2013 Investor Day April 10, 2013 Exhibit 99.1

2 2 Forward-Looking Statements The information contained in this presentation includes certain estimates, projections and other forward-looking information that reflect Calpine’s current views with respect to future events and financial performance. These estimates, projections and other forward-looking information are based on assumptions that Calpine believes, as of the date hereof, are reasonable. Inevitably, there will be differences between such estimates and actual results, and those differences may be material. There can be no assurance that any estimates, projections or forward-looking information will be realized. All such estimates, projections and forward-looking information speak only as of the date hereof. Calpine undertakes no duty to update or revise the information contained herein other than as required by law. You are cautioned not to place undue reliance on the estimates, projections and other forward-looking information in this presentation as they are based on current expectations and general assumptions and are subject to various risks, uncertainties and other factors, including those set forth in Calpine’s Annual Report on Form 10-K for the year ended December 31, 2012, and in other documents that Calpine files with the SEC. Many of these risks, uncertainties and other factors are beyond Calpine’s control and may cause actual results to differ materially from the views, beliefs and estimates expressed herein. Calpine’s reports and other information filed with the SEC, including the risk factors identified in its Annual Report on Form 10-K for the year ended December 31, 2012, can be found on the SEC’s website at www.sec.gov and on Calpine’s website at www.calpine.com. Reconciliation to U.S. GAAP Financial Information The following presentation includes certain “non-GAAP financial measures” as defined in Regulation G under the Securities Exchange Act of 1934, as amended. Schedules are included herein that reconcile the non-GAAP financial measures included in the following presentation to the most directly comparable financial measures calculated and presented in accordance with U.S. GAAP. Safe Harbor Statement

3 Agenda 3 • Welcome and Safe Harbor Bryan Kimzey VP, Investor Relations • Value Proposition Jack Fusco Chief Executive Officer • Operations & Development Overview Thad Hill President, Chief Operating Officer • Introductory Q&A Jack Fusco Thad Hill Chief Executive Officer President, Chief Operating Officer • Commercial Operations: National Trends Caleb Stephenson VP, Commercial Analytics • Commercial Operations: Regional Trends Steve Pruett SVP, Commercial Operations • Commercial Operations Q&A Steve Pruett Caleb Stephenson Todd Thornton SVP, Commercial Operations VP, Commercial Analytics VP, Commercial Development Break • Power Operations Panel John Adams Ron Macklin Tom Long Ron Hall SVP, Power Operations VP, Outage Services VP, Development & Optimization Engineering VP, Engineering & Construction • Regulatory Panel Thad Miller Yvonne McIntyre Steve Schleimer Mark Smith William Taylor EVP, Chief Legal Officer VP, Governmental & Regulatory Affairs (Federal) VP, Governmental & Regulatory Affairs (North) VP, Governmental & Regulatory Affairs, Legal (West) VP, Governmental & Regulatory Affairs (Texas) • Financial Overview Zamir Rauf EVP, Chief Financial Officer • Executive Q&A

2013 Investor Day: Value Proposition Jack Fusco Chief Executive Officer April 10, 2013

5 Thank You: A Milestone Achievement 5 Jack Fusco Voted Best IR by a CEO or Chairman (Mid-Cap) Calpine IR Nominee for Best IR – Utilities Sector Jack Fusco Voted Best CEO – Elec. Utilities Buy- and Sell-Side Calpine IR Top 3 for Best IR – Elec. Utilities Buy- and Sell-Side 2013 All-America Executive Team Thank you for recognizing our commitment to our shareholders and to providing the investing community with disclosures and access

Calpine: Positioned to Benefit from Secular Trends 6 Stricter Environmental Regulation • State and federal pressures: Primarily focused on health concerns; resurgent climate change debate Insufficient New Capacity in Key Markets Sustained Low Natural Gas Prices Aging Power Generation Infrastructure • Prices must rise to incent economic new investment where needed • “New norm”: 100+ years supply of affordable, domestic natural gas • America’s fleet continues to age; investments in improvements / maintenance less economic ~240,000 MW Source: Energy Velocity. Excludes renewable and hydro units. Source: SNL. Shaded nuclear represent potential retirements, including plants currently not in operation. Est. CCGT new build requirement Source: Calpine, Broker quotes. As of 3/26/13. 32 GW of retirements announced through 2016

7 Myths Around Over-Reliance on Natural Gas in the Power Sector 7 • There is abundant excess capacity in the current fleet, and sufficient time exists to develop new resources. • The level of mid-stream investment is dramatic and growing. • Even with natural gas gaining share, the US will be multi-fuel for a long, long time. Source: U.S. Energy Information Association, December 2012. Coal Nuclear Renewables Natural gas 2 3 4 5 6 1990 2000 2010 2020 2030 2040 0 1 1993 2011 History Projections 30% 16% 17% 35% 1% 13% 11% 19% 53% 4% 25% 13% 19% 42% 1% Oil and other liquids US Electricity Generation: Multi-Fuel • America’s natural gas fleet cannot meet reliability needs. • Pipeline infrastructure cannot support new natural gas demand. • The US will become over-dependent on natural gas. Myth Truth

8 Coal Electric Vehicles Calpine: Strong Generator of Cash, Disciplined in Deployment 8 ($ millions) We will be discerning and disciplined in our capital allocation decisions. Rooftop Solar 1 Represents Cash and Cash Equivalents as of 12/31/12, less estimated cash needed to maintain minimum liquidity of $1 billion. 2 A non-GAAP financial measure. Reconciliations of Adjusted EBITDA and Adjusted Free Cash Flow to Net Income (Loss), the most comparable U.S. GAAP measure, are included herein. Announced Capital Management Further Capital Management: • Organic growth • Acquisition and divestiture opportunities • Additional share repurchases $1,040 $865 - $1,025 $615 - $775 $(140) $(250) $(400) Excess Cash: Dec 2012 1 Adj. FCF 2 Scheduled Debt Amortizations Growth CapEx (Net) Share Repurchases Excess Cash: Dec 2013E

9 Delivering Shareholder Value 9 Demonstrating Strong Financial Performance Adjusted EBITDA ¹ Returning Capital to Shareholders Announced Share Repurchase Authorizations Raising Guidance: $1,800 - $1,960 Enhancing Value Per Share Adjusted Free Cash Flow Per Share ¹ Modest gains in Adj. EBITDA ¹ translate into meaningful gains in Adj. FCF 1 /Share +$300 +$400 1 A non-GAAP financial measure. Reconciliations of Adjusted EBITDA and Adjusted Free Cash Flow to Net Income (Loss), the most comparable U.S. GAAP measure, are included herein. 2 As of 04/05/13. Update: Invested $58MM year-to-date ² Targeting 15 – 20% CAGR

10 Significant Valuation Upside Remains 10 2015 Consensus Adj. EBITDA¹: Conservative Adj. FCF / Share¹ Growth Represents Total Shareholder Return 1 A non-GAAP financial measure. Reconciliations of Adjusted EBITDA and Adjusted Free Cash Flow to Net Income (Loss), the most comparable U.S. GAAP measure, are included herein. 2 Represents estimated 2015 Adj. EBITDA from Deer Park and Channel expansions (scheduled to come online in 2014) and Garrison (scheduled to come online mid-2015). Below current forwards Not in consensus Note: Chart holds Price to Adj. FCF/Share Multiple constant at 13.7, consistent with current trading levels based upon 2013E Adj. FCF/Share. Adj. EBITDA¹ outlook and opportunistic capital allocation drive meaningful valuation upside potential

2013 Investor Day: Operations and Development Overview Thad Hill President, Chief Operating Officer April 10, 2013

12 Shaping Our Footprint to Match our Regional Strategy Note: Capacity shown here represents Calpine’s net interest. 12 West Asset management and regulatory engagement Texas Capitalize on demand- driven market recovery North Capitalize on supply-driven market recovery and organic growth opportunities Southeast Monetize value through long-term contracts or asset divestitures Calpine: 27,321 MW + 1,472 MW Under Construction April 2013

13 Optimizing Fleet Performance 13 Significantly Reduced Forced Outage Factor -53% Goals for 2013 • Safety First to Zero: No lost time incidents • Better than 2.5% FOF • Complete maintenance program: 13 Majors and 20 Hot Gas Paths Maintaining Plant Operating Expense While Expanding Fleet 1 Objective: Premier wholesale power company 1 Plant Operating Expense excluding major maintenance expense, non-cash stock-based compensation, non-cash loss on disposal of assets and other costs. Both Plant Operating Expense and Capacity (MW) shown here exclude deconsolidated power plants, plants owned but not operated by us and plants classified as discontinued operations in the respective periods. 1 $0 $200 $400 $600 $800 $1,000 $1,200 0 5,000 10,000 15,000 20,000 25,000 30,000 2008 2009 2010 2011 2012 Avg. MW in Operation 0% 1% 2% 3% 4% 2008 2009 2010 2011 2012 Plant Operating Expense

14 Adding Value Through Commercial Origination 14 Continued Contracting Success • Focus on demonstrating further value from SE portfolio • Create commercial solutions to bridge CA structural gaps • Continue to expand public power origination efforts (TX, North) • Commercially optimize portfolio Contracts: Effective Form of Asset Monetization Illustrative Contract Economics Mgmt. dialogue initiated Contract commenced Capturing Future Value Represents >$5B (notional) of fixed payments Goals for 2013 Note: Market projection represents extrapolation of current market prices. Shaded bars represent projected capacity lifted in 2016/2017 and 2017/2018 RPM capacity auctions based upon amounts cleared in 2015/2016 auction. Toll/PPA capacity includes contracts at Los Medanos and Gilroy, which are subject to CPUC approval. Why do customers pay? • Avoided cost of new build • Capacity obligations beyond energy • Regulatory requirements • Sometimes regulators or customers want some portion of PPAs Market / Projection T-4 T-2 T T+2 T+4 T+6 T+8 Fundamentals Contract 2013 2017 Toll / PPA Capacity Regulatory Capacity 0 2,500 5,000 7,500 10,000 12,500 15,000 2014 2015 2016 840 1,402 2,095 2010 2011 2012

15 Calpine Development Pipeline: Pursuing Disciplined Growth 2013 2014 2015 2016 2017 Russell City Combined-cycle power plant under 10-year contract with PG&E 464 MW 1 Los Esteros Conversion of existing plant from simple- cycle to combined-cycle technology under 10-year contract with PG&E 120 MW Deer Park Expansion Expansion of existing CCGT in Texas leveraging existing site and equipment 260 MW 2 Channel Expansion Expansion of existing CCGT in Texas leveraging existing site and equipment 260 MW 2 Garrison (Phase 1) Greenfield CCGT leveraging existing equipment and advantaged site 309 MW Deepwater Brownfield CCGT leveraging existing infrastructure and advantaged site 350 MW Texas Upgrade Program Turbine modernizations and other upgrades; Requires market reform 300 MW Mankato Expansion Response to PUC resource acquisition plan; Expansion of existing CCGT leveraging existing site and equipment 345 MW Total 584 MW 520 MW 309 MW 650 MW 345 MW Goals for 2013 • Complete CA construction projects • Keep Deer Park, Channel, Garrison on track • Originate attractive-return growth opportunities — New cogen — Public power • Build set of site options with first mover advantage 1 Represents Calpine share. 2 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 the plant. NEW NEW NEW

16 Operations Organization 16 COO Power Operations Commercial Analytics Commercial Operations Human Resources West Strat. Origination Development Hether Benjamin-Brown Todd Thornton Steve Pruett John Adams Caleb Stephenson Alex Makler Presenter Panelist In Attendance Thad Hill

2013 Investor Day: National Trends Impacting Our Portfolio Caleb Stephenson Vice President, Commercial Analytics April 10, 2013

18 18 Important Trends Impacting Our Portfolio National Caleb Stephenson Regional Steve Pruett Texas • Inefficiency of forward curves, plus • Regulatory shifts (including our new VMP) PJM • Retiring coal + Demand Response = Flattish capacity, but • Real upside in energy Southeast • Capturing significant origination opportunity with load serving entities California • Near-term: SONGS + AB32 • Medium-term: Increasing importance of capacity versus energy Load Trends • Cheer up! Energy efficiency not the end of load growth • Regional diversity: Texas load growth outlook remains robust The “New Build” Spark Spread • Spark spreads needed to motivate new construction likely higher than some think • Operational realities matter Gas Price Immunity • Generation volumes inversely related to gas prices; margin fairly neutral Energy Capacity Views of Value

Energy Efficiency Isn’t New; Additional Efficiency Improvements Needed Just to Keep Pace with Historical Trend 19 Long History of Energy Efficiency GDP Growth > Load Growth = More Efficient Electricity Use More Efficiency Needed Just to Maintain Trend Beating Past Efficiency Trend May Not be Easy Significant portion of past efficiency gains driven by structural shift away from industrial load... Will this continue? Flattening load growth entirely would require efficiency gains equivalent to GDP growth – >2.5x historical efficiency gains Residential Load has Tended to be Resilient Efficiency improvements often offset by new demand; Challenged so far by slow recovery of housing starts • Average new home size up >10% from 1990s • More and larger appliances • Light bulb standards aside, some low-hanging fruit already captured Electricity needed to produce $1 of GDP has decreased by ~1% per year Sustaining GDP Growth of … … and Load Growth of … … Requires an Ongoing Efficiency Gain of … 2.4% 1.5% 0.9% (consistent with history) 1.0% 1.4% (>1.5x history) 0% 2.4% (>2.5x history) We’re not convinced load growth has reached a regime change: Much still seems driven by regional economies … Industrial load now a smaller share of electricity consumption (and economy) Sources: Retail sales total and by sector from EIA , GDP Data from BEA ($ 2005), Calpine Analysis

20 Regionally Diverse Growth Trends: Texas Among Highest Growth Regions 20 Forecast Forecast Forecast Notes: Historical peak load data is not weather normalized (WN). All growth rates are compound annual growth between 2009 – 2014. Sources: Historical data from ERCOT, CAISO, & PJM (unrestricted peak load) . Load Forecasts from ERCOT, CEC, & PJM. GSP data from Moody's Analytics ($ 2005). Mid-Atlantic GSP is sum of PA, NJ, DE, & MD. Weather-normalized load growth rates reflect Calpine analysis. Texas California Mid-Atlantic Rather than having fundamentally changed, regional load growth trends appear to remain primarily a function of regional economic strength Population, industry and commercial trends positive for continued strong load growth •Feb 2013: In past year, employment increase in TX more than 2x gain in national payroll growth (Bloomberg) •Greater Houston Port Bureau survey: Businesses in Houston Port region will invest $35 billion in capital and maintenance between 2012 – 2015 (Houston Chronicle) Economic and load growth expectations in California and Mid-Atlantic are less robust ERCOT forecasts annual load growth of ~2,000 MW through 2016

21 Factors Sometimes Overlooked Factors Typically Considered Conventional Underestimation of New Build Spark Requirements 21 • Headline construction costs per headline kW • Cost of capital • Fixed operating costs • Total construction costs per operable kW • Cost and return of capital • Fixed, variable, and maintenance reserve operating costs • Operational realities such as: — Off peak and weekend operations — Imperfect plant availability — Higher fuel costs due to realized versus baseload heat rates, use of duct-fired capacity not just baseload capacity, and local gas delivery costs Spark spread required to incent merchant new build is an important benchmark for evaluating power market upside, particularly in regions without capacity markets. People often underestimate this benchmark, thereby not appreciating full fundamental potential of existing assets. Issue: Typical approach is to calculate annual revenue requirements and divide by the number of on-peak hours during the year to determine the spark spread level necessary to cover revenue requirements. A more careful approach recognizes the costs of operational “frictions” and generally results in higher new build benchmark.

22 $29 $2 $1 $3 $(4) $3 $1 $3 $38 Simple Estimate Interest During Construction Seasonal Capacity (less than Nameplate) Return of Capital Off Pk and Wknd Margins Plant Availability less than 100% Add'l Realized Fuel Costs Variable Costs and Maintenance Reserve Improved Estimate Impact of Refinements to the Math Operational Frictions Drive Higher Required Spark Spread 22 Illustrative ERCOT Estimate Operational Realities Starting Point: Illustrative Simple Math Construction Costs Return on Capital Fixed O&M Total Margin Needed On-Peak Hours Simple New Build Spark $893/kW 10% $30/kW-Yr $119/kW-Yr 4,100 $29/MWh ÷ = = x + Sources: EIA , Calpine Analysis

Calpine: Generation Volumes Inversely Related to Gas Prices; Margin Fairly Neutral NON-EQUITY Volume Projection (MM MWh) Recommended Premium to On-Peak Spark Spread <100 5% - 15% 100 – 110 (5)% - 5% 110 – 120… (15)% - (5)% Realized margin per MWh (relative to on-peak spark spreads) varies with total volume 1 Historical volumes adjusted to reflect only those plants currently owned by us. All periods exclude deconsolidated plants. 2013E as of 03/26/13. 2 Relates to our summary level modeling tips. Refer to slide 35 for complete tips and further detail. Calpine Margin Not Particularly Sensitive to Natural Gas Prices Modeled Impacts of Changes in Gas Price on Unhedged Portfolio As gas prices decline, volumes increase as gas units take market share from coal units As gas prices rise, margin increases as fuel cost advantage over less efficient generators widens Calpine Dispatch Sensitive to Natural Gas Prices Volumes¹ vs. Natural Gas Price Trend Though volumes can move substantially with changes in gas prices, unhedged Commodity Margin is relatively immune to changes in gas prices. Modeling Tip Application²: 23

24 24 APPENDIX

25 Further Detail on Illustrative “New Build Spark Spread” Estimates 25 Sources: EIA for illustrative ERCOT construction cost per kW, Calpine analysis. In reality, the “new build spark” varies for each particular project. Construction costs, project risks, and operating expectations all need to be factored in. /+ $100 per kW Construction Cost /+ 1% Capital Return Rate /+ $10 Fixed O&M Costs /+ 100 btu/KWh Heat Rate Chg 1% Availability /+ $1 Variable or Maintenance Costs Change in Required On Peak Spark Spread ($/MWh) $(3.00) $(2.00) $(1.00) $- $1.00 $2.00 $3.00 - - - - +/ - Illustrative Math Illustrative Sensitivities 634 $ A Headline Construction Costs ($MM) 710 B Headline (Gross) Plant Capacity (MW) 893 $ C=A/B Headline Construction Costs ($ per kW) 10% D Return on Capital 89 $ E=CxD Capital Return ($ per kW-Year) 30 $ F Fixed O&M ($ per kW-Year) 119 $ G=E+F Total Margin Needed ($ per kW-Year) 4,100 H Total On Peak Hours 29.10 $ I=Gx1000/H Simple Required On Peak Spark Level ($ per MWh) 697 $ A 680 B Net Annual Average Plant Capacity (MW) 1,026 $ C=A/B Total Construction Costs ($ per kW) 11% D Return Of and On Capital 113 $ E=CxD Capital Return ($ per kW-Year) 30 $ F Fixed O&M ($ per kW-Year) 143 $ G=E+F Total Margin Needed ($ per kW-Year) 15 $ H Estimated Off Peak and Weekend Net Margin ($ per kW-Year) 128 $ I=G-H Remaining Margin to be Recovered During On Peak Hours 92% J Plant Availability 3,772 K=4,117xJ Available On Pk Hours 33.89 $ L=Ix1000/K Required On Peak Margin per MWh 7.1 M Realized HR After Effects of Cycling, Use of Duct-Firing, and Degradation (MMBtu per MWh) 0.45 $ N=(M-7.0)x$4.50 Adder to Cover Realized Heat Rate above 7 HR (at $4.50 Gas Price) 0.72 $ O=0.10*7.2 HR Adder to Cover Local Fuel Delivery Costs ($0.10 per MMBtu, Converted $ per MWh) 2.50 $ P Adder to Cover Variable Costs and Major Maintenance Reserve 37.56 $ Q=L+N+O+P Improved Required On Peak Spark Spread Level ($ per MWh) SIMPLE MATH IMPROVED MATH (Changes/Additions in italics) Total Construction Costs ($MM) - Includes Interest During Construction

2013 Investor Day: Regional Trends Impacting Our Portfolio Steve Pruett Sr. Vice President, Commercial Operations April 10, 2013

27 27 Important Trends Impacting Our Portfolio National Caleb Stephenson Regional Steve Pruett Texas • Inefficiency of forward curves, plus • Regulatory shifts (including our new VMP) PJM • Retiring coal + Demand Response = Flattish capacity, but • Real upside in energy Southeast • Capturing significant origination opportunity with load serving entities California • Near-term: SONGS + AB32 • Medium -term: Increasing importance of capacity versus energy Load Trends • Cheer up! Energy efficiency not the end of load growth • Regional diversity: Texas load growth outlook remains robust The “New Build” Spark Spread • Spark spreads needed to motivate new construction likely higher than some think • Operational realities matter Gas Price Immunity • Generation volumes inversely related to gas prices; margin fairly neutral Energy Capacity Views of Value

28 Market Overview: Texas Addressing Need for New Generation 28 Substantial New Capacity Needed to Meet Current Reserve Margin Target Source: Calpine, ERCOT. Represents capacity necessary to meet target reserve margin of 13.75%. Reflects annual growth of 1.53% / 2.32% / 3.00% for Low/Base/High Case. CDR Planned Units exclude wind. Tightening Reserve Margins Should Suggest More Scarcity, Yet Forward Curves Reflect Less Source: ERCOT, Calpine. As of 3/26/13. Reflects Jul - Aug of each year and SWOC of $5,000 / $7,000 / $9,000 in 2013/2014/2015. Assumes market heat rate (absent scarcity) of 12,000 btu/kWh. Voluntary Mitigation Plan: Protects Bidding Despite Potentially Volatile Market Another 1,000 – 1,500 MW required to meet potentially higher target Day Ahead : Full bidding discretion Real Time: Approved bidding parameters for capacity above min load (chart) Texas Summary: • Generation needed: Regulatory reform necessary to attract more capacity • Inefficient forward market not providing signals • Meanwhile, Calpine actively managing its position in a volatile market - VMP approved How it Works:

Market Overview: PJM Retirements + DR = Flattish Capacity, but Energy Upside Significant Retirements on the Horizon… …Yet Forward Curves Remain Suppressed Source: Calpine, PJM, Energy Velocity, SNL. HEDD: High-Energy Demand Days (New Jersey regulation). Source: Calpine, Broker quotes. As of 3/26/13. Assumes market heat rate of 8,000 btu/kWh. RPM Capacity prices shown for MAAC and reflect annual weighted average capacity price, converted into on-peak spark spread equivalent assuming 50% on-peak capacity factor. 2016 reflects price for 2015/2016 auction, as 2016/2017 rates have not yet been established. Source: PJM. …Being Replaced by Demand Response Capacity in Excess of Reliability Requirement 7.2% 53.2% 53.6% 57.6% 25.7% % Commitment Repurchased: Replacing Retiring Units with Higher-Cost DR Should Increase Energy Prices… Demand Response Potential impact of increased DR calls on summer prices: +$18/MWh Source (DR Prices): EIA, MJ Bradley. Diesel Gen Set represents 1500 hp engine. See footnotes in Appendix for additional assumptions for price impact. (40 hrs. @ $500/MWh) Retiring Units Price-Setting Units? 15 – 17GW of retirements expected by 2016 29 Generation DR Installed Reserve Margin

30 Market Overview: California Increasing Need for Flexible Generation 30 Source: CAISO. Mid-Term: Renewable Integration Increases Need for Flexible Generation Hour of Day California Summary: • Near-term: AB32 + SONGS + Dry summer Price volatility • Mid-term: Regulatory reform needed to adequately compensate flexible generation; key for integration of renewables • Good news: Calpine has been effective at securing capacity contracts Near-Term: Carbon Regulation and Nuclear Outage Impacting Market SONGS Outage First Carbon Auction (AB32) Source: Calpine, Broker quotes. Origination Team Successful at Capturing Value through Contracts Where full plant output has been contracted, capacities shown here represent summer peaking capacity as reported in 2012 10-K; actual contract amounts may vary depending upon contract terms. Contract expiration may occur within the final year shown. Sutter, Los Medanos and Gilroy Cogen for 2013 represents summer only. * Indicates contracts subject to CPUC approval in a contested proceeding. 857 MW 500 MW 578 MW 675 650 250 MW 749 MW 515 120 MW 50 MW 608 MW 169 MW 560 28 MW 329 MW 309 MW 619 MW 280 MW 560 Years Contracted:

31 Market Overview: Southeast Realizing Opportunities with Load Serving Entities 31 Capturing Value: Continued Progress Upcoming Generation Shortages Projected in Southeast Region Utility IRPs + New Capacity – Projected Retirements = Significant Deficit Source: Calpine, TVA IRP, DUK/PGN IRP, Southern 10K, SCE&G IRP, SNL. Assumes 15% reserve margin across all utilities. Recent Updates: • • Years Contracted: 340 MW 225 MW 117 MW 795 MW 485 MW 135 MW 200 MW 200 400 260 MW 160 - 280 MW Where full plant output has been contracted, capacities shown here represent summer peaking capacity as reported in 2012 10-K; actual contract amounts may vary depending upon contract terms. Contract expiration may occur within the final year shown. Oneta – OMPA represents summer only. 50 MW Columbia Pine Bluff Hog Bayou Osprey Santa Rosa Auburndale Decatur Carville Morgan Oneta - SPS Oneta - OMPA Oneta - PSO Oneta - WFEC (6,000) (3,000) 0 3,000 6,000 9,000 12,000 15,000 2013 2014 2015 2016 2017 2018 2013 2016 2019 2022 2025 2028 2031 2034 Decatur: 10-year PPA with TVA Morgan: Planning to offer capacity into PJM for 2016/2017

32 Maximizing Shareholder Value Through Hedging 32 Portfolio Changes and Hedges Have Shifted Quarterly Distribution of Earnings Hedging Objective Calpine hedges in order to achieve full and fair value for our assets and maximize return on assets for our shareholders Bal-2013 2014 2015 % Hedged 49% 32% 31% Gas Position Neutral Long Long % Hedged 68% 33% 31% Gas Position Modestly Short Neutral Long 1 Spark spread in NP-15 and ERCOT based upon 7,000 btu/kWh market heat rate and in PJM-W based upon 8,000 btu/kWh market heat rate. NP-15 adjusted to deduct cost of carbon cap-and-trade, without which, spark spreads would have been $13.10 and $16.51 as of 10/26/12 and 3/26/13, respectively. Position Updates (Summary) Note: See complete updates to standard hedge disclosures in Appendix. 3Q12 Call (10/26/12) Investor Day (3/26/13) NP-15 $8.48 $10.94 ERCOT $20.75 $21.15 PJM-W $13.36 $13.29 Nat Gas (HH) $3.93 $3.90 • 4Q12 Portfolio Changes: — Sold Broad River, Riverside (contracted) — Acquired Bosque (merchant) • Addition of Russell City and Los Esteros (Summer 2013) • Changes in hedging profile — More open in 2013 — Seasonal (versus annual) hedges • Result: 1Q13 vs 1Q12 / 3Q13 vs 3Q12 2013 Considerations:

33 33 APPENDIX

34 Energy Margin 1 : Positioned to Respond to Favorable Secular Trends 34 • Power position — 2013: Hedges added; still have Q3 length — 2014/2015: Remain very open • Effective gas position Reminder: — Market heat rates tend to show inverse relationships with gas prices in some markets — ±500 btu/kWh sensitivity shown here, but inverse relationship historically much stronger at lower gas prices volumes and gas price exposures. Sensitivities are assumed to occur across the portfolio and the sensitivities on strategic options only capture intrinsic value. Volumes are on a delta hedge basis. Delta volumes are the expected volume based on the probability of economic dispatch at a future date based on current market prices for that future date. This is lower than the notional volume, which is plant capacity, less known performance and operating constraints. Volumes assume addition of Los Esteros and 75% of Russell City (2013); announced expansions at Deer Park and Channel (2014); as well as addition of Garrison and retirement of certain plants in New Jersey related to NOx compliance (2015). Represents Calpine’s forecasted average annual capacity of net ownership interest with peaking capacity, excluding equity plants. Capacity additions/deletions are reflected in anticipated month of completion. Spark spread in NP-15 and ERCOT based upon 7,000 btu/kWh market heat rate and in PJM-W based upon 8,000 btu/kWh market heat rate. NP-15 adjusted to deduct cost of carbon cap-and-trade, without which, spark spreads would have been been $13.10 and $16.51 as of 10/26/12 and 03/26/13, respectively. Energy Hedge Profile 2 2013 2014 2015 Hedged Margin ($/MWh) 2 $20 $27 $26 Avg. MW in Operation 2,4 27,209 27,761 27,934 $ Energy Margin 1,2 as % of Total Commodity Margin (by year): 75% 77% 78% Use in conjunction with modeling tips in appendix Natural Gas Price Sensitivity 2 (assuming no change in heat rate) Market Heat Rate Sensitivity 2 (assuming no change in gas price) Summary Sensitivities 2013 Modestly short 2014 Neutral 2015 Long 3Q12 Call (10/26/12) Investor Day (3/26/13) NP-15 $8.48 $10.94 ERCOT $20.75 $21.15 PJM-W $13.36 $13.29 Nat Gas (HH) $3.93 $3.90 Energy Margin + Regulatory & Other Margin = Total Commodity Margin. Estimated as of 03/26/13. Hedged margin excludes unconsolidated projects and includes the current mark-to-market adjustments of all executed transactions. Changing market heat rates will change delta 1 2 3 4 5

35 Although Calpine’s fleet can be difficult to model, simplifying techniques may help 35 1. Estimate annual generation (MWh) based on market outlook relative to disclosed historical generation with adjustments for asset acquisitions, asset divestitures and plants reaching commercial operations as well as changes in gas and coal price environments. • Note: Estimated generation in this step should exclude volumes from unconsolidated investments (Greenfield, Whitby). Margin from these plants is captured in step 7 below. 2. Estimate hedged energy margin based on disclosed % hedged (blue bars) and disclosed hedge margin ($/MWh). • Note: 2013 hedged margin ($/MWh) is full year average including YTD settlements. 2013 hedge profile is for balance of year only (applicable for steps 3 and 4 as well). 3. Estimate Geysers unhedged energy margin using MWh estimate (historically, ~6 million MWhs), assume the Geysers unhedged % is the same as the entire portfolio, and apply NP-15 ATC prices. 4. Estimate gas fleet unhedged energy margin based on rough assumptions: • Dispatched generation tends to capture a premium to the block on-peak spark spread for open volume. This premium varies significantly with, and is inversely related to, dispatch volumes. For 2013, this relationship is captured within our guidance. For years past 2013, depending upon your volume assumption in step 1 above, use the following rules of thumb for applying the premium: • For this exercise, hedge profile is assumed to be relatively flat across all regions, and disclosed regional steam adjusted plant heat rates should be considered when calculating spark spreads. Note: Tips are provided to help investors consider simplifying techniques to apply the information disclosed to date in their modeling efforts. These tips are naturally less precise than models based on detailed operational, contract, and hedge position data might be. 1 Excluding major maintenance expense, non-cash loss on disposal of assets, and stock-based compensation. 2 Excluding stock-based compensation. 5. Adjust margin to capture items such as ancillary services and storage positions (benefit of small tens of millions), as well as carbon costs in California. • To consider Calpine's AB32 costs, apply our combined-cycle average emissions rate of 876 lb/MWh for the California combined-cycle plants and assume that ~50% of those costs are passed on to our customers per contractual arrangements. 6. The sum of steps 2 through 5 above will provide you with an estimate of our Energy Margin. To estimate the contribution of Reliability and Other Margin (regulatory capacity and REC revenue) and arrive at an estimate of Total Commodity Margin, simply divide the Energy Margin by the disclosed percentages of Energy Margin as a % of total Commodity Margin. 7. Add estimated margin from unconsolidated investments (Greenfield, Whitby) by multiplying Calpine capacity (net interest) by $110/kw-yr in all periods shown. • Since these margins from unconsolidated investments are not included in Commodity Margin, but are included in Adjusted EBITDA, it is necessary to additionally estimate expenses related to unconsolidated investments for purposes of calculating Adjusted EBITDA. 8. When modeling operating costs for the consolidated power plants, use 2012 reported plant operating expense and sales, general and administrative expense and other operating expense and apply an inflationary factor for 2013 and subsequent periods, with adjustments for asset acquisitions, asset divestitures and plants reaching commercial operations. NON-EQUITY Volume Projection (MM MWh) Recommended Premium to On-Peak Spark Spread <100 5% - 15% 100 – 110 (5)% - 5% 110 – 120… (15)% - (5)% 1 1 2

36 Reliability & Other Margin Detailed 1 Estimated as of 03/26/13. Excludes unconsolidated projects. 2 Amounts shown as percentages of projected 2013 Regulatory & Other Margin. Excludes unconsolidated projects. 3 Represents volumetric position. Reliability & Other Margin Hedge Profile 1 Reliability & Other Margin Components 2 Substantially hedged 36 RECs 24% Regulatory Capacity 76% 100% 94% 92% 6% 8% Bal-2013 2014 2015 Hedged Dollars Open Dollars REC Sales: % Volume 3 2013 100% 2014 97% 2015 95%

37 Closer Look at Demand Response in PJM 37 Demand Response in PJM: An Overview Economic Products as Percent of Total DR Revenue ($9.2 MM in 2012) Footnotes for Summer Pricing Impact of Increased DR Dispatch: Source: Calpine, Energy Velocity. Summer represents July and August. Estimate reflects average summer price impact of the market clearing on the cost of DR (at assumed $500/MWh) instead of the cost of a gas turbine (at assumed production cost of $45/MWh) for 40 incremental hours. Product Description Pricing Emergency: Capacity • Three types: Annual, Extended Summer, Limited • Receives annual RPM payments set by Base Residual Auction (if cleared) Emergency: Energy • If cleared RPM auction, required to offer into DA/RT energy market; can only be called upon in emergency situations • Sets price if needed to avoid scarcity event — Received ~$1,500/MWh in 2012 Economic • Offered into day-ahead and/or real-time markets voluntarily • LMP must be > Net Benefits Test to be dispatched • Paid full LMP — Often dispatched at <$100/MWh Ancillary Services • Quick-response products to support grid stability • Based upon hourly market prices Source: PJM.

2013 Investor Day: Power Operations John Adams Sr. Vice President, Power Operations April 10, 2013

39 Power Operations Organization 39 West: Rob Parker Geysers: Mike Rogers Central: Dave Plauck Southeast: Rick Colgan North: Bill Ferguson Panelist In Attendance John Adams West Region Geysers Central Region Southeast Region North Region Outage Services Ron Macklin Engineering Dev. & Opt. Tom Long Engineering & Construction Supply Chain & Asset Management Ron Hall Andre Walker Safety Wendi Martin Environmental Services Derek Furstenwerth Strategic Procurement Murray Sanderford Sr. Vice President, Power Operations

40 Committed to Best-in-Class Operations 40 Increasing Generation While Improving Operations… According to EEI Safety Survey (2011). Includes generation companies only. 1 Success Drivers: 1 …and Maintaining Focus on Safety Generation Forced Outage Factor 0.0 1.0 2.0 3.0 4.0 80,000 90,000 100,000 110,000 120,000 2008 2009 2010 2011 2012 3-Yr. Avg. 2012 EEI Top Quartile — Predictive and preventive maintenance — Transformer reliability and spares — Summer and winter preparation — Fleetwide Root Cause Analysis program — Enhanced training — Master purchasing agreements: Volume discounts and parts consistency — Turbine expertise — Expanded borescope program — Outage planning certainty — Optimized parts management • Fleet Programs • Supply Chain Services • Outage Services

41 Leveraging Technological Expertise 41 GE Siemens Combustion Turbines (158) Steam Turbines (79) Use of similar technology across fleet provides scale, reduces costs and facilitates sharing of best practices

42 42 MAJOR MAINTENANCE Ron Macklin Vice President, Outage Services

43 Calpine’s Outage Services 43 Economies of scale + Proprietary knowledge = Competitive Advantage Preventive Maintenance Supporting Lower Equipment Failure Expense • Calpine Outage Services: Manages Major Maintenance program - Technical, outage, planning, asset, finance and safety expertise servicing largest modern CCGT fleet in world and largest co-generation fleet in US • Outage Services mission: - Eliminate forced outage / equipment failure - Provide CCGT maintenance to Calpine fleet - Provide technical expertise - Exercise cost control and demonstrate accurate forecasting • Scale produces a market - Inventory of assets - Competition between suppliers - Long-term contracts for percent of contracts

44 Outage Services: Scheduled Maintenance Program 44 Committed to preserving fleet value through diligent maintenance 2014 -2018 Major Maintenance Schedule Maintenance Intervals: • Combustion Inspection (Manways open) - GE turbine: 12,000/24,000 hrs - Siemens turbine: 8,000/16,000/24,000 hrs • Hot Gas Path Inspection (Turbine cover lifted) - GE & Siemens turbines: 24,000 hrs • Major Inspection (Rotor removal, all covers off) - GE & Siemens turbines: 48,000 hrs 5-year average: $350MM Major maintenance expense and Capex Lower $ Higher $ Rigorous & Ongoing Maintenance Program 0 10 20 30 40 50 60 70 2014 2015 2016 2017 2018 Combustion inspection Hot gas path Major inspection Steam Turbine Major inspection Steam Turbine Minor inspection

45 45 TURBINE TECHNOLOGY Tom Long Vice President, Development and Optimization Engineering

46 • Technology developing; totally new platforms • Original Siemens G-class and GE H-class abandoned • Units are lower heat rate, but less flexible: Cannot meet cycling needs as effectively Calpine F-Class Fleet: Modern and Competitive 46 F-Class: Advanced Classes: • Technology evolution continuing—but not revolutionary: OEM’s continue to invest • Will continue to be the workhorse of industry • All Calpine units upgradable F-Class Will Continue to Be Industry’s Workhorse — Efficient — Cyclable — Reliable • GE 7FA • Siemens 501F • G-, H- & J-Class • GE, Siemens, Mitsubishi — Target customer: Baseload operations in high gas price environments (e.g. Korea, Japan, some regulated U.S. utilities)

47 5,781 7,240 6,982 - 7,147 636 200 130 0 - 50 235 - 350 Manufacturer Quoted "New" HR (LHV)¹ LHV to HHV Natural Gas Aux Load Long-term Degradation Ambient Conditions (v ISO) Cycling/ Min Load Potential Realized HR CPN Framed CCGT Fleet HR- Non Cogen (2012) Making Sense of the Numbers: Calpine’s Fleet Remains Competitive 47 Calpine’s modern fleet remains competitive as new technology is introduced Potential to improve efficiency given ability to upgrade with appropriate market signals (Fleet only ~25% upgraded) “Real World” Operations Necessitate Adjustments to Published Efficiencies 2 1 LHV: Lower heating value. HHV: Higher heating value. HR: Heat Rate. HR based on OEM promotional material and ISO ratings. ISO Ratings = 59°F, 60% Relative Humidity, Sea Level 2 Varies from our published fleet-wide steam adjusted heat rate due to exclusion of technologies other than combine-cycle gas turbines. (2x2x1 Plant) 1

48 48 CONSTRUCTION / NEW-BUILD Ron Hall Vice President, Engineering and Construction

49 1 Source: Calpine Data, EIA, November 2010, “Updated Capital Cost Estimates for Electricity Generation Plants”. Figures shown in 2010 real $. 2 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 the plant. Regional / Local impacts to construction costs: • Lateral interconnection costs (gas, water, transmission) • Climate impacts (inside versus outside STG) • Air cooled condenser versus wet cooling tower • Seismic design • Zero-liquid discharge versus other means • Noise and visual requirements • Availability of workforce: Labor wages & productivity • Environmental restrictions / limitations • Location adjustments Cost of Typical CCGT Plant for various locations Calpine advantages that lower overall construction costs: • Organic growth: Existing plants with upgrade flexibility – Oversized steam turbines – Combustion turbine upgrades – Chillers/Foggers/Power augmentation • Surplus equipment – F-class combustion turbines & steam turbines • Re-powering / Expansion sites – Interconnection capability – Site infrastructure (water & gas supply, buildings, substation) 49 Projected Combined-Cycle Construction Costs Garrison Energy Center (309 MW) • Surplus CTG • Gray market STG • Competitive EPC pricing Channel & Deer Park Energy Centers (260 MW each) • Surplus CTG • Excess capacity STG • Existing infrastructure advantage $893 $916 $980 $1,005 $1,164 $1,292 $1,650 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 Texas Southeast (AL/FL/GA/LA) Base 2x1 540 MW NGCC Mid West Mid Atlantic California New York 2 1

50 Russell City Energy Center Hayward, CA • 464 MW 1 2x2x1 CCGT • Siemens FD3 CTGs, GE D-11 STG • 10 year contract to PG&E • Commissioning in progress • COD Summer 2013 • 120 MW 4x4x1 CCGT Conversion • GE LM 6000 CTGs, MHI STG • 10 year contract to PG&E • Commissioning in progress • COD Summer 2013 Los Esteros Critical Energy Facility San Jose, CA Deer Park and Channel Energy Centers Houston, TX • 260 MW 2 incremental capacity at each site • Siemens FD3 CTGs • Leveraging existing sites and equipment (~ $400/kW savings) • Foundations currently being poured • COD Summer 2014 Garrison Energy Center Dover, DE • 309 MW CCGT greenfield site • New GE 7F.04 CTG, A10 STG • Leveraging existing equipment and advantaged site (~ $250/kW savings) • Now under construction • COD Summer 2015 50 Calpine Construction Projects 1 Represents Calpine share. 2 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 the plant. Calpine Construction Philosophy • Owner-furnished equipment • Efficient Calpine team • Deep expertise • Leverage best EPC’s

2013 Investor Day: Regulatory Panel Thad Miller Executive Vice President, Chief Legal Officer April 10, 2013

52 Texas & SE 52 52 Legal and Regulatory Team EVP, Chief Legal Officer Thad Miller Legal Governmental & Regulatory Affairs Corporate Communications Internal Audit/ Compliance Insurance Panelist William Taylor Environmental In Attendance West North FERC & ISOs Federal Steve Schleimer Mark Smith Norma Dunn Joe Ronan Derek Furstenwerth Yvonne McIntyre Shonnie Daniel Randy Jones

53 Overarching Regulatory Themes Key Fronts for Continued Progress 53 Moving toward fairer, more transparent and stable price signals • In CA, seeking to • eliminate discrimination between old and new generation • obtain appropriate compensation for flexibility attributes of CCGTs • In TX, advocating to • adopt a capacity market to incent investment, assuring long term viability of competition • in the interim, reduce impediments to scarcity pricing in energy-only market design • In PJM, refining MOPR, DR rules to assure a level playing field Allowing markets (not regulators) to choose “winners” • Challenging NJ/MD efforts to exert buyer-side market power subsidizing new plants • Opposing legislative/regulatory actions denying ratepayers benefits of lower wholesale prices through uneconomic • utility self-builds (CA, OR, VA, NV, MN) • offshore wind (ME, MD) and intermittent renewables (CA) Role of DR must align with environmental and competitive markets goals • Protect environmental ground gained by limiting DR from behind-the-meter, uncontrolled, inefficient generator sets to replace retiring coal plants or otherwise supplant gas generation • If DR to be compensated similar to generators, assure comparable performance requirements and non-performance penalties Market Structure/ Rules Non- Competitive/ Subsidized Generation Demand Response

54 54 Advocating for Competitive Markets and Responsible Regulation As of 4/10/2013 West (CAISO) • Assure incremental compensation for gas generation with flexibility attributes critical to integration of intermittent renewables • End discrimination against existing (vs. new) generation and ensure adequate compensation for existing generation • Support and refine GHG Cap- and-Trade Multi-regional • o success in OK, progress in MN, battles in CA/OR/NV/VA Texas (ERCOT) • • o Safe harbor allows more rational bidding • o PUCT active consideration likely this year Federal • Congress – inaction likely to continue o Climate Change: resurgent o GHG and other EPA rules: Unlikely to be blocked o PTC: extended thru ’13 o Cybersecurity: Multiple proposals; Executive Order interim measure • EPA – activism to continue o MATS: In effect, court case slogs on o CSAPR: o Coal Ash: o 316(b) (OTC): o GHG (new sources): Rule final this year o GHG (existing sources): Proposed rule on hold • CFTC Derivatives Rules o CPN qualifies for end-user exemption • FERC – new leadership? o Trending positive on support for capacity markets Rulings on ISO-NE, NY-ISO capacity market rules NERC letter to ERCOT on resource adequacy Ruling on CAISO application for “forward backstop mechanism” made right noises on PJM MOPR ruling pending o Gas/Electric Interdependency review underway North (PJM, MISO, ISO-NE, NY-ISO) • Continue to refine rules to promote fair and transparent market precluding NJ, MD court cases FERC approval of MOPR fix pending PJM rules tightened Challenging dirty DR • Oppose MISO capacity transportability into PJM • Assure ISO-NE concerns on gas/electric interdependency lead to market-based solution not mandate No Sandy surge but dialogue Overturned, EPA appealing to USSC Rule delayed Final rule expected ‘13 Oppose uneconomic utility self-builds o Some implemented and considering others affecting operating reserves Support interim changes to allow scarcity pricing Approval of Calpine’s Voluntary Mitigation Plan Support transition to capacity market to assure long-term reliability o Opposed by PJM/some MISO stakeholders o FERC to hold conference o State exercise of buyer-side market power o Special treatment for DR resources

55 55 APPENDIX

56 Initiatives • FERC Rule on DR • FERC Review of Gas/Electric Coordination Issues • Cybersecurity • Dodd-Frank & CFTC Regulation Comments • Appealed to court asserting unfairly overcompensates DR relative to generation and threatens reliability • ISO-NE and MISO concerned about gas transport insufficiency • ISO-NE actively examining energy and capacity market rules changes to help alleviate problem • Executive order issued: government- private sector information sharing program and cybersecurity best practices framework • CPN continues to qualify for end-user exemption 56 Environmental Regulation Initiatives • GHG Performance Standards • Mercury and Air Toxics Standards (MATS) • Cross-State Air Pollution Rule (CSAPR) • Revised PM-2.5 Ambient Air Quality Standard • Coal Combustion Residuals Management Rule • Cooling Water Intake Structures (Once-through-cooling Rule) • National Emissions Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines (RICE-NESHAP) Comments • Final rule for new sources expected ‘13 • Existing sources on hold • Effective 4/15 • Challenged in court but no stay • Vacated by Court; remanded to EPA for revisions; EPA likely to appeal • CAIR in effect • Reset PM-2.5 NAAQS based on latest science; effective by ‘15 • Regulates bottom ash/sludge/ slag as waste • Final rule timing uncertain • Reduces impingement/ entrainment impacts on aquatic life • Final rule by mid-’13; compliance starts mid-2015 • Final rule contradicts national environmental goals • Being challenged in court Market Regulation Regulatory and Legislative Overview: Federal Continuing the March Toward Responsible Environmental Policy

57 Regulatory and Legislative Overview: North Region Discouraging Non-competitive Resources 57 Non-Competitive/Subsidized Generation Market Structure/Rules Demand Response Initiatives • New Jersey (LCAPP) & Maryland (RFP process) subsidized generation • Utility self-build • Renewables Comments • Both trials underway • May issue decision prior to May auction • Challenging competitiveness of rate based assets in VA, MN • Offshore Wind: MD law passed, but with significant safeguards; NJ still examining policies • Canadian Hydro: CT proposal to count as “Tier 1” renewable Initiatives • Capacity Markets Comments • PJM: Strengthening MOPR process • ISO-NE: FERC approved strong buyer-side market power rules over objections of states; price floor going away in next auction • NY-ISO: FERC approves generators’ complaint over implementation of buyer-side market power rules Initiatives • Treatment and impact of increasing role of demand response Comments • Court challenge to RICE NESHAP (dirty DR) filed • ISO-NE/PJM continue to strengthen DR rules Other Regional Issues Initiatives • Regional Greenhouse Gas Initiative (RGGI) • “Seams” Issues Comments • Tighter GHG caps proposed across region • PA and NJ key states out of program, creating “leakage” • MISO/PJM addressing operational improvements and capacity portability by MISO into PJM

58 Regulatory and Legislative Overview: Texas Region Incentivizing New Capacity 58 Market Structure/Rules Other Regional Issues Initiatives • PUCT Resource Adequacy Proceedings • PUCT Scarcity Pricing Proceedings • Capacity, Demand and Reserves (CDR) forecast • Demand Response Proceeding • Calpine’s Voluntary Mitigation Plan (VMP) • ERCOT Scarcity Pricing Proceedings Comments • Required v. target reserve margin • Energy-only v. capacity market • Increased System Wide Offer Cap • Considering interim operating reserve demand curve proposals: • PUCT/ERCOT review of inputs for bi- annual CDR to establish appropriate reserve margin target • PUCT considering how to incorporate/increase DR (economic and reliability response) without adverse impact to market • PUCT approved plan (3/28) provides: • Limiting mitigation to resources that contribute to real-time non- competitive constraints • Reducing deployment of Regulation- Up service Initiatives • 2013 Legislative Agenda • PUCT Commissioner update Comments • PUCT Sunset review • Proposed legislation requiring cost- benefit analysis before changing market structure • Environmental legislation authorizing TX to assume authority from EPA for GHG permitting • Pablos replacement not likely until after end of regular legislative session (May 27) o establishing “price adder” to existing real-time scarcity price o adding operating reserves with $350/MWh floor (Non-Spin Res.) o informal bidding guidance for other market participants o creates safe harbor against market power abuse charges o guidelines for CPN’s bidding behavior

59 Initiatives • CPUC: Long Term Planning & Procurement (LTPP) • CPUC: Resource Adequacy (RA) • CAISO: Forward Capacity Procurement Initiatives Comments • Pursuing new products that: Regulatory and Legislative Overview: West Region Properly Compensating Existing, Flexible Generation 59 Market Structure/Rules Non-Competitive/Subsidized Generation Other Regional Issues Initiatives • Utility self-build (or BOT) • Subsidized renewables and generation alternatives (DR, Storage, etc.) Comments • Regulators continue to support uneconomic/unneeded projects at expense of existing generation and ratepayer • Policies continue to increase renewable investment and drive need for system flexibility for integration of renewables • GHG reduction policies focus on uneconomic alternatives to conventional generation Initiatives • California Air Resources Board (CARB) GHG Cap-and-Trade Program (AB32) • Water Resources Control Board: Once-Through-Cooling (OTC) Comments • Emissions market functioning with two auctions already held • CARB staff reviewing rules refinements to assure long term viability of market • Replacement of OTC units: Part of IOU procurement analysis being discussed at CPUC & CEC o Provide incentive for procurement of existing generation intermediate term o Allow existing and new power plants to compete on equal basis (FERC ruling on CAISO forward backstop creates pressure point) o Compensate flexible gas generation critical to integration of intermittent renewables

2013 Investor Day: Financial Overview Zamir Rauf Exec. Vice President, Chief Financial Officer April 10, 2013

61 Note: Debt balances as of 12/31/12. 1 Includes net debt of unconsolidated projects. 2 Figures based upon TTM (2012) Adjusted EBITDA. Calculation excludes project debt associated with Russell City and Los Esteros while under construction, as well as effective corporate debt (equivalent capital spend) for Garrison, Deer Park and Channel projects. 3 A non-GAAP financial measure. Reconciliations of Adjusted EBITDA and Adjusted Free Cash Flow to Net Income (Loss), the most comparable U.S. GAAP measure, are included herein. Capital Structure Optimization Opportunistically managing maturities and streamlining capital structure while delivering interest savings and increasing Adj. FCF /share Recent Activities: Delivered ~ $0.08 Adj. FCF /Share Savings • Oct 2012: — Issued term loan to refinance 10% of Sr. Secured Notes ($590 MM) and retire BRSP ($218 MM) — ~$25 MM annual interest savings • Feb 2013: — Repriced all $2.5B of term loans — ~$12 MM annual interest savings Upcoming Opportunities: • 8.0% CCFC bonds due 2016 — $1 billion callable at 104 in Jun 2013 • 7.25% Senior Secured Notes due 2017 — $1.08 billion callable at 103.6 in Oct 2013 • 10% of all Senior Secured Notes (7.25% - 8.0%) — Currently callable at 103 in twelve month intervals (next opportunity: Oct 2013) CCFC $978 Capital Leases $217 Notes Payable/ Other $47 Gross Debt: $10,750 Less: Cash, Cash Equivalents & Rest. Cash: $(1,537) Net Debt : $9,405 Net Debt / Adjusted EBITDA : 4.9x Average Interest Rate: 2008 8.8% 2013 7.3% Corporate Debt Senior Secured Notes $5,303 First Lien Term Loan $2,463 Corporate Revolver — Total Corporate Debt $7,766 Project Debt $1,742 ($ millions) 61 3 3 1 1 2

62 Strong Liquidity, No Near-Term Refinancing Risk 62 No Near-Term Maturities Projected Scheduled Amortizations & Estimated Cash Sweeps ($ millions) Represents ~$1B of debt paydown Minimum: $1 billion Strong Liquidity / Better Quality Capital Allocation Flexibility Project Debt CCFC Senior Secured Notes Senior Secured Term Loans Restricted Cash Cash and Cash Equivalents, Non-corporate Cash and Cash Equivalents, Corporate Revolver / LC Availability 1 Debt maturity schedule shown here is not prepared on a U.S. GAAP basis and does not conform to debt maturity schedule presented in Calpine’s Form 10-K. (Refer to the 2012 Form 10-K for further information regarding U.S. GAAP-basis debt maturities). Assumptions used in debt maturity charts shown here are as follows: (i) excludes letter of credit facilities; (ii) maturity balances assume cash sweeps; and (iii) all other debt maturities are paid from operating cash flows at the project level. Project debt in 2019 represents projected balance for OMEC. Put price in the PPA approximates the projected debt balance. 1 $658 $567 $757 $1,058 $946 $1,153 $269 $306 $131 $248 $194 $253 2010 2011 2012 Calpine Peers Environmental CapEx Legacy Environmental Liabilities Decommissioning Liabilities Underfunded Pension Liability Cash Taxes Discretionary Capital Allocation $1,000 $1,080 $1,368 $1,544 $1,421 $990 $1,800 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 $140 $180 $190 $200 $210 2013 2014 2015 2016 2017 $2,294 $2,013 $2,233

63 NOLs: Additional Source of Value NOL Summary NOL usage enhances excess liquidity available for capital deployment NOL Benefits Cash tax savings since 2010 ~$250 MM Southeast fleet tax basis ~$200/kW ($ millions) Managing Expirations to Maximize Value State NOLs Present Additional Opportunity Note: Calpine does not have state NOLs in Texas due to lack of income tax in the state. (Companies instead pay franchise taxes.) $0 $2,000 $4,000 $6,000 $8,000 Federal State Foreign $0 $1,000 $2,000 $3,000 $4,000 $5,000 0 - 5 6 - 10 11 - 15 16 - 20 Over 20 Years Until Expiration 63

64 Disciplined Approach to Capital Allocation Minimum liquidity met? • $1 billion FOCUS ON OPERATIONAL PERFORMANCE High return investment opportunities available? Need to reduce leverage? Ability to return capital? INVEST IN GROWTH • Accretive to Adj. FCF 1 per share • Equity returns above cost of capital • Benchmark against share repurchase • Ensure ability to achieve target credit ratios over time REDUCE LEVERAGE • Leverage target: ~4.5x Net Debt / Adj. EBITDA 1 • Actual ratio may fluctuate, but target remains in sight RETURN CAPITAL • Flexible capital structure • Share buyback: Effectively buying back our own plants at a discount • Ability to consider dividend if/when time is right Excess Cash Adj. Free Cash Flow 64 1 A non-GAAP financial measure. Reconciliations of Adjusted EBITDA and Adjusted Free Cash Flow to Net Income (Loss), the most comparable U.S. GAAP measure, are included herein.

65 Capital Allocation Drives Adj. Free Cash Flow Per Share Growth 65 Driving Adj. FCF 1 /Share Growth Successfully Deploying Capital 1 A non-GAAP financial measure. Reconciliations of Adjusted EBITDA and Adjusted Free Cash Flow to Net Income (Loss), the most comparable U.S. GAAP measure, are included herein. Financially disciplined growth Accretive acquisitions Asset monetization and capital reallocation Opportunistic share repurchases Optimizing capital structure Paying down debt 20% CAGR 15% CAGR (15-20% CAGR)

66 Both metrics presented before capital allocation activity: Principal repayment Organic growth investments M&A Share repurchases Merits of Adj. Free Cash Flow Per Share • More accurately reflects shareholder value than absolute Adj. EBITDA 1 or FCF 1 • Captures value created by —Asset sales —Interest savings —Tax position (NOL) —Share repurchases Adj. FCF Per Share 1 … …A Proxy for Cash Earnings Per Share Earnings Per Share + Non-Cash Taxes + Non-Cash Interest (net) Non-Cash Unrealized Mark-to-Market + Depreciation & Amortization — Maintenance CapEx Other non-cash / non-recurring items 2 = Adj. FCF Per Share 1 Adj. FCF/Share 1 Growth: Representative of potential total shareholder return Targeting 15 — 20% CAGR 66 1 A non-GAAP financial measure. Reconciliations of Adjusted EBITDA and Adjusted Free Cash Flow to Net Income (Loss), the most comparable U.S. GAAP measure, are included herein. 2 Includes non-cash stock compensation expense, non-cash (gain) loss on disposal of assets, and other items. 2011 2012 2013E

67 67 APPENDIX

68 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 or non-recurring items as detailed in the following reconciliation. Adjusted EBITDA is presented because our management uses Adjusted EBITDA (i) 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; (ii) as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations; and (iii) in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance. We believe Adjusted EBITDA is also used by and 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. Adjusted EBITDA 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. 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. Furthermore, Adjusted EBITDA is not necessarily comparable to similarly-titled measures reported by other companies. Adjusted Free Cash Flow represents net income (loss) attributable to Calpine before net income (loss) attributable to the noncontrolling interest, 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 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. _________ (1)Depreciation and amortization expense in the income from operations calculation on our Consolidated Statements of Operations excludes amortization of other assets. (2)Included on our Consolidated Statements of Operations in (income) from unconsolidated investments in power plants. (3)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 December 31, 2012 and 2011, respectively, and nil and $1 million for the years ended December 31, 2012 and 2011, respectively. (4)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 expenditures for the three months and year ended December 31, 2012, respectively. Includes $27 million and $201 million in major maintenance expense for the three months and year end December 31, 2011, respectively, and $35 million and $196 million in maintenance capital expenditures for the three months and year ended December 31, 2011, respectively. (5)Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. Reg G Reconciliation: Adjusted EBITDA and Adjusted Free Cash Flow Net income (loss) attributable to Calpine $ 199 $ (190) Net income attributable to the noncontrolling interest Income tax expense (benefit) Debt extinguishment costs and other (income) expense, net (Gain) loss on interest rate derivatives Interest expense, net of interest income Income from operations $ 1,002 $ 800 Add: Adjustments to reconcile income from operations to Adjusted EBITDA: Depreciation and amortization expense, excluding deferred financing costs (1) Major maintenance expense Operating lease expense Unrealized (gain) loss on commodity derivative mark- to-market activity (Gain) on sale of assets, net Adjustments to reflect Adjusted EBITDA from unconsolidated investments (2)(3) Stock-based compensation expense (Gain) loss on dispositions of assets Acquired contract amortization Other Total Adjusted EBITDA $ 1,749 $ 1,726 Less: Operating lease payments Major maintenance expense and capital expenditures (4) Cash interest, net (5) Cash taxes Other Adjusted Free Cash Flow (6) $ 564 $ 489 Weighted average shares of common stock outstanding (diluted, in thousands) Adjusted Free Cash Flow Per Share (diluted) $ 2011 Year Ended December 31, 2012 $ 1.20 471,343 485,381 8 11 757 781 11 13 34 35 375 397 7 25 12 16 14 8 31 36 25 24 82 25 (222) — 200 205 34 35 564 552 725 751 45 115 14 145 — 1 19 (22) (6)Excludes a decrease in working capital of $91 million and $107 million for the three months and year ended December 31, 2012, respectively, and a decrease in working capital of $8 million and increase in working capital of $13 million for the three months and year ended December 31, 2011, respectively. Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance. 1.01

Full Year 2013 Range: Low High GAAP Net Income (1) $ 175 $ 335 Plus: Interest expense, net of interest income 745 745 Depreciation and amortization expense 575 575 Major maintenance expense 205 205 Operating lease expense 35 35 Other (2) 65 65 Adjusted EBITDA $ 1,800 $ 1,960 Less: Operating lease payments 35 35 Major maintenance expense and maintenance capital expenditures (3) 370 370 Cash interest, net (4) 755 755 Cash taxes 15 15 Other 10 10 Adjusted Free Cash Flow $ 615 $ 775 _________ (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 $210 million and maintenance capital expenditures of $160 million. Capital expenditures exclude major construction and development projects. 2013 figures exclude non-recurring IT system upgrade. (4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. (in millions) 69 Reg G Reconciliation: 2013 Adjusted EBITDA and Adjusted Free Cash Flow Guidance

70 Investor Relations Contacts • Calpine Investor Relations investor-relations@calpine.com 713-830-8775 • Christine Parker Director, Investor Relations parkerc@calpine.com 713-820-4023 • Bryan Kimzey Vice President, Investor Relations bryan.kimzey@calpine.com 713-830-8777