 500 MW of new capacity. The initial stage of the proceeding was managed via a contested case hearing. On March 27, 2014, the MPUC directed Xcel Energy (Northern States Power) to negotiate PPAs with Calpine and certain other entities. Xcel Energy filed the negotiated PPAs on September 23, 2014, but recommended that the MPUC delay approval. The MPUC is expected to decide whether to approve one or more PPAs or to delay the pending resource acquisition process during deliberations later this year. York 2 Energy Center: York 2 Energy Center is a 760 MW dual-fueled combined-cycle project that will be co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. PJM has completed the project’s feasibility and system impact studies, and the facilities study is underway. The project’s capacity cleared PJM’s 2017/2018 base residual auction, and we expect commercial operations to commence during the second quarter of 2017. The project’s key permits and approvals are being actively pursued and major equipment purchase commitments were executed during the third quarter of 2014. PJM Development Opportunities: We are currently evaluating opportunities to develop additional projects in the PJM market area that feature cost advantages such as existing infrastructure and favorable transmission queue positions. These projects are continuing to advance entitlements (such as permits, zoning and transmission) for their potential future development. All Segments: Turbine Modernization: We continue to move forward with our turbine modernization program. Through September 30, 2014, we have completed the upgrade of thirteen Siemens and eight GE turbines totaling approximately 210 MW and have committed to upgrade approximately three additional turbines. Similarly, we have the opportunity at several of our power plants in Texas to implement further turbine modernizations to add as much as 500 MW of incremental capacity across the region at attractive prices. In addition, we have begun a program to update our dual-fueled turbines at certain of our power plants in our East segment. Our decision to invest in these turbine modernizations depends upon, among other things, further clarity on market design reforms currently being considered. ___________ 5 Represents incremental baseload capacity at annual average conditions. Incremental summer peaking capacity is approximately 200 MW per unit, supplemented by incremental efficiencies across the balance of plant. OPERATIONS UPDATE Third Quarter 2014 Power Operations Achievements Safety Performance:— Maintained top quartile6 safety metrics: 0.70 Total Recordable Incident Rate year-to-date Availability Performance:— Achieved low fleetwide forced outage factor: 2.3%— Delivered strong fleetwide starting reliability: 99% Power Generation:— Provided approximately 1.5 million MWh of renewable baseload generation from our Geysers geothermal plants— Pastoria Energy Center: 94% capacity factor and 0% forced outage factor— King City Cogen: 100% availability factor, 100% starting reliability and 0% forced outage factor Third Quarter 2014 Commercial Operations Achievements: Customer-oriented Growth:— We entered into a new one-year PPA with Guadalupe Valley Electric Cooperative to provide approximately 270 MW of power from our Texas power plant fleet commencing in June 2016— We entered into a new ten-year PPA with the Sonoma Clean Power Authority to provide 15 MW of renewable power from our Geysers assets commencing in January 2017. The capacity under contract will vary by year, increasing up to a maximum of 50 MW for years 2024 through 2026— We entered into a new three-year resource adequacy contract with Southern California Edison (SCE) for our Pastoria Energy Facility commencing in January 2016. The capacity under contract will initially be 238 MW and will increase to 476 MW during the final year of the contract— We entered into a new two-year resource adequacy contract with SCE for our Delta Energy Center for 500 MW of capacity commencing in January 2017— We entered into a new PPA with a term of up to 27 months with Duke Energy Florida, Inc., subject to certain approvals, to provide 515 MW of power and capacity from our Osprey Energy Center which commenced in October 2014. ___________ 6 According to EEI Safety Survey (2013). 2014 & 2015 FINANCIAL OUTLOOK (in millions, except per share amounts) ________ (1) Includes projected major maintenance expense of $240 million and $235 million and maintenance capital expenditures of $165 million and $160 million in 2014 and 2015, respectively. Capital expenditures exclude major construction and development projects. (2) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (3) Includes $120 million of 2023 First Lien Notes to be redeemed in the fourth quarter of 2014. As detailed above, today we are narrowing our 2014 guidance. We now project Adjusted EBITDA of $1,915 million to $1,965 million, Adjusted Free Cash Flow of $800 million to $850 million and Adjusted Free Cash Flow Per Share of $1.90 to $2.05. We are also initiating guidance for 2015. We expect Adjusted EBITDA of $1,900 million to $2,100 million, Adjusted Free Cash Flow of $810 million to $1,010 million and Adjusted Free Cash Flow Per Share of $2.10 to $2.60. We also expect to invest $355 million in our ongoing growth-related projects during the year, including the expected completion of our Garrison Energy Center and the start of construction of our York 2 Energy Center. INVESTOR CONFERENCE CALL AND WEBCAST We will host a conference call to discuss our financial and operating results for the third quarter of 2014 on Thursday, November 6, 2014, at 10 a.m. Eastern time / 9 a.m. Central time. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing (800) 447-0521 in the U.S. or (847) 413-3238 outside the U.S. The confirmation code is 38036868. An archived recording of the call will be made available for a limited time on our website or by dialing (888) 843-7419 in the U.S. or (630) 652-3042 outside the U.S. and providing confirmation code 38036868. Presentation materials to accompany the conference call will be available on our website on November 6, 2014. ABOUT CALPINE Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources. Our fleet of 87 power plants in operation or under construction represents approximately 26,000 megawatts of generation capacity. Serving customers in 17 states and Canada, we specialize in developing, constructing, owning and operating natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our clean, efficient, modern and flexible fleet is uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. We focus on competitive wholesale power markets and advocate for market-driven solutions that result in nondiscriminatory forward price signals for investors. Please visit www.calpine.com to learn more about why Calpine is a generation ahead - today. Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, has been filed with the Securities and Exchange Commission (SEC) and may be found on the SEC’s website at www.sec.gov. FORWARD-LOOKING INFORMATION In addition to historical information, this release contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this release. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to: Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability to hedge risks; Laws, regulations and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate; Our ability to manage our liquidity needs and to comply with covenants under our First Lien Notes, Senior Unsecured Notes, Corporate Revolving Facility, First Lien Term Loans, CCFC Term Loans and other existing financing obligations; Risks associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies; Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of water to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources; The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated thereunder; Competition, including risks associated with marketing and selling power in the evolving energy markets; Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools; The expiration or early termination of our PPAs and the related results on revenues; Future capacity revenues may not occur at expected levels; Natural disasters, such as hurricanes, earthquakes and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants serve and our corporate headquarters; Disruptions in or limitations on the transportation of natural gas, fuel oil and transmission of power; Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions; Our ability to attract, motivate and retain key employees; Present and possible future claims, litigation and enforcement actions; and Other risks identified in this press release and in our 2013 Form 10-K. Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise. CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (Unaudited) Basic earnings per common share attributable to Calpine: Weighted average shares of common stock outstanding (in thousands) 398,232 434,384 411,534 444,486 Net income per common share attributable to Calpine — basic $ 1.54 $ 0.70 $ 1.79 $ 0.25 Diluted earnings per common share attributable to Calpine: Weighted average shares of common stock outstanding (in thousands) $ 402,962 $ 438,493 $ 416,056 $ 448,546 Net income per common share attributable to Calpine — diluted $ 1.52 $ 0.70 $ 1.77 $ 0.25 CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) September 30, 2014 Total current liabilities CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) (14 ) (25 ) (219 ) (111 ) (11 ) (472 ) (1 ) (468 ) (1,022 ) (51 ) (27 ) (462 ) (207 ) (260 ) __________ (1) Includes depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated Condensed Statements of Operations. REGULATION G RECONCILIATIONS Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance. Net Income (Loss), As Adjusted, represents net income (loss) attributable to Calpine, adjusted for certain non-cash and non-recurring items as previously detailed in Table 1, including mark-to-market (gain) loss on derivatives, and other adjustments. Net Income (Loss), As Adjusted, is presented because we believe it is a useful tool for assessing the operating performance of our company in the current period. Net Income (Loss), As Adjusted, is not intended to represent net income (loss), the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, revenue from renewable energy credits, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities including natural gas transactions hedging future power sales, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent income (loss) from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Adjusted EBITDA represents net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization, adjusted for certain non-cash and non-recurring items as detailed in the following reconciliation. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. We believe Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effects of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any extraordinary, unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends. In summary, our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance. Adjusted Free Cash Flow represents net income before interest, taxes, depreciation and amortization, as adjusted, less operating lease payments, major maintenance expense and maintenance capital expenditures, net cash interest, cash taxes and other adjustments, including non-recurring items. Adjusted Free Cash Flow is presented because we believe it is a useful tool for assessing the financial performance of our company in the current period. Adjusted Free Cash Flow is a performance measure and is not intended to represent net income (loss), the most directly comparable U.S. GAAP measure, or liquidity and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin Reconciliation During the third quarter of 2014, we altered the composition of our geographic segments to combine our former North and Southeast segments into one segment which was renamed the East segment. This change reflects the manner in which our geographic information is presented internally to our chief operating decision maker following the sale of six power plants in July 2014 from what was formerly our Southeast segment. Thus, beginning in the third quarter of 2014, our reportable segments are West (including geothermal), Texas and East (including North, Southeast and Canada). During the fourth quarter of 2013, we changed the methodology previously used during 2013 for allocating corporate expenses to our segments. This change had no impact to our Consolidated Condensed Statements of Operations for the three and nine months ended September 30, 2013; however, segment amounts previously reported for the three and nine months ended September 30, 2013, were adjusted by immaterial amounts. The following tables reconcile our Commodity Margin to its U.S. GAAP results for the three months ended September 30, 2014 and 2013 (in millions): The following tables reconcile our Commodity Margin to its U.S. GAAP results for the nine months ended September 30, 2014 and 2013 (in millions): _________ (1) Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was not significant for the three months ended September 30, 2014. Commodity Margin related to these plants was $65 million for the three months ended September 30, 2013. (2) Includes $49 million and $44 million of lease levelization and $4 million and $4 million of amortization expense for the three months ended September 30, 2014 and 2013, respectively. (3) Our East segment includes Commodity Margin of $81 million and $122 million for the nine months ended September 30, 2014 and 2013, respectively, related to the six power plants in our East segment that were sold in July 2014. (4) Includes $(7) million and $17 million of lease levelization and $11 million and $11 million of amortization expense for the nine months ended September 30, 2014 and 2013, respectively. Consolidated Adjusted EBITDA Reconciliation In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our net income attributable to Calpine for the three and nine months ended September 30, 2014 and 2013, as reported under U.S. GAAP. Three Months EndedSeptember 30, Nine Months EndedSeptember 30, _________ (1) Adjusted EBITDA related to the six power plants sold in our East segment on July 3, 2014, was not significant for the three months ended September 30, 2014. Adjusted EBITDA related to these plants was $54 million for the three months ended September 30, 2013. (2) Our East segment includes Adjusted EBITDA of $43 million and $75 million for the nine months ended September 30, 2014 and 2013, respectively, related to the six power plants in our East segment that were sold in July 2014. (3) Depreciation and amortization expense in the income from operations calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets. (4) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for each of the three and nine months ended September 30, 2014 and 2013. (5) Includes $39 million and $195 million in major maintenance expense for the three and nine months ended September 30, 2014, respectively, and $28 million and $131 million in maintenance capital expenditure for the three and nine months ended September 30, 2014, respectively. Includes $34 million and $185 million in major maintenance expense for the three and nine months ended September 30, 2013, respectively, and $28 million and $118 million in maintenance capital expenditure for the three and nine months ended September 30, 2013, respectively. (6) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (7) Excludes a decrease in working capital of $24 million and an increase of $18 million for the three and nine months ended September 30, 2014, respectively, and an increase in working capital of $59 million and $265 million for the three and nine months ended September 30, 2013, respectively. Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance. In the following table, we have reconciled our Adjusted EBITDA to our Commodity Margin, both of which are non-GAAP measures, for the three and nine months ended September 30, 2014 and 2013. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. Amounts below are shown exclusive of the noncontrolling interest. _________ (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 _________ (1) For purposes of Net Income guidance reconciliation, mark-to-market adjustments are assumed to be nil. (2) Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, income tax expense and other items. (3) Includes projected major maintenance expense of $240 million and maintenance capital expenditures of $165 million. Capital expenditures exclude major construction and development projects. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance _________ (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: ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us.

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE:CPN) today completed the previously announced sale of six power plants to an affiliate of LS Power for $1.57 billion plus adjustments. The portfolio of divested assets comprises 3,498 MW of combined-cycle generation capacity across five states in the Southeastern U.S., a non-core market. As a result of this sale, Calpine has further aligned its portfolio with its strategic focus on competitive wholesale power markets. “The closing of this transaction represents an important milestone in our ongoing efforts to allocate capital effectively,” said Thad Hill, Calpine’s President and Chief Executive Officer. “By divesting these non-core assets, we have captured significant value for our shareholders, freeing capital for redeployment into higher return opportunities.” Calpine expects to record a net book gain of approximately $750 million in the third quarter as a result of the sale. Taxable gains are expected to be almost entirely offset by federal and state net operating losses. As a result, the transaction is expected to result in net cash proceeds of approximately $1.53 billion, which the company intends to allocate in a balanced manner that is accretive to Adjusted Free Cash Flow Per Share. Management intends to discuss its capital allocation plans and financial guidance on its second quarter 2014 financial results conference call. Second Quarter 2014 Financial Results Conference Call Calpine also announced today that it plans to release second quarter 2014 financial results on Friday, August 1, 2014, before the opening of the New York Stock Exchange. Management will present the results during an investor call scheduled for 10 a.m. Eastern Time / 9 a.m. Central Time on August 1. A listen-only webcast of the call may be accessed through the Company’s website at www.calpine.com or by dialing (800) 446-1671 in the United States or (847) 413-3362 outside the United States. The confirmation code is 37498051. Please call in 10 to 15 minutes prior to the scheduled start time. An archived recording of the call will also be made available on the website and can be accessed by dialing (888) 843-7419 in the United States or 630-652-3042 outside the United States and providing confirmation code 37498051. About Calpine Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources. Our fleet of 87 power plants in operation or under construction represents approximately 26,000 megawatts of generation capacity. Serving customers in 17 states and Canada, we specialize in developing, constructing, owning and operating natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our clean, efficient, modern and flexible fleet is uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. We focus on competitive wholesale power markets and advocate for market-driven solutions that result in nondiscriminatory forward price signals for investors. Please visit www.calpine.com to learn more about why Calpine is a generation ahead – today. 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 of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions identify forward-looking statements. Such statements include, among others, those concerning expected financial performance and strategic and operational plans, as well as 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. Please see the risks identified in this release or in Calpine’s reports and registration statements filed with the Securities and Exchange Commission, including, without limitation, the risk factors identified in its Annual Report on Form 10-K for the year ended Dec. 31, 2013. These filings are available by visiting the Securities and Exchange Commission’s website at www.sec.gov or Calpine’s website at www.calpine.com. 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. Actual results or developments may differ materially from the expectations expressed or implied in the forward-looking statements, and, other than as required by law, Calpine undertakes no obligation to update any such statements, whether as a result of new information, future events, or otherwise.

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE: CPN) Summary of First Quarter 2014 Financial Results (in millions, except per share amounts): Reaffirming 2014 Full Year Guidance3 (in millions, except per share amounts): Recent Achievements: Operations:— Generated approximately 24 million MWh4 of electricity in first quarter of 2014— Leveraged dual-fuel capabilities in Mid-Atlantic and Northeast U.S. to reliably provide power during extreme winter weather— Despite extreme weather conditions, delivered low fleetwide forced outage factor of 2.5% Capital Management:— Announced value-enhancing agreement to divest approximately 3.5 GW of non-core assets from our Southeast portfolio for $1.57 billion5— Completed acquisition of Guadalupe Energy Center in Texas and closed related $425 million term loan— Reached final stages of construction for expansions of Deer Park and Channel Energy Centers in Texas, which are expected to commence commercial operations during the second quarter of 2014— Advanced construction on Garrison Energy Center in Delaware, which is expected to commence commercial operations during the second quarter of 2015 Calpine Corporation (NYSE: CPN) today reported first quarter 2014 Adjusted EBITDA of $446 million, compared to $286 million in the prior year period, and Adjusted Free Cash Flow of $130 million, or $0.31 per diluted share, compared to $(43) million, or $(0.10) per diluted share, in the prior year period. Net Loss1 for the first quarter of 2014 was $17 million, or $0.04 per diluted share, compared to $125 million, or $0.28 per diluted share, in the prior year period. Net Income, As Adjusted2, for the first quarter of 2014 was $55 million compared to a Net Loss, As Adjusted2, of $70 million in the prior year period. The increases in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted2, were driven primarily by higher Commodity Margin resulting from stronger market conditions driven by colder than normal weather, our ability to capture the value of our dual-fuel-capable plants in the North during extreme commodity pricing conditions, portfolio changes and higher regulatory capacity revenue. “Calpine’s power generation fleet and commercial operations produced record-breaking financial results in the first quarter of 2014,” said Jack Fusco, Calpine’s Chief Executive Officer. “Our versatile combined-cycle and dual-fueled fleet performed exceptionally well this winter, providing essential power to the grid during times of scarcity and price volatility. Despite the extreme weather conditions, our workforce preparedness and preventive maintenance enabled us to deliver a low forced outage factor of 2.5%. Our strong results confirm that Calpine has the right fleet, in the right place, at the right time. “We continue to strategically reposition the company with the recently announced sale of six power plants in our Southeast region for $1.57 billion,” said Fusco. “This transaction unlocks shareholder value from these non-core, historically underappreciated assets, and we intend to redeploy the capital in a balanced and opportunistic manner that is accretive to Adjusted Free Cash Flow Per Share. “As I reflect on my six years as CEO, I am proud of the strategic, operational and financial accomplishments of the Calpine team. I am confident that Calpine is very well positioned for further success and that Thad Hill is the right leader to capitalize upon those efforts as we navigate the ongoing secular shift in the U.S. power generation sector. As Executive Chairman, I expect to dedicate more time to focusing on corporate strategy including our capital allocation efforts, in order to maximize shareholder returns while also increasing my efforts to advocate for competitive markets and responsible environmental regulation.” __________ 1 Reported as Net Loss attributable to Calpine on our Consolidated Condensed Statements of Operations. 2 Refer to Table 1 for further detail of Net Income (Loss), As Adjusted. 3 2014 guidance assumes closing of previously announced Southeast asset divestiture as of June 1, 2014. 4 Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants. 5 Subject to working capital and other adjustments. SUMMARY OF FINANCIAL PERFORMANCE First Quarter Results Adjusted EBITDA for the first quarter of 2014 was $446 million compared to $286 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily related to a $184 million increase in Commodity Margin, which was primarily due to: Net Loss1 was $17 million for the first quarter of 2014, compared to $125 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $55 million in the first quarter of 2014 compared to a Net Loss, As Adjusted2, of $70 million in the prior year period. The year-over-year improvement was driven largely by: Adjusted Free Cash Flow was $130 million in the first quarter of 2014 compared to $(43) million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to the increase in Adjusted EBITDA, as previously discussed. Table 1: Net Income (Loss), As Adjusted __________ (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 unrealized (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) West Region First Quarter: Commodity Margin in our West segment was unchanged in the first quarter of 2014 compared to the prior year period. Primary drivers were: lower contribution from hedges. Texas Region First Quarter: Commodity Margin in our Texas segment increased by $45 million in the first quarter of 2014 compared to the prior year period. Primary drivers were: North Region First Quarter: Commodity Margin in our North segment increased by $125 million in the first quarter of 2014 compared to the prior year period. Primary drivers were: Southeast Region First Quarter: Commodity Margin in our Southeast segment increased by $14 million in the first quarter of 2014 compared to the prior year period. Primary drivers were: LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES Table 3: Liquidity 649 __________ (1) Includes $18 million and $5 million of margin deposits posted with us by our counterparties at March 31, 2014, and December 31, 2013, respectively. Liquidity was approximately $1.6 billion as of March 31, 2014. Cash and cash equivalents decreased during the first quarter of 2014 primarily resulting from the use of $244 million in cash on hand to fund the purchase of Guadalupe Energy Center, $140 million in share repurchases, $37 million in payments to fund the construction of Garrison Energy Center and the expansions of our Channel and Deer Park Energy Centers as well as other seasonal variations in working capital, which cause fluctuations in our cash and cash equivalents. Table 4: Cash Flow Activities Cash flows from operating activities in the first quarter of 2014 resulted in net inflows of $123 million compared to net outflows of $157 million in the first quarter of 2013. The increase in cash provided by operating activities was primarily due to an increase in income from operations (adjusted for non-cash items). Also contributing to the increase was a decrease in working capital employed, largely due to a decrease in net accounts receivable/accounts payable balances resulting from timing of cash receipts/disbursements, along with reduced margin requirements. These increases were partially offset by higher cash paid for interest due to timing of interest payments. Cash flows used in investing activities were $769 million in the first quarter of 2014 compared to $122 million in the first quarter of 2013. The increase in outflows was primarily due to the $656 million purchase of our Guadalupe Energy Center in 2014 with no corresponding acquisition activity in the first quarter of 2013. Cash flows provided by financing activities were $220 million and were primarily related to proceeds received from the issuance of CCFC Term Loans used to fund a portion of the purchase price of our Guadalupe Energy Center, partially offset by payments associated with execution of our share repurchase program. CAPITAL ALLOCATION Sale of Six Southeast Power Plants On April 17, 2014, we entered into a purchase and sale agreement to sell six of our power plants in the Southeast segment for a purchase price of approximately $1.57 billion in cash, subject to working capital and other adjustments. The divestiture of these power plants will better align our asset base with our strategic focus on competitive wholesale markets. Share Repurchase Program In November 2013, our Board of Directors authorized a new $1.0 billion multi-year share repurchase program, under which we have repurchased a total of 12,759,919 shares of our common stock for approximately $245 million at an average price of $19.18 per share as of the date of this release. In February 2014, we temporarily suspended our share repurchase program during our negotiations regarding the aforementioned transaction. PLANT DEVELOPMENT Texas: Channel and Deer Park Expansions: In the fourth quarter of 2012, we began construction to expand the baseload capacity of our Deer Park and Channel Energy Centers by approximately 260 MW6 each. Each power plant features an oversized steam turbine that, along with existing plant infrastructure, allows us to add capacity and improve the power plant’s overall efficiency at a meaningful discount to the market cost of building new capacity. We expect commercial operations on the expansions of our Channel and Deer Park Energy Centers to commence during the second quarter of 2014. Guadalupe Energy Center: On February 26, 2014, we, through our indirect, wholly owned subsidiary Calpine Guadalupe GP, LLC, completed the purchase of a power plant owned by MinnTex Power Holdings, LLC with a nameplate capacity of 1,050 MW for approximately $625 million, excluding working capital adjustments. The addition of this modern, natural gas-fired, combined-cycle power plant increased capacity in our Texas segment, which is one of our core markets. We also paid $15 million to acquire the rights to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker. We funded the acquisition with $425 million in incremental CCFC Term Loans and cash on hand. North: 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. Construction commenced in April 2013, and we expect commercial operations to commence during the second quarter of 2015. The project’s capacity cleared PJM’s 2015/2016 and 2016/2017 base residual auctions. We are in the early stages of development of a second phase (309 MW) of this project. PJM has completed the feasibility and system impact studies for this phase, and the facilities study is currently underway. Mankato Power Plant Expansion: We are proposing a 345 MW expansion of the Mankato Power Plant in response to a competitive resource acquisition process established by the Minnesota Public Utilities Commission (“MPUC”) to acquire up to approximately 500 MW of new capacity. The initial stage of the proceeding was managed via a contested case hearing. On March 27, 2014, the MPUC agreed in part and disagreed in part with the recommendation of the Administrative Law Judge and directed Xcel Energy (Northern States Power) to negotiate in parallel PPAs with Calpine and certain other entities, subject to final review and approval by the MPUC. A decision is expected in late 2014 or early 2015. PJM Development Opportunities: We are currently evaluating opportunities to develop more than 1,000 MW 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 (permits, zoning, transmission, etc.) for their potential development at a future date. All Segments: Turbine Modernization: We continue to move forward with our turbine modernization program. Through March 31, 2014, we have completed the upgrade of twelve Siemens and eight GE turbines totaling approximately 200 MW and have committed to upgrade approximately four additional turbines. Similarly, we have the opportunity at several of our power plants in Texas to implement further turbine modernizations to add as much as 500 MW of incremental capacity across the region at attractive prices. In addition, we have begun a program to update our dual-fueled turbines at certain of our power plants in our North segment. Our decision to invest in these modernizations depends upon, among other things, further clarity on market design reforms currently being considered. ___________ 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 First Quarter 2014 Power Operations Achievements Safety Performance:— Maintained top quartile7 safety metrics: 0.80 Total Recordable Incident Rate Availability Performance:— Despite extreme weather conditions, achieved a low fleetwide forced outage factor of 2.5% and impressive fleetwide starting reliability of 97.4% Geothermal Generation:— Provided approximately 1.4 million MWh of renewable baseload generation Natural Gas-fired Generation:— Provided approximately 350,000 MWh of reliable oil-fired generation from dual-fuel PJM fleet during extreme weather conditions— Pastoria Energy Center: 0% forced outage factor, 100% starting reliability ___________ 7 According to EEI Safety Survey (2012). 2014 FINANCIAL OUTLOOK (in millions, except per share amounts) ________ (1) Includes projected major maintenance expense of $220 million and maintenance capital expenditures of $160 million. 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. As detailed above, today we are reaffirming our 2014 guidance, even after accounting for the impact of our announced Southeast asset divestiture. We project Adjusted EBITDA of $1,900 million to $2,000 million, Adjusted Free Cash Flow of $785 million to $885 million and Adjusted Free Cash Flow Per Share guidance of $1.85 to $2.10. We expect to invest $200 million (net of debt funding) in our ongoing growth-related projects during the year, including the expected completion of our Deer Park and Channel Energy Center expansions and ongoing construction of our Garrison Energy Center. INVESTOR CONFERENCE CALL AND WEBCAST We will host a conference call to discuss our financial and operating results for the first quarter of 2014 on Thursday, May 1, 2014, at 10 a.m. Eastern time / 9 a.m. Central time. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing (800) 447-0521 in the U.S. or (847) 413-3238 outside the U.S. The confirmation code is 36846002. 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 36846002. Presentation materials to accompany the conference call will be available on our website on May 1, 2014. ABOUT CALPINE Calpine Corporation generates more electricity than any other independent power producer in America, with a fleet of 94 power plants in operation or under construction, representing more than 29,000 megawatts of generation capacity. Serving customers in 20 states and Canada, we specialize in developing, constructing, owning and operating natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our clean, efficient, modern and flexible fleet is uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. We focus on competitive wholesale power markets and advocate for market-driven solutions that result in nondiscriminatory forward price signals for investors. Please visit www.calpine.com to learn more about why Calpine is a generation ahead - today. Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 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 to hedge risks; Laws, regulation and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate; Our ability to manage our liquidity needs and to comply with covenants under our First Lien Notes, Corporate Revolving Facility, First Lien Term Loans, CCFC Term Loans and other existing financing obligations; Risks associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies; Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of water to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources; The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated thereunder; Competition, including risks associated with marketing and selling power in the evolving energy markets; Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools; The expiration or early termination of our PPAs and the related results on revenues; Future capacity revenues may not occur at expected levels; Natural disasters, such as hurricanes, earthquakes and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants serve and our corporate headquarters; Disruptions in or limitations on the transportation of natural gas, fuel oil and transmission of power; Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions; Our ability to attract, motivate and retain key employees; Present and possible future claims, litigation and enforcement actions; and Other risks identified in this press release and in our 2013 Form 10-K. Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise. CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (Unaudited) Basic and diluted loss per common share attributable to Calpine: Weighted average shares of common stock outstanding (in thousands) 420,105 451,706 Net loss per common share attributable to Calpine — basic and diluted $ (0.04 ) $ (0.28 ) CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) CALPINE CORPORATION AND SUBSIDIARIESCONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) __________ (1) Includes depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated Condensed Statements of Operations. REGULATION G RECONCILIATIONS Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance. Net Income (Loss), As Adjusted, represents net income (loss) attributable to Calpine, adjusted for certain non-cash and non-recurring items as previously detailed in Table 1, including unrealized 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 the unrealized portion of our 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 it 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 effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any unrealized 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, non-cash GAAP-related adjustments to levelize revenues from tolling contracts, gains or losses on the repurchase or extinguishment of debt 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. During the fourth quarter of 2013, we changed the methodology previously used during 2013 for allocating corporate expenses to our segments. This change had no impact to our Consolidated Condensed Statements of Operations for any period in 2013; however, segment amounts previously reported for the first three quarterly periods in 2013 were adjusted by immaterial amounts. Adjusted Free Cash Flow represents net income before interest, taxes, depreciation and amortization, as adjusted, less operating lease payments, major maintenance expense and maintenance capital expenditures, net cash interest, cash taxes and other adjustments, including non-recurring items. Adjusted Free Cash Flow is presented because we believe it is a useful tool for assessing the financial performance of our company in the current period. Adjusted Free Cash Flow is a performance measure and is not intended to represent net income (loss), the most directly comparable U.S. GAAP measure, or liquidity and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin Reconciliation The following table reconciles our Commodity Margin to its U.S. GAAP results for the three months ended March 31, 2014 and 2013 (in millions): _________ (1) Includes $(29) million and $(16) million of lease levelization and $4 million and $4 million of amortization expense for the three months ended March 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 loss attributable to Calpine for the three months ended March 31, 2014 and 2013, as reported under U.S. GAAP. 420,105 _________ (1) Depreciation and amortization expense in the income from operations calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets. (2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized (gain) loss on mark-to-market activity of nil for each of the three months ended March 31, 2014 and 2013. (3) Includes $83 million and $66 million in major maintenance expense for the three months ended March 31, 2014 and 2013, respectively, and $50 million and $70 million in maintenance capital expenditures for the three months ended March 31, 2014 and 2013, respectively. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (5) Excludes an increase in working capital of $6 million and $94 million for the three months ended March 31, 2014 and 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 ended March 31, 2014 and 2013. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. _________ (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. (4) Amount is composed of income from unconsolidated investments in power plants, as well as adjustments to reflect Adjusted EBITDA from unconsolidated investments. Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance _________ (1) 2014 guidance assumes closing of previously announced Southeast asset divestiture as of June 1, 2014. (2) For purposes of Net Income guidance reconciliation, unrealized mark-to-market adjustments are assumed to be nil. (3) Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, income tax expense and other items. (4) Includes projected major maintenance expense of $220 million and maintenance capital expenditures of $160 million. Capital expenditures exclude major construction and development projects. (5) 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 continuing operations: North 3,645 3,909 Southeast 3,624 3,722 Southeast 97.6 % 94.1 % Average capacity factor, excluding peakers Southeast 32.8 % 33.7 % Southeast 7,377 7,269 ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us.

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE:CPN) Summary of 2013 Financial Results (in millions, except per share amounts): Raising 2014 Full Year Guidance (in millions, except per share amounts): 2014 Prior Guidance(as of Nov. 7, 2013) 2014Current Guidance Recent Achievements: Operations:— Generated approximately 104 million MWh3 of electricity in 2013— Achieved record-low annual fleetwide forced outage factor: 1.6%— Delivered impressive annual fleetwide starting reliability: 98.5% Commercial:— Announced acquisition of Guadalupe Energy Center, a 1,050 MW combined-cycle power plant in Texas, for approximately $625 million, or $595/kW— Advanced construction of growth projects totaling approximately 700 MW in Texas and the Mid-Atlantic— Entered into new ten-year PPA with Sonoma Clean Power Authority to provide 10 MW of renewable power from our Geysers assets Capital Management:— During the fourth quarter, completed cumulative $1.1 billion of previously announced share repurchase authorizations— Subsequently completed approximately $239 million of share repurchases under recently announced $1 billion multi-year authorization— During 2013, refinanced or repriced approximately $6 billion of our debt, achieving material interest savings and extending maturities Calpine Corporation (NYSE: CPN) today reported fourth quarter 2013 Adjusted EBITDA of $399 million, compared to $315 million in the prior year period, and Adjusted Free Cash Flow of $126 million, or $0.29 per diluted share, compared to $41 million, or $0.09 per diluted share, in the prior year period. Net Loss1 for the fourth quarter of 2013 was $97 million, or $0.23 per diluted share, compared to Net Income1 of $100 million, or $0.22 per diluted share, in the prior year period. Net Income, As Adjusted2, for the fourth quarter of 2013 was $5 million compared to a Net Loss, As Adjusted2, of $86 million in the prior year period. The increases in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted2, were driven primarily by higher Commodity Margin resulting from portfolio changes, higher regulatory capacity payments and new contracts. Full year 2013 Adjusted EBITDA was $1,830 million, compared to $1,749 million in the prior year period, and Adjusted Free Cash Flow was $677 million, or $1.52 per diluted share, compared to $564 million, or $1.20 per diluted share, in the prior year period. Net Income1 for 2013 was $14 million, or $0.03 per diluted share, compared to $199 million, or $0.42 per diluted share, in the prior year period. Net Income, As Adjusted2, for 2013 was $170 million compared to $78 million in the prior year period. The increases in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted2, were driven primarily by the same factors that drove favorable performance in the fourth quarter, as well as lower interest expense due to a decrease in our annual effective interest rate as a result of the refinancing activities of 2012 and 2013. “We are proud to report that Calpine successfully delivered on its 2013 financial commitments, achieving $1.52 of Adjusted Free Cash Flow Per Share, a year-over-year increase of approximately 27%,” said Jack Fusco, Calpine’s Chief Executive Officer. “Calpine’s best-in-class fleet and dedicated personnel provided the foundation for our solid performance. In 2013, we achieved a record-low fleetwide forced outage factor and impressive starting reliability, thanks in large part to our ongoing preventative maintenance program. This fleet optimization enabled us to deliver on our customer commitments and commercial obligations, while maintaining strict cost management. “Our strong financial results were also driven by opportunistic portfolio management, customer-oriented origination, prudent risk management and disciplined capital allocation. These factors, along with operational excellence, are the hallmarks of a premier power generation company, and in our view, will continue to drive sustainable growth for our shareholders over the long term,” said Fusco. “Toward this end, we are raising our 2014 Adjusted EBITDA guidance range by $100 million to $1.9 billion to $2.0 billion. This results in an increase in our Adjusted Free Cash Flow Per Share guidance range to $1.85 to $2.10, representing approximately 30% year-over-year growth based on the midpoint. This revised guidance reflects our pending acquisition of the 1,050 MW Guadalupe CCGT in Texas, which we expect to close during the first quarter, coupled with a good start to the year and the repurchase of approximately 13 million shares since our last update. “Finally, I would like to note that in the face of extreme cold weather during the first six weeks of this year, our versatile Mid-Atlantic and Northeast dual-fueled fleet performed exceptionally well, providing essential power to the grid during times of scarcity and extreme price volatility,” said Fusco. “This weather has highlighted the importance of flexible and reliable generation as the power grid shifts away from old, uneconomic coal and nuclear plants and becomes increasingly reliant upon intermittent renewable generation and demand response. Grid operators continue to refine energy and capacity markets in an effort to identify market-driven solutions that result in nondiscriminatory investment signals for generating units with the right characteristics to balance the grid of the future.” __________ 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. SUMMARY OF FINANCIAL PERFORMANCE Fourth Quarter Results Adjusted EBITDA for the fourth quarter of 2013 was $399 million, compared to $315 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily related to a $74 million increase in Commodity Margin, which was primarily due to: our Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013 and the acquisition of Bosque Energy Center in November 2012, partially offset by the sale of our Broad River and Riverside Energy Centers in December 2012 Net Loss1 was $97 million for the fourth quarter of 2013, compared to Net Income1 of $100 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $5 million in the fourth quarter of 2013 compared to a Net Loss1, As Adjusted2, of $86 million in the prior year period. The year-over-year improvement was driven largely by: lower plant operating expense primarily due to a decrease in mainly production-related expenses and salaries and benefits, partially offset by higher depreciation and amortization expense due to the acquisition of Bosque Energy Center in November 2012 and the commencement of commercial operations at our Russell City and Los Esteros power plants in August 2013. Adjusted Free Cash Flow was $126 million in the fourth quarter of 2013 compared to $41 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to an increase in Adjusted EBITDA, as previously discussed. Full Year Results Adjusted EBITDA in 2013 was $1,830 million compared to $1,749 million in the prior year period. The year-over-year increase was primarily due to a $47 million decrease in plant operating expense4, driven by factors similar to those discussed in the results for the fourth quarter, and a $30 million increase in Commodity Margin. 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 and the acquisition of Bosque Energy Center in November 2012, partially offset by the sale of our Broad River and Riverside Energy Centers in December 2012 Net Income1 was $14 million in 2013 compared to $199 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $170 million in 2013 compared to $78 million in the prior year period. The favorable year-over-year improvement in Net Income, As Adjusted2, reflects: lower plant operating expense, primarily due to a decrease in mainly production-related costs, salaries and benefits and the reversal of previously recognized regulatory fees for which we determined that we have no current or retroactive fee obligation as well as lower equipment failure costs, partially offset by higher depreciation and amortization expense due to the acquisition of Bosque Energy Center in November 2012 and the commencement of commercial operations at our Russell City and Los Esteros power plants in August 2013. Adjusted Free Cash Flow was $677 million for 2013 compared to $564 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to higher Adjusted EBITDA and lower interest expense, as previously discussed. 4 Decrease 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, 2013 and 2012. Table 1: Net Income (Loss), As Adjusted __________ (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 unrealized (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) Other items for the year ended December 31, 2012, include realized mark-to-market losses associated with the settlement of non-hedged interest rate swaps totaling $156 million. Other items for the three months and year ended December 31, 2012, include a $13 million tax refund (including interest) associated with our 2004 amended federal income tax return. (4) 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) West Region Fourth Quarter: Commodity Margin in our West segment increased by $37 million in the fourth quarter of 2013 compared to the prior year period. Primary drivers were: stronger market conditions resulting from lower hydroelectric generation, warmer weather and the impact of the January 1, 2013, implementation of the AB 32 carbon market, partially offset by Full Year: Commodity Margin in our West segment increased by $26 million in 2013 compared to the prior year period. Full year results were largely impacted by the same factors that drove comparative performance for the fourth quarter, as previously discussed. Texas Region Fourth Quarter: Commodity Margin in our Texas segment decreased by $3 million in the fourth quarter of 2013 compared to the prior year period. Primary drivers were: Full Year: Commodity Margin in our Texas segment increased by $62 million in 2013 compared to the prior year period. Primary drivers were: higher contribution from hedges the acquisition of Bosque Energy Center in November 2012 and + higher spark spreads during the fourth quarter of 2013 resulting from stronger market conditions due to colder weather, partially offset by North Region Fourth Quarter: Excluding a $9 million decrease from the sale of our Riverside Energy Center in December 2012, Commodity Margin in our North segment increased by $40 million in the fourth quarter of 2013 compared to the prior year period, primarily as a result of higher regulatory capacity revenues. Full Year: Excluding a $73 million decrease from the sale of our Riverside Energy Center in December 2012, Commodity Margin in our North segment increased by $56 million in 2013 compared to the prior year period. Primary drivers were: weaker market conditions driven by milder weather and a reversal of coal-to-gas switching due to higher natural gas prices. Southeast Region Fourth Quarter: Excluding an $8 million decrease from the sale of our Broad River Energy Center in December 2012, Commodity Margin in our Southeast segment increased by $17 million in the fourth quarter of 2013 compared to the prior year period. Primary drivers were: Full Year: Excluding a $52 million decrease from the sale of our Broad River Energy Center in December 2012, Commodity Margin in our Southeast segment increased by $11 million in 2013, compared to the prior year period. Primary drivers were: LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES Table 3: Liquidity __________ (1) Includes $5 million and $11 million of margin deposits posted with us by our counterparties at December 31, 2013 and 2012, respectively. (2) As a result of the completion of the sale of Riverside Energy Center, LLC, a wholly owned subsidiary of CDHI, on December 31, 2012, we are required to cash collateralize letters of credit issued in excess of $225 million until replacement collateral is contributed to the CDHI collateral package, which we are in the process of arranging. At December 31, 2013, we had no outstanding letters of credit issued in excess of $225 million under our CDHI letter of credit facility that were collateralized by cash. Liquidity was approximately $2 billion as of December 31, 2013. Cash and cash equivalents declined during 2013 due largely to our deployment of capital, including the repurchase of $623 million of our common stock, in addition to the funding of construction payments related to our Russell City, Los Esteros and Garrison Energy Centers and the expansion of our Deer Park and Channel Energy Centers. These expenditures were partially offset by $549 million in cash provided by operations earned during the year as well as $303 million in net proceeds from borrowings. Table 4: Cash Flow Activities Cash flows from operating activities in 2013 resulted in net inflows of $549 million compared to $653 million in 2012. The decrease in cash provided by operating activities was primarily due to an increase in working capital employed, largely as a result of higher net accounts receivable and accounts payable balances due to increased revenues in December 2013. Also contributing to the decrease were higher debt extinguishment costs in 2013 due to payments associated with the redemption of our CCFC notes and a portion of certain First Lien Notes. Partially offsetting the decrease were higher income from operations (adjusted for non-cash items) and lower cash paid for interest due to the refinancing activity of 2013. Cash flows used in investing activities were $593 million in 2013 compared to $470 million in 2012. The increase in outflows was primarily due to net proceeds from asset sale and purchase activity in 2012 that did not recur in 2013, partially offset by $156 million in non-hedging interest rate swap settlements in 2012 that did not recur this year. Cash flows used in financing activities were $299 million and were primarily related to the execution of our share repurchase program, partially offset by net proceeds received from the refinancing activity of 2013 related to our CCFC notes, First Lien Notes and First Lien Term Loans. CAPITAL ALLOCATION Share Repurchase Program Having previously authorized $600 million in repurchases of our common stock, our Board of Directors authorized the repurchase of an additional $400 million in shares of our common stock in February 2013 and an additional $100 million in August 2013. Under the aggregate $1.1 billion of authorizations, we repurchased a total of 60,139,816 shares of our outstanding common stock at an average price of $18.29 per share. In November 2013, our Board of Directors authorized a new $1.0 billion multi-year share repurchase program, under which we have repurchased a total of 12,459,919 shares of our common stock for approximately $239 million at an average price of $19.15 per share as of the date of this release. PLANT DEVELOPMENT West: Russell City Energy Center: Our Russell City Energy Center commenced commercial operations in August 2013, which brought on-line approximately 429 MW of net interest baseload capacity (464 MW with peaking capacity) representing our 75% share. Russell City Energy Center is contracted to deliver its full output to Pacific Gas and Electric Company (PG&E) under a ten-year PPA. Los Esteros Critical Energy Facility: During 2009, we and PG&E negotiated a new ten-year PPA to replace the existing California Department of Water Resources contract and facilitate the modernization of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle generation power plant to a 309 MW combined-cycle generation power plant, which has increased the efficiency and environmental performance of the power plant by lowering the heat rate. Our Los Esteros Critical Energy Facility commenced commercial operations in August 2013. Texas: Channel and Deer Park Expansions: In the fourth quarter of 2012, we began construction to expand the baseload capacity of our Deer Park and Channel Energy Centers by approximately 260 MW5 each. Each power plant features an oversized steam turbine that, along with existing plant infrastructure, allows us to add capacity and improve the power plant’s overall efficiency at a meaningful discount to the market cost of building new capacity. We expect commercial operations on the expansions of our Channel and Deer Park Energy Centers to commence during the second quarter of 2014. Guadalupe Energy Center: On December 2, 2013, we announced an agreement to purchase a natural gas-fired, combined-cycle power plant with a nameplate capacity of 1,050 MW located in Guadalupe County, Texas for approximately $625 million, which will increase capacity in our Texas segment. The purchase price does not include $15 million in consideration for the rights we also acquired to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker, if market conditions warrant. We are currently evaluating funding sources for the acquisition of this power plant including, but not limited to, nonrecourse financing, corporate financing or internally generated funds. North: 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. Construction commenced in April 2013, and we expect commercial operations to commence during the second quarter of 2015. The project’s capacity cleared PJM’s 2015/2016 and 2016/2017 base residual auctions. We are currently evaluating funding sources for the construction of this project including, but not limited to, nonrecourse financing, corporate financing or internally generated funds. We are in the early stages of development of a second phase (309 MW) of this project. PJM has completed the feasibility and system impact studies for this phase, and the facilities study is currently underway. Mankato Power Plant Expansion: We are proposing a 345 MW expansion of the Mankato Power Plant in response to a competitive resource acquisition process for approximately 500 MW of new capacity established by the Minnesota Public Utilities Commission (MPUC). The initial stage of the proceeding was managed via a contested case hearing. On December 31, 2013, the Administrative Law Judge (ALJ) in the contested case issued a non-binding recommendation to the MPUC that the state should secure approximately 100 MW of distributed solar resources at this time and defer procurement of new thermal resources. Xcel Energy (Northern States Power) and the Minnesota Department of Commerce subsequently filed exceptions to the ALJ decision and continue to advocate in support of new, natural gas-fired generation resources. The MPUC will hold deliberations and decide whether to accept, reject or modify the ALJ recommendation in early 2014. PJM Development Opportunities: We are currently evaluating opportunities to develop more than 1,000 MW 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 (permits, zoning, transmission, etc.) for their potential development at a future date. All Segments: Turbine Modernization: We continue to move forward with our turbine modernization program. Through December 31, 2013, we have completed the upgrade of twelve Siemens and eight GE turbines totaling approximately 200 MW and have committed to upgrade approximately four additional turbines. Similarly, we have the opportunity at several of our power plants in Texas to implement further turbine modernizations to add as much as 500 MW of incremental capacity across the region at attractive prices. In addition, we have begun a program to update our dual-fueled turbines at certain of our power plants in our North segment. Our decision to invest in these modernizations depends upon, among other things, further clarity on market design reforms currently being considered. ___________ 5 Represents incremental baseload capacity at annual average conditions. Incremental summer peaking capacity is approximately 200 MW per unit, supplemented by incremental efficiencies across the balance of plant. OPERATIONS UPDATE 2013 Power Operations Achievements Safety Performance:— Maintained top quartile6 safety metrics: 0.88 Total Recordable Incident Rate Availability Performance:— Delivered record-low annual fleetwide forced outage factor: 1.6%— Achieved remarkable fleetwide starting reliability: 98.5% Geothermal Generation:— Provided approximately 6 million MWh of renewable baseload generation for 13th consecutive year Natural Gas-fired Generation:— Otay Mesa Energy Center: 100% starting reliability— Kennedy International Airport Power Plant: 100% starting reliability 2013 Commercial Operations Achievements: Customer-oriented Growth:— Successfully completed construction of our Russell City and Los Esteros power plants in California and began servicing related contracts with PG&E— Entered into a new three-year PPA with South Carolina Electric and Gas Company to provide 200 MW of power generated by our Columbia Energy Center, commencing in January 2014— Entered into two new resource adequacy contracts with PG&E for our Delta and Sutter Energy Centers for the full capacity of each plant which commence in January and June 2014, respectively, and extend through December 2015 and 2016, respectively— Entered into two new PPAs with the Marin Energy Authority consisting of a one-year contract to provide 3 MW of renewable power during 2014 and a ten-year contract to provide 10 MW of renewable power commencing in January 2017. The renewable power to be delivered under both contracts will be generated from our Geysers assets— Entered into a 100 MW financial PPA with a counterparty in PJM which commenced in November 2013 and extends through 2016— Entered into a new five-year PPA commencing in 2014 for approximately 50 MW and extended the existing steam agreement for ten years beyond 2016 with Celanese Ltd for power and steam generated from our Clear Lake Power Plant— Entered into a new ten-year PPA with the Sonoma Clean Power Authority to provide 10 MW of renewable power from our Geysers assets commencing in May 2014. The capacity under contract will increase in increments each year, up to a maximum of 18 MW for years 2020 through 2023 ___________ 6 According to EEI Safety Survey (2012). 2014 FINANCIAL OUTLOOK(in millions, except per share amounts) 1,900 - 2,000 785 - 885 ________ (1) Includes projected major maintenance expense of $220 million and maintenance capital expenditures $160 million. 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 $15 million in consideration for the rights we also acquired to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker, if market conditions warrant, exclusive of adjustments relating to working capital. As detailed above, today we are raising our 2014 guidance. We now project Adjusted EBITDA of $1,900 million to $2,000 million and Adjusted Free Cash Flow of $785 million to $885 million. Similarly, we are raising our Adjusted Free Cash Flow Per Share guidance to $1.85 to $2.10. We expect to invest $200 million (net of debt funding) in our ongoing growth-related projects during the year, including the expected completion of our Deer Park and Channel Energy Center expansions and ongoing construction of our Garrison Energy Center. We also expect to invest $625 million7 in the acquisition of Guadalupe Energy Center, which is expected to close in the first quarter of 2014 and $15 million in consideration for the rights we will concurrently acquire to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker, if market conditions warrant. We are currently evaluating funding sources for the acquisition including, but not limited to, nonrecourse financings, corporate financing or internally generated funds. ___________ 7 Exclusive of adjustments relating to working capital. 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 2013 on Thursday, February 13, 2014, at 10 a.m. Eastern time / 9 a.m. Central time. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing (800) 447-0521 in the U.S. or (847) 413-3238 outside the U.S. The confirmation code is 36388664. 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 36388664. Presentation materials to accompany the conference call will be available on our website on February 13, 2014. ABOUT CALPINE Calpine Corporation generates more electricity than any other independent power producer in America, with a fleet of 93 power plants in operation or under construction, representing more than 28,000 megawatts of generation capacity. Serving customers in 20 states and Canada, we specialize in developing, constructing, owning and operating natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our clean, efficient, modern and flexible fleet is uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. 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, 2013, has been filed with the Securities and Exchange Commission (SEC) and may be found on the SEC’s website at www.sec.gov. FORWARD-LOOKING INFORMATION In addition to historical information, this release contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this release. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to: Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability to hedge risks; Laws, regulations and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate; Our ability to manage our liquidity needs and to comply with covenants under our First Lien Notes, 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 wastewater to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources; The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated thereunder; Competition, including risks associated with marketing and selling power in the evolving energy markets; Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools; The expiration or early termination of our PPAs and the related results on revenues; Future capacity revenues may not occur at expected levels; Natural disasters, such as hurricanes, earthquakes and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants serve and our corporate headquarters; Disruptions in or limitations on the transportation of natural gas, fuel oil and transmission of power; Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions; Our ability to attract, motivate and retain key employees; Present and possible future claims, litigation and enforcement actions; and Other risks identified in this press release and in our 2013 Form 10-K. Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise. CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Basic earnings (loss) per common share attributable to Calpine: Weighted average shares of common stock outstanding (in thousands) 429,331 459,304 440,666 467,752 Net income (loss) per common share attributable to Calpine — basic $ (0.23 ) $ 0.22 $ 0.03 $ 0.43 Diluted earnings (loss) per common share attributable to Calpine: Weighted average shares of common stock outstanding (in thousands) 429,331 463,291 444,773 471,343 Net income (loss) per common share attributable to Calpine — diluted $ (0.23 ) $ 0.22 $ 0.03 $ 0.42 CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS December 31, 2013 and 2012 (in millions, except share and per share amounts) CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2013 and 2012 (in millions) (593 Cash flows from financing activities: __________ (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 debt extinguishment costs, unrealized 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 and optimization activities including natural gas transactions hedging future power sales, but excludes the unrealized portion of our 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 it 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 effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any unrealized 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, non-cash GAAP-related adjustments to levelize revenues from tolling contracts, gains or losses on the repurchase or extinguishment of debt 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. During the fourth quarter of 2013, we changed the methodology previously used during 2013 for allocating corporate expenses to our segments. This change had no impact to our Consolidated Statements of Operations for any period in 2013; however, amounts previously reported for income (loss) from operations by segment for the first three quarterly periods in 2013 were impacted by immaterial amounts. Adjusted Free Cash Flow represents net income before interest, taxes, depreciation and amortization, as adjusted, less operating lease payments, major maintenance expense and maintenance capital expenditures, net cash interest, cash taxes and other adjustments, including non-recurring items. Adjusted Free Cash Flow is presented because we believe it is a useful tool for assessing the financial performance of our company in the current period. Adjusted Free Cash Flow is a performance measure and is not intended to represent net income (loss), the most directly comparable U.S. GAAP measure, or liquidity and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin Reconciliation The following table reconciles our Commodity Margin to its U.S. GAAP results for the three months ended December 31, 2013 and 2012 (in millions): The following table reconciles our Commodity Margin to its U.S. GAAP results for the years ended December 31, 2013 and 2012 (in millions): _________ (1) Includes $(11) million and $(6) million of lease levelization and $3 million and $3 million of amortization expense for the three months ended December 31, 2013 and 2012, respectively. (2) Our North segment includes Commodity Margin of $9 million and $73 million for the three months and year ended December 31, 2012, related to Riverside Energy Center, LLC, which was sold in December 2012. (3) Our Southeast segment includes Commodity Margin of $8 million and $52 million for the three months and year ended December 31, 2012, related to Broad River, which was sold in December 2012. (4) Includes $6 million and $1 million of lease levelization and $14 million and $14 million of amortization expense for the years ended December 31, 2013 and 2012, 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, 2013 and 2012, as reported under U.S. GAAP. Three Months EndedDecember 31, (Gain) loss on dispositions of assets _________ (1) Depreciation and amortization expense on our Consolidated Statements of Operations excludes amortization of other assets. (2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized (gain) loss on mark-to-market activity of nil for each of the three and twelve months ended December 31, 2013 and 2012. (3) 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. Includes $42 million and $192 million in major maintenance expense for the three months and year ended December 31, 2012, respectively, and $35 million and $183 million in maintenance capital expenditure for the three months and year ended December 31, 2012, respectively. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (5) Excludes a decrease in working capital of $250 million and an increase in working capital of $130 million for the three months and year ended December 31, 2013, respectively, and a decrease in working capital of $91 million and $107 million for the three months and year ended December 31, 2012, 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 year end December 31, 2013 and 2012. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. _________ (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. (4) Amount is composed of income from unconsolidated investments in power plants, as well as adjustments to reflect Adjusted EBITDA from unconsolidated investments. Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance _________ (1) For purposes of Net Income guidance reconciliation, unrealized 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 $220 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 continuing operations: ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us.