exv99w2

Exhibit 99.2

CALPINE CORPORATION EARNINGS CONFERENCE CALL 2ND QUARTER ENDED JUNE 30, 2005 SAN JOSE, CALIFORNIA

CALPINE PARTICIPANTS PETE CARTWRIGHT Chairman, President and Chief Executive Officer BOB KELLY Executive Vice President and Chief Financial Officer PAUL POSOLI Executive Vice President and President of Calpine Energy Services, L.P. KAREN BUNTON Manager, Investor Relations

FORWARD-LOOKING STATEMENT This presentation discusses certain matters that may be considered "forward- looking" statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including statements regarding our expected financial performance, our strategic and operational plans, as well as all assumptions, expectations, predictions, intentions, or beliefs about future events. Investors are cautioned that any forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements. We refer you to the documents we file from time to time with the Securities and Exchange Commission (SEC), including our Annual Report on Form 10-K for the year ended December 31, 2004. These documents can also be found on our web site at www.calpine.com. We undertake no duty to update any forward-looking statements. This presentation also includes certain non-GAAP financial measures as defined under SEC rules. As required by SEC rules, we have provided a reconciliation of those financial measures to the most directly comparable GAAP measures, which can be found in Appendix A of this presentation. The financial information presented is subject to adjustment until we file our Quarterly Report on Form 10-Q with the SEC for the quarter ended June 30, 2005.

BUSINESS UPDATE PETE CARTWRIGHT CHAIRMAN, PRESIDENT AND CHIEF EXECUTIVE OFFICER

STRATEGIC INITIATIVE UPDATE Completed Asset Sales Saltend Energy Centre Gas Company Grays Ferry Morris Successful Refinancing Activity Restructured Long-Term Maintenance Contracts CES Credit Enhancement Taking Action for a Strong Tomorrow

BUSINESS OVERVIEW Challenging 2nd Quarter Low Spark Spreads in the West Several Plant Outages Electricity Consumption Continues to Grow Entered 3rd Quarter with Strengthening Spark Spreads

PROJECT PORTFOLIO Recent Project Additions 600 mw Metcalf Energy Center 750 mw Pastoria Energy Center 300 mw Fox Energy Center, Phase I 79.9 mw Bethpage Energy Center 3 93 Plants in Operation; 27,000 Megawatts Active Construction; Contracted Projects Only

2ND QUARTER 2005 FINANCIAL AND OPERATING RESULTS BOB KELLY EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER

KEY FINANCIAL HIGHLIGHTS (In millions, except EPS) (In millions, except EPS) 2nd Qtr. Ended June 30, 2005 Revenue $ 2,226.0 GAAP Net Loss $ (298.5) GAAP Basic and Diluted Loss Per Share $ (0.66) Operating Cash Flow $ (124.7) EBITDA, as Adjusted for Non-Cash and Other Charges (1) $ 251.4 EBITDA, as Adjusted for Non-Cash and Other Charges to Interest Expense (2) 0.68 (1) Earnings Before Interest, Tax, Depreciation and Amortization, as Adjusted for Non-Cash and Other Charges; See Appendix A for Reconciliation from Net Loss, Which is the Most Directly Comparable GAAP Measure (2) Interest Expense Includes One-Third of Operating Lease Expense

GENERATION AND SPARK SPREADS 2nd Quarter 2nd Quarter 2nd Quarter 2005 2004 Average mw in Operation 25,931 23,211 Mwh Generated (000s) 20,042 20,066 Mwh Delivered (000s) 33,058 33,992 Total Spark Spread (000s) $ 452,285 $ 413,680 Spark Spread (per mwh) $ 22.57 $ 20.62

POWER PLANT STATISTICS 2nd Quarter 2nd Quarter 2nd Quarter 2005 2004 Plant Availability Factor 89.0% 88.9% Plant Baseload Capacity Factor 39.9% 45.0% Average Heat Rate (btu/kwh)(1) 7,294 7,265 Total Plant Operating Expenses (000s) $ 201,855 $ 204,583 Plant Operating Expenses (per mwh)(2) $ 4.95 $ 5.41 (1) Excludes Saltend Facility (2) Total plant operating expenses include major maintenance expense and are calculated on a trailing 12-month basis at an assumed 70% capacity factor (1) Excludes Saltend Facility (2) Total plant operating expenses include major maintenance expense and are calculated on a trailing 12-month basis at an assumed 70% capacity factor (1) Excludes Saltend Facility (2) Total plant operating expenses include major maintenance expense and are calculated on a trailing 12-month basis at an assumed 70% capacity factor (1) Excludes Saltend Facility (2) Total plant operating expenses include major maintenance expense and are calculated on a trailing 12-month basis at an assumed 70% capacity factor

2ND QUARTER 2005 POWER MARKETS UPDATE PAUL POSOLI EXECUTIVE VICE PRESIDENT AND PRESIDENT OF CALPINE ENERGY SERVICES, L.P.

POWER MARKETS UPDATE Spark Spreads Per Mwh Note: Figures Represent Average On-Peak, Day-Ahead Spark Spreads at 7,000 btu/kwh Heat Rate Source: Company Data 2nd Quarter 2nd Quarter 2nd Quarter 2005 2004 NP15 $ 8.16 $ 12.38 SP15 $ 11.44 $ 14.66 ERCOT (Houston) $ 19.65 $ 11.25 NEPOOL (Mass Hub) $ 18.11 $ 14.60 Southeast $ 6.99 $ 8.95

2006 FORWARD CURVES Calendar 2006 Forward Spark Spreads Per Mwh Source: Company Data, Assumes a 7,000 btu/kwh Heat Rate As of 9/30/04 As of 7/27/05 % Change NP15 $ 18.03 $21.49 19% SP15 $ 21.11 $ 24.88 18% ERCOT (Houston) $ 13.47 $ 22.24 65% NEPOOL (Mass Hub) $ 16.30 $ 20.16 24% Southeast $ 7.78 $ 9.96 28%

MANAGING COLLATERAL REQUIREMENTS CES Total Collateral 12/31/04 $442.3 Million 3/31/05 $482.9 Million 6/30/05 $499.6 Million Current Factors Higher Gas Prices Sale of Gas Company Negative Factors in Q3 Offset by: Higher Spark Spreads Power Receivables

2ND QUARTER 2005 FINANCE UPDATE BOB KELLY EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER

Corporate Financing Contingent Convertible Notes 650.0 10.0 7.75% and $4.00 Conversion Total & Weighted Avg Totals $ 1,028.1 10.0 8.05% Average Interest Rate Equity Transactions - 3(a)9 $ 94.3 n/a $3.42 Common Stock Price Amount Term (Years) Interest / Other Project Financing Metcalf Energy Center Senior Term Loan $ 100.0 5.0 LIBOR + 300bp Redeemable Preferred Shares 155.0 5.5 LIBOR + 900bp Bethpage Energy Center 3 Senior Loan 108.5 20.0 6.13% Fixed Junior Loan 14.6 15.0 7.94% Fixed FINANCING ACTIVITY (In millions)

ASSET SALES - 3rd Quarter Transactions Gross Proceeds Net(1) Proceeds Pre-Tax Book Gain/(Loss) Closed Calpine Natural Gas $ 1,050.0 $ 835.0(2) 350.0 Saltend 862.5 207.0 6.0 Grays Ferry 37.4 37.4 (18.6) Morris 84.5 84.5 (106.2) Total $ 2,034.4 $ 1,168.9 $ 231.2 Negotiations Ontelaunee Philadelphia Water (1) Net of estimated fees, expenses and debt re-payments as of July 31, 2005 (2) Includes $75 million of oil and gas properties for which we were unable to obtain consents to assignment prior to closing } Potential Q3 Transactions (In millions)

DEBT PAYDOWNS Senior Secured $ 139 Senior Unsecured 480 Convertible Bonds 94 High Tides III 403 Saltend Preferred 1&2 620 Subtotal 1,740 New 7 3/4% Convertible (650) Debt Paydown $1,086 April - July 31, 2005 (In millions)

QUESTION AND ANSWER SESSION

APPENDICES

APPENDIX A: GAAP NET INCOME TO EBITDA, AS ADJUSTED FOR NON-CASH AND OTHER CHARGES Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, Six Months Ended June 30, Six Months Ended June 30, Six Months Ended June 30, (In thousands) 2005 2004 2005 2004 GAAP net loss $ (298,458) $ (28,698) $ (467,189) $ (99,890) (Income) loss from unconsolidated investments in power projects and oil and gas properties (3,268) 2,085 (9,260) 972 Distributions from unconsolidated investments in power projects and oil and gas supplies 5,416 9,474 10,288 14,614 Subtotal (296,310) (17,139) (466,161) (84,304) Interest expense 333,778 270,576 658,444 516,161 1/3 of operating lease expense 8,509 8,988 16,768 18,254 Provision (benefit) for income taxes (134,862) (73,374) (233,591) (175,233) Depreciation, depletion, and amortization expense ("DD&A") 145,362 129,726 282,794 255,491 Power plant impairment 106,155 - 106,155 - Interest expense, provision for income taxes, DD&A, and income from discontinued operations 52,478 69,769 113,119 151,471 EBITDA, as adjusted $ 215,110 $ 388,546 $ 477,528 $ 681,840

APPENDIX A: GAAP NET INCOME TO EBITDA, AS ADJUSTED FOR NON-CASH AND OTHER CHARGES Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, Six Months Ended June 30, Six Months Ended June 30, Six Months Ended June 30, (In thousands) 2005 2004 2005 2004 EBITDA, as adjusted $ 215,110 $ 388,546 $ 477,528 $ 681,840 Equipment cancellation and impairment cost 46,968 7 46,895 2,367 Foreign currency transaction (gain) loss 3,489 5,152 (1,751) (4,832) Unrealized mark-to-market activity (gain) loss 40,569 28,913 31,731 33,858 (Income) from repurchases of various issuances of debt (129,154) (2,559) (150,926) (3,394) SFAS No. 123 (stock-based compensation expense) 4,837 5,500 11,973 9,766 Minority interest expense 10,172 4,724 20,786 13,159 (Income) loss or interest rate swap ineffectiveness 808 - 841 - Unconsolidated investment impairment 18,542 - 18,542 - Write-off of deferred financing costs (not related to bonds repurchased) 5,887 19,376 5,887 19,376 Long-term service agreement cancellation charge 33,918 - 33,918 - Other non-cash and other charges 282 (3,487) 737 (1,041) EBITDA, as adjusted for non-cash and other charges $ 251,428 $ 446,172 $ 496,161 $ 751,099

Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Security Balance Sheet Value Outstanding Amount 7/1-12/31 2005 2006 2007 2008 2009 Thereafter Total Notes Payable / Lines of Credit DWR Monetization 5.2% Senior Secured Notes Due 2006 $ 152.0 $ 152.0 $ 74.0 $ 78.0 $ - $ - $ - $ - $ 152.0 6.256% Senior Secured Notes Due 2010 462.3 462.3 - 77.9 128.2 97.6 103.7 54.9 462.3 Power Contract Financing 54.0 85.0 - - - - - 85.0 85.0 Gilroy Note 121.6 121.6 3.9 8.6 9.6 10.6 11.8 77.1 121.6 BPA Monetization 41.0 41.0 11.5 23.5 6.0 - - - 41.0 Calpine Commercial Trust 29.9 32.6 4.3 8.7 8.7 6.5 2.2 2.2 32.6 Miscellaneous 21.7 21.7 18.0 0.5 0.9 0.3 0.3 1.7 21.7 Notes Payable $ 882.5 $ 916.2 $ 111.7 $ 197.2 $ 153.4 $ 115.0 $ 118.0 $ 220.9 $ 916.2 Preferred Interests Auburndale Power Plant $ 78.4 $ 78.4 $ 0.3 $ 0.7 $ 1.5 $ 3.9 $ 6.4 $ 65.6 $ 78.4 Saltend Redeemable Preferred Shares - #1 (A) 360.0 360.0 - 360.0 - - - - 360.0 Saltend Redeemable Preferred Shares - #2 (B) 260.0 260.0 260.0 - - - - - 260.0 Metcalf Energy Center 155.0 155.0 - - - - - 155.0 155.0 Gilroy Energy Center 63.7 63.7 3.9 8.8 7.5 8.3 9.8 25.4 63.7 Preferred Interests $ 917.1 $ 917.1 $ 264.2 $ 369.5 $ 9.0 $ 12.2 $ 16.2 $ 246.0 $ 917.1 Capital Lease Obligations Hidalgo Energy Center $ 101.4 $ 101.4 $ - $ 1.1 $ 1.3 $ 3.1 $ 3.3 $ 92.6 $ 101.4 King City Power Plant 95.1 95.1 1.2 1.2 1.5 1.4 2.0 87.8 95.1 Stony Brook Power Plant 62.9 71.7 - 1.2 1.5 1.7 1.8 65.5 71.7 Agnews Power Plant 26.7 26.7 2.5 3.0 3.2 3.7 4.0 10.3 26.7 Corporate 1.7 1.7 0.5 0.6 0.5 0.1 - - 1.7 Capital Lease Obligations $ 287.8 $ 296.6 $ 4.2 $ 7.1 $ 8.0 $ 10.0 $ 11.1 $ 256.2 $ 296.6 As of June 30, 2005 (In millions) APPENDIX B: OUTSTANDING DEBT & PRINCIPAL PAYMENT SCHEDULES

APPENDIX B: OUTSTANDING DEBT & PRINCIPAL PAYMENT SCHEDULES (continued) Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Security Balance Sheet Value Outstanding Amount 7/1-12/31 2005 2006 2007 2008 2009 Thereafter Total CalGen Term Loan Notes Due 2009 $ 600.0 $ 600.0 $ - $ - $ 3.0 $ 6.0 $ 591.0 $ - $ 600.0 Floating Rate Notes Due 2009 235.0 235.0 - - 1.2 2.4 231.4 - 235.0 Floating Rate Notes Due 2010 632.4 640.0 - - - 3.2 6.4 630.4 640.0 Term Loan Notes Due 2010 98.9 100.0 - - - 0.5 1.0 98.5 100.0 Floating Rate Notes Due 2011 680.0 680.0 - - - - - 680.0 680.0 Fixed Rate Notes Due 2011 150.0 150.0 - - - - - 150.0 150.0 Revolver - - - - - - - - - CalGen $ 2,396.3 $ 2,405.0 $ - $ - $ 4.2 $ 12.1 $ 829.8 $ 1,558.9 $ 2,405.0 Project Financing Gilroy Energy Center $ 242.3 $ 244.6 $ 19.4 $ 40.1 $ 34.6 $ 37.0 $ 37.7 $ 75.8 $ 244.6 Broad River Energy Center 270.3 270.3 5.1 12.1 14.2 16.6 12.6 209.7 270.3 Pasadena Power Plant 282.2 282.2 - 6.7 12.8 15.4 19.1 228.2 282.2 Riverside Energy Center 360.0 360.0 1.8 3.7 3.7 3.7 3.7 343.4 360.0 Blue Spruce Energy Center 98.3 98.3 1.9 3.7 3.8 3.8 3.7 81.4 98.3 Rocky Mountain Energy Center 255.8 255.8 1.3 2.6 2.6 2.6 2.6 244.1 255.8 Aries Power Plant 171.2 171.2 4.7 9.9 10.6 10.7 10.9 124.4 171.2 Fox Energy Center 293.3 293.3 10.6 15.8 1.1 7.2 11.4 247.2 293.3 Otay Mesa Energy Center 7.0 7.0 - - - - - 7.0 7.0 Metcalf Energy Center 100.0 100.0 - - - - - 100.0 100.0 Freeport Energy Center 99.0 99.0 - - 1.5 1.4 1.2 94.9 99.0 Mankato Power Plant 85.6 85.6 - - 1.3 1.3 1.1 81.9 85.6 Bethpage Energy Center 3 123.1 123.1 - 3.6 4.0 4.2 4.2 107.1 123.1 Project Financing $ 2,388.1 $ 2,390.4 $ 44.8 $ 98.2 $ 90.2 $ 103.9 $ 108.2 $ 1,945.1 $ 2,390.4 As of June 30, 2005 (In millions)

APPENDIX B: OUTSTANDING DEBT & PRINCIPAL PAYMENT SCHEDULES (continued) As of June 30, 2005 (In millions) Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Security Balance Sheet Value Outstanding Amount 7/1-12/31 2005 2006 2007 2008 2009 Thereafter Total CCFC I Term Loan Notes Due 2009 $ 376.6 $ 379.2 $ 1.9 $ 3.9 $ 3.9 $ 3.8 $ 365.7 $ - $ 379.2 Floating Rate Notes Due 2011 409.0 415.0 - - - - - 415.0 415.0 CCFC I $ 785.6 $ 794.2 $ 1.9 $ 3.9 $ 3.9 $ 3.8 $ 365.7 $ 415.0 $ 794.2 First Priority Senior Secured Notes 9.625% Senior Secured Notes Due 2014 (C) $ 779.3 $ 785.0 $ - $ - $ - $ - $ - $ 785.0 $ 785.0 First Priority Senior Secured Notes $ 779.3 $ 785.0 $ - $ - $ - $ - $ - $ 785.0 $ 785.0 Second Priority Senior Secured Notes Term Loan B Notes Due 2007 $ 736.9 $ 736.9 $ 3.8 $ 7.5 $ 725.6 $ - $ - $ - $ 736.9 Floating Rate Notes Due 2007 491.3 491.3 2.5 5.0 483.8 - - - 491.3 8.5% Senior Notes Due 2010 1,150.0 1,150.0 - - - - - 1,150.0 1,150.0 9.875% Senior Notes Due 2011 393.6 400.0 - - - - - 400.0 400.0 8.75% Senior Notes Due 2013 900.0 900.0 - - - - - 900.0 900.0 Second Priority Senior Secured Notes $ 3,671.8 $ 3,678.2 $ 6.3 $ 12.5 $ 1,209.4 $ - $ - $ 2,450.0 $ 3,678.2 Convertible Unsecured Senior Notes 4.0% Convertible Senior Notes Due 2006 $ 1.3 $ 1.3 $ - $ 1.3 $ - $ - $ - $ - $ 1.3 6.0% Convertible Senior Notes Due 2014 546.1 641.7 - - - - - 641.7 641.7 7.75% Convertible Senior Notes Due 2015 650.0 650.0 - - - - - 650.0 650.0 4.75% Convertible Senior Notes Due 2023 633.8 633.8 - - - - - 633.8 633.8 Convertible Unsecured Senior Notes $ 1,831.2 $ 1,926.8 $ - $ 1.3 $ - $ - $ - $ 1,925.5 $ 1,926.8

Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Security Balance Sheet Value Outstanding Amount 7/1-12/31 2005 2006 2007 2008 2009 Thereafter Total Unsecured Senior Notes 8.25% Senior Notes Due 2005 $ 186.0 $ 186.1 $ 186.1 $ - $ - $ - $ - $ - $ 186.1 7.625% Senior Notes Due 2006 110.3 110.3 - 110.3 - - - - 110.3 10.5% Senior Notes Due 2006 149.2 149.2 - 149.2 - - - - 149.2 8.75% Senior Notes Due 2007 (Canadian) 162.4 162.8 - - 162.8 - - - 162.8 8.75% Senior Notes Due 2007 192.3 192.3 - - 192.3 - - - 192.3 7.875% Senior Notes Due 2008 227.1 227.3 - - - 227.3 - - 227.3 8.375% Senior Notes Due 2008 (Euro) 141.6 141.6 - - - 141.6 - - 141.6 8.5% Senior Notes Due 2008 1,556.2 1,556.9 - - - 1,556.9 - - 1,556.9 7.75% Senior Notes Due 2009 186.6 186.6 - - - - 186.6 - 186.6 8.625% Senior Notes Due 2010 410.9 411.2 - - - - - 411.2 411.2 8.5% Senior Notes Due 2011 663.4 682.8 - - - - - 682.8 682.8 8.875% Senior Notes Due 2011 (Sterling) 217.8 219.0 - - - - - 219.0 219.0 Unsecured Senior Notes $ 4,203.8 $ 4,226.1 $ 186.1 $ 259.5 $ 355.1 $ 1,925.8 $ 186.6 $ 1,313.0 $ 4,226.1 Notes Payable to Calpine Capital Trust High Tides III (D) $ 517.5 $ 402.5 $ - $ - $ - $ - $ - $ 402.5 $ 402.5 Notes Payable to Calpine Capital Trust $ 517.5 $ 402.5 $ - $ - $ - $ - $ - $ 402.5 $ 402.5 Total Debt $ 18,661.0 $ 18,738.1 $ 619.2 $ 949.2 $ 1,833.2 $ 2,182.8 $ 1,635.6 $ 11,518.1 $ 18,738.1 Scheduled Principal Payments $ 173.1 $ 329.7 $ 268.7 $ 256.8 $ 260.9 Final Principal Payments 446.1 619.5 1,564.5 1,925.8 1,374.7 Total $ 619.2 $ 949.2 $ 1,833.2 $ 2,182.8 $ 1,635.6 APPENDIX B: OUTSTANDING DEBT & PRINCIPAL PAYMENT SCHEDULES (continued) As of June 30, 2005 (In millions) (A) Saltend Redeemable Preferred Shares #1 redeemed in full on July 28 with proceeds from the sale of the Saltend Energy Centre. (B) Saltend Redeemable Preferred Shares #2 redeemed in full on July 28 with proceeds from the sale of the Saltend Energy Centre. (C) On July 12, the company purchased approximately $138.9 million of the 9 5/8% First Priority Senior Secured Notes due 2014. The notes were tendered to the company under the terms of a tender offer commenced on June 9, 2005. (D) On July 13, Calpine redeemed all of its outstanding 5% High Tides III, of which $115 million was held by Calpine.

APPENDIX C: PROJECT PORTFOLIO OPERATING ASSETS Region / Project Location Fuel Baseload Capacity (mw) Capacity w/Peaking (mw) Calpine Interest (%) Net Interest Baseload (mw) Net Interest w/Peaking (mw) Commercial Operation Date / Calpine Acquisition Date ERCOT Freestone Energy Center (CalGen) Texas Natural Gas 1,022.0 1,022.0 100.0% 1,022.0 1,022.0 Jul-02 Deer Park Energy Center Texas Natural Gas 792.0 1,019.0 100.0% 792.0 1,019.0 Jun-03 354 mw, 362 mw; Jun-04 438 mw, 657 mw Baytown Energy Center (CalGen) Texas Natural Gas 742.0 830.0 100.0% 742.0 830.0 May-02 Pasadena Power Plant Texas Natural Gas 776.0 777.0 100.0% 776.0 777.0 Jul-98 231 mw, 240 mw; Jun-00 545 mw, 537 mw Magic Valley Generating Station (CCFC I) Texas Natural Gas 700.0 751.0 100.0% 700.0 751.0 Feb-02 Channel Energy Center (CalGen) Texas Natural Gas 527.0 574.0 100.0% 527.0 574.0 Aug-01 190 mw; Apr-02 337 mw, 384 mw Brazos Valley Power Plant (CCFC I) Texas Natural Gas 450.0 570.0 100.0% 450.0 570.0 Jul-03 / Apr-04 Corpus Christi Energy Center (CalGen) Texas Natural Gas 414.0 537.0 100.0% 414.0 537.0 Oct-02 Texas City Power Plant Texas Natural Gas 457.0 534.0 100.0% 457.0 534.0 May-87 / 50% Jun-97, 50% Apr-98 Clear Lake Power Plant Texas Natural Gas 344.0 400.0 100.0% 344.0 400.0 Jan-85 / 50% Jun-97, 50% Apr-98 Hidalgo Energy Center Texas Natural Gas 499.0 499.0 78.5% 392.0 392.0 Jun-00 Total ERCOT 6,723.0 7,513.0 6,616.0 7,406.0 FRCC Osprey Energy Center (CCFC I) Florida Natural Gas 530.0 609.0 100.0% 530.0 609.0 May-04 Auburndale Power Plant Florida Natural Gas 150.0 150.0 100.0% 150.0 150.0 Jul-94 / Oct-97 Auburndale Peaking Energy Center Florida Natural Gas - 116.0 100.0% - 116.0 Aug-02 Total FRCC 680.0 875.0 680.0 875.0 MAAC Ontelaunee Energy Center (CCFC I) Pennsylvania Natural Gas 561.0 584.0 100.0% 561.0 584.0 Oct-02 Parlin Power Plant New Jersey Natural Gas 98.0 118.0 100.0% 98.0 118.0 Jun-91 / 80% Dec-99, 20% Mar-04 Newark Power Plant New Jersey Natural Gas 50.0 56.0 100.0% 50.0 56.0 Nov-90 / 80% Dec-99, 20% Mar-04 Philadelphia Water Project Pennsylvania Natural Gas - 23.0 83.0% - 19.1 Jan-95 / 66.4% Dec-99, 16.6% Mar-04 Total MAAC 709.0 781.0 709.0 777.1 MAIN Riverside Energy Center Wisconsin Natural Gas 518.0 603.0 100.0% 518.0 603.0 Jun-04 Zion Energy Center, Units 1, 2 & 3 (CalGen) Illinois Natural Gas - 513.0 100.0% - 513.0 Jun-02 300 mw, Jun-03 213 mw RockGen Energy Center Wisconsin Natural Gas - 460.0 100.0% - 460.0 May-01 Fox Energy Center, Phase I Wisconsin Natural Gas 245.0 300.0 100.0% 245.0 300.0 Jun-05 Total MAIN 763.0 1,876.0 763.0 1,876.0

APPENDIX C: PROJECT PORTFOLIO OPERATING ASSETS (continued) Region / Project Location Fuel Baseload Capacity (mw) Capacity w/Peaking (mw) Calpine Interest (%) Net Interest Baseload (mw) Net Interest w/Peaking (mw) Commercial Operation Date / Calpine Acquisition Date NEPOOL Westbrook Energy Center (CCFC I) Maine Natural Gas 528.0 528.0 100.0% 528.0 528.0 May-01 Tiverton Power Plant Rhode Island Natural Gas 267.0 267.0 100.0% 267.0 267.0 Oct-00 Rumford Power Plant Maine Natural Gas 263.0 263.0 100.0% 263.0 263.0 Dec-00 Dighton Power Plant Massachusetts Natural Gas 170.0 170.0 100.0% 170.0 170.0 Jul-99 Androscoggin Energy Center Maine Natural Gas 136.0 136.0 32.3% 44.0 44.0 Jan-00 / Oct-00 Total NEPOOL 1,364.0 1,364.0 1,272.0 1,272.0 NPCC Whitby Cogeneration (1) Ontario Natural Gas 50.0 50.0 15.0% 7.5 7.5 Sep-98 / Sep-01 Total NPCC 50.0 50.0 7.5 7.5 NYPOOL Kennedy International Airport Power Plant New York Natural Gas 99.0 105.0 100.0% 99.0 105.0 Feb-95 / Dec-97 Bethpage Energy Center 3 New York Natural Gas 79.9 79.9 100.0% 79.9 79.9 Jul-05 Bethpage Power Plant New York Natural Gas 55.0 56.0 100.0% 55.0 56.0 Aug-89 / Dec-97 Stony Brook Power Plant New York Natural Gas 45.0 47.0 100.0% 45.0 47.0 Apr-95 / Dec-97 Bethpage Peaker New York Natural Gas - 46.0 100.0% - 46.0 Jul-02 Total NYPOOL 278.9 333.9 278.9 333.9 SERC Morgan Energy Center (CalGen) Alabama Natural Gas 722.0 852.0 100.0% 722.0 852.0 Jun-03 475 mw, 533 mw; Jan-04 247 mw, 319 mw Decatur Energy Center (CalGen) Alabama Natural Gas 793.0 852.0 100.0% 793.0 852.0 Jun-02 437 mw, 528 mw; Jun-03 356 mw, 324 mw Broad River Energy Center South Carolina Natural Gas - 847.0 100.0% - 847.0 Jun-00 540 mw; Aug-01 307 mw / Oct-00 Columbia Energy Center (CalGen) South Carolina Natural Gas 464.0 641.0 100.0% 464.0 641.0 May-04 Acadia Energy Center Louisiana Natural Gas 1,092.0 1,210.0 50.0% 546.0 605.0 Aug-02 Carville Energy Center (CalGen) Louisiana Natural Gas 455.0 531.0 100.0% 455.0 531.0 Jun-03 Santa Rosa Energy Center Florida Natural Gas 250.0 250.0 100.0% 250.0 250.0 Jun-03 Hog Bayou Energy Center Alabama Natural Gas 235.0 237.0 100.0% 235.0 237.0 Jul-01 Pine Bluff Energy Center Arkansas Natural Gas 184.0 215.0 100.0% 184.0 215.0 Sep-01 Total SERC 4,195.0 5,635.0 3,649.0 5,030.0

APPENDIX C: PROJECT PORTFOLIO OPERATING ASSETS (continued) Region / Project Location Fuel Baseload Capacity (mw) Capacity w/Peaking (mw) Calpine Interest (%) Net Interest Baseload (mw) Net Interest w/Peaking (mw) Commercial Operation Date / Calpine Acquisition Date SPP Oneta Energy Center (CalGen) Oklahoma Natural Gas 994.0 994.0 100.0% 994.0 994.0 Jul-02 570 mw; June-03 424 mw Aries Power Project Missouri Natural Gas 523.0 590.0 100.0% 523.0 590.0 Jun-01 320 mw; Feb-02 203 mw, 270 mw Pryor Power Plant Oklahoma Natural Gas 38.0 90.0 100.0% 38.0 90.0 Oct-88 / 80% Dec-99, 20% Mar-04 Total SPP 1,555.0 1,674.0 1,555.0 1,674.0 WECC Delta Energy Center (CalGen) California Natural Gas 799.0 882.0 100.0% 799.0 882.0 Jun-02 Pastoria Energy Center, Phase I (CalGen) California Natural Gas 750.0 750.0 100% 750.0 750.0 May-05 250 mw; Jul-05 500 mw Hermiston Power Project (CCFC I) Oregon Natural Gas 546.0 642.0 100.0% 546.0 642.0 Aug-02 Rocky Mountain Energy Center Colorado Natural Gas 479.0 621.0 100.0% 479.0 621.0 May-04 Metcalf Energy Center California Natural Gas 554.0 600.0 100.0% 554.0 600.0 Jun-05 Los Medanos Energy Center (CalGen) California Natural Gas 497.0 566.0 100.0% 497.0 566.0 Jul-01 Sutter Energy Center (CCFC I) California Natural Gas 535.0 543.0 100.0% 535.0 543.0 Jul-01 South Point Energy Center Arizona Natural Gas 520.0 530.0 100.0% 520.0 530.0 Jun-01 Blue Spruce Energy Center Colorado Natural Gas - 285.0 100.0% - 285.0 Apr-03 Goldendale Energy Center (CalGen) Washington Natural Gas 237.0 271.0 100.0% 237.0 271.0 Sep-04 Los Esteros Critical Energy Center California Natural Gas - 188.0 100.0% - 188.0 Mar-03 Gilroy Peaking Energy Center California Natural Gas - 135.0 100.0% - 135.0 Feb-02 Gilroy Power Plant California Natural Gas 117.0 128.0 100.0% 117.0 128.0 Mar-88 / Aug-96 King City Power Plant California Natural Gas 120.0 120.0 100.0% 120.0 120.0 Apr-89 / Apr-96 Calgary Energy Centre Alberta Natural Gas 252.0 286.0 30.0% 75.6 85.8 Mar-03 McCabe #5 & #6 California Geothermal 75.0 75.0 100.0% 75.0 75.0 Dec-71 / May-99 Island Cogeneration British Columbia Natural Gas 219.0 250.0 30.0% 65.7 75.0 May-02 Ridge Line #7 & #8 California Geothermal 72.0 72.0 100.0% 72.0 72.0 Jan-72 / May-99 Calistoga California Geothermal 70.0 70.0 100.0% 70.0 70.0 Apr-84 / Oct-99 Big Geysers California Geothermal 70.0 70.0 100.0% 70.0 70.0 Jan-80 / May-99 Pittsburg Power Plant California Natural Gas 64.0 64.0 100.0% 64.0 64.0 Jan-65 / Jul-98 Quicksilver California Geothermal 61.0 61.0 100.0% 61.0 61.0 Jan-85 / May-99 Eagle Rock California Geothermal 60.0 60.0 100.0% 60.0 60.0 Jan-75 / May-99 Sulphur Springs California Geothermal 55.0 55.0 100.0% 55.0 55.0 Dec-80 / May-99 Cobb Creek California Geothermal 53.0 53.0 100.0% 53.0 53.0 Jan-79 / May-99 Socrates California Geothermal 51.0 51.0 100.0% 51.0 51.0 Jan-83 / May-99

APPENDIX C: PROJECT PORTFOLIO CONSTRUCTION PROJECTS Region / Project Location Fuel Baseload Capacity (mw) Capacity w/Peaking (mw) Calpine Interest (%) Net Interest Baseload (mw) Net Interest w/Peaking (mw) Estimated Commercial Operation Date ECAR Fremont Energy Center Ohio Natural Gas 550.0 700.0 100.0% 550.0 700.0 Jun-07 Total ECAR 550.0 700.0 550.0 700.0 ERCOT Freeport Energy Center Texas Natural Gas 200.0 250.0 100.0% 200.0 250.0 Steam Delivery to begin Nov-05, COD Nov-06 Total ERCOT 200.0 250.0 200.0 250.0 MAPP Mankato Power Plant Minnesota Natural Gas 292.0 375.0 100.0% 292.0 375.0 Jun-06 Total MAPP 292.0 375.0 292.0 375.0 MAIN Fox Energy Center, Phase II Wisconsin Natural Gas 245.0 260.0 100.0% 245.0 260.0 Dec-05 Total MAIN 245.0 260.0 245.0 260.0 SERC Hillabee Energy Center Alabama Natural Gas 710.0 770.0 100.0% 710.0 770.0 Jun-09 Washington Parish Energy Center Louisiana Natural Gas 509.0 565.0 100.0% 509.0 565.0 Jun-10 Total SERC 1,219.0 1,335.0 1,219.0 1,335.0 WECC Otay Mesa Project California Natural Gas 510.0 593.0 100.0% 510.0 593.0 Nov-07 Total WECC 510.0 593.0 510.0 593.0 MEXICO Valladolid III Mexico Natural Gas 525.0 525.0 45.0% 236.3 236.3 Jun-06 Total Mexico 525.0 525.0 236.3 236.3 TOTAL UNDER CONSTRUCTION 3,541.0 4,038.0 3,252.3 3,749.3

APPENDIX C: PROJECT PORTFOLIO SUMMARY & ASSETS BY REGION OPERATING OPERATING CONSTRUCTION CONSTRUCTION OPERATING + CONSTRUCTION OPERATING + CONSTRUCTION OPERATING + CONSTRUCTION Region Total Net Int. w/Peak. (mw) % Total Net Int. w/Peak. (mw) % Total Net Int. w/Peak. (mw) % ECAR (East Central Area Reliability Coordination) ECAR (East Central Area Reliability Coordination) ECAR (East Central Area Reliability Coordination) - 0.0% 700.0 18.7% 700.0 2.3% ERCOT (Electric Reliability Council of Texas) ERCOT (Electric Reliability Council of Texas) ERCOT (Electric Reliability Council of Texas) 7,406.0 27.4% 250.0 6.7% 7,656.0 24.8% FRCC (Florida Reliability Coordinating Council) FRCC (Florida Reliability Coordinating Council) FRCC (Florida Reliability Coordinating Council) 875.0 3.2% - 0.0% 875.0 2.9% MAAC (Mid-Atlantic Area Council) MAAC (Mid-Atlantic Area Council) MAAC (Mid-Atlantic Area Council) 777.1 2.9% - 0.0% 777.1 2.5% MAPP (Mid-Continent Area Power Pool) MAPP (Mid-Continent Area Power Pool) MAPP (Mid-Continent Area Power Pool) - 0.0% 375.0 10.0% 375.0 1.2% MAIN (Mid-America Interconnected Network) MAIN (Mid-America Interconnected Network) MAIN (Mid-America Interconnected Network) 1,876.0 6.9% 260.0 6.9% 2,136.0 6.9% NPCC-NE (Northeast Power Coordinating Council, New England) NPCC-NE (Northeast Power Coordinating Council, New England) NPCC-NE (Northeast Power Coordinating Council, New England) 1,272.0 4.7% - 0.0% 1,272.0 4.1% NPCC-Ontario (Northeast Power Coordinating Council, Ontario) NPCC-Ontario (Northeast Power Coordinating Council, Ontario) NPCC-Ontario (Northeast Power Coordinating Council, Ontario) 7.5 0.0% - 0.0% 7.5 0.0% NPCC-NY (Northeast Power Coordinating Council, New York) NPCC-NY (Northeast Power Coordinating Council, New York) NPCC-NY (Northeast Power Coordinating Council, New York) 333.9 1.2% - 0.0% 333.9 1.1% SERC (Southeastern Electric Reliability Council) SERC (Southeastern Electric Reliability Council) SERC (Southeastern Electric Reliability Council) 5,030.0 18.6% 1,335.0 35.6% 6,365.0 20.7% SPP (Southwest Power Pool) SPP (Southwest Power Pool) SPP (Southwest Power Pool) 1,674.0 6.2% - 0.0% 1,674.0 5.4% WECC (Western Electricity Coordinating Council) WECC (Western Electricity Coordinating Council) WECC (Western Electricity Coordinating Council) 7,767.8 28.7% 593.0 15.8% 8,360.8 27.2% Mexico Mexico Mexico - 0.0% 236.3 6.3% 236.3 0.0% TOTAL CALPINE 27,019.3 100.0% 3,749.3 100.0% 30,768.5 100.0% # of Projects Total BL Cap. (mw) Total w/Peak. Cap. (mw) Total Net Int. BL (mw) Total Net Int. w/Peak. (mw) Total Operating - Natural Gas Total Operating - Natural Gas Total Operating - Natural Gas 74 22,162.9 27,494.9 21,045.7 26,269.3 Total Operating - Geothermal Total Operating - Geothermal Total Operating - Geothermal 19 750.0 750.0 750.0 750.0 Total Under Construction Total Under Construction Total Under Construction 8 3,541.0 4,038.0 3,252.3 3,749.3 Total Project Portfolio 101 26,453.9 32,282.9 25,047.9 30,768.5 TOTAL PROJECTS IN OPERATION OPERATED BY CALPINE (92) TOTAL PROJECTS IN OPERATION OPERATED BY CALPINE (92) TOTAL PROJECTS IN OPERATION OPERATED BY CALPINE (92) TOTAL PROJECTS IN OPERATION OPERATED BY CALPINE (92) 22,862.9 28,194.9 21,788.2 27,011.8

APPENDIX D: CONTRACTUAL PORTFOLIO SUMMARY 138 Contracts / 99 Customers Weighted Average Credit: A- 7-Year Weighted Average Life

APPENDIX D: CONTRACTUAL PORTFOLIO CONTRACT TYPE 2005 2006 2007 2008 2009 Fixed Price 35% 30% 25% 17% 17% Heat Rate 64% 69% 71% 71% 71% Other 1% 1% 4% 12% 12%

APPENDIX D: CONTRACTUAL PORTFOLIO DEFINITIONS The following detailed reports represent several data points for Calpine's power generation portfolio, primarily, as of June 30, 2005 (see page 39 for additional information). Estimated Generation Baseload - Estimated generation, in millions of megawatt hours, represents the baseload generation capacity of Calpine's fleet based upon a 95% plant availability level. This availability factor is used to account for scheduled maintenance and other miscellaneous outages. It also takes into account the generation capacity year-by-year as a result of our current estimates of commercial operation dates for those plants currently in construction. Peaking - Estimated generation, in millions of megawatt hours, represents a peaking generation capacity based upon a 30% plant availability and dispatch factor or higher if a plant-specific contract dictates.

APPENDIX D: CONTRACTUAL PORTFOLIO DEFINITIONS (continued) Contractual Generation This represents in millions of megawatt hours, the baseload and peaking generation under contract. For those contracts that are take or pay, the contractual generation estimate assumes the customers take 100% of the contracted power. Contracts Announced / Signed Subsequent to June 30, 2005 Contracts that have been announced and, or signed subsequent to June 30, 2005 are not reflected in this data. Such contracts, as they are finalized, will be reflected in future Contractual Portfolios. % Sold Calculated as the contractual generation divided by the estimated generation. Contractual Spark Spread Represents the contractual or "locked in" spark spread embedded in the company's contracted portfolio. Also includes the value of the company's equity gas reserves which is represented by the market price of gas less operating costs.

Estimated Generation (In Millions of mwh) - Baseload 92.3 189.6 200.9 211.5 214.7 - Peaking 13.0 26.0 26.5 27.1 27.0 Total 105.3 215.6 227.4 238.6 241.7 Contractual Generation (In Millions of mwh) - Baseload 52.8 80.5 60.3 58.1 58.8 - Peaking 10.2 18.9 18.7 18.0 15.0 Total 63.0 99.4 79.0 76.1 73.8 % Sold - Baseload 57% 42% 30% 27% 27% - Peaking 78% 73% 71% 66% 56% Total 60% 46% 35% 32% 31% Contractual Spark Spread $839 $1,490 $1,228 $1,332 $1,355 (In Millions) APPENDIX D: CONTRACTUAL PORTFOLIO TOTAL 2005 2006 2007 2008 2009 Data as of 6/30/05(1) Jul-Dec (1) See following page for additional information

APPENDIX D: CONTRACTUAL PORTFOLIO TOTAL (continued) Estimated and Contractual Generation Reflects July Asset Sales Saltend Grays Ferry Contractual Margin Relects Asset Sales Saltend Grays Ferry Oil and Gas Properties As a Result of the Sales of Saltend, Grays Ferry and the Oil and Gas Properties, the Contractual Spark Spread has been Reduced. This will be Offset by Lower Interest Expense Realized from the Repurchase of Debt from Proceeds of the Asset Sales.

Estimated Generation (In Millions of mwh) - Baseload 26.4 53.0 53.7 57.4 57.2 - Peaking 3.4 6.7 6.7 6.9 6.9 Total 29.8 59.7 60.4 64.3 64.1 Contractual Generation (In Millions of mwh) - Baseload 17.5 30.3 24.8 24.7 23.4 - Peaking 2.8 4.2 4.1 4.1 4.1 Total 20.3 34.5 28.8 28.8 27.5 % Sold - Baseload 66% 57% 46% 43% 41% - Peaking 82% 63% 61% 59% 59% Total 68% 58% 48% 45% 43% APPENDIX D: CONTRACTUAL PORTFOLIO WECC 2005 2006 2007 2008 2009 Data as of 6/30/05 Jul-Dec

APPENDIX D: CONTRACTUAL PORTFOLIO ERCOT Estimated Generation (In Millions of mwh) - Baseload 27.7 56.5 56.6 56.8 56.6 - Peaking 1.1 2.3 2.3 2.3 2.3 Total 28.8 58.8 58.9 59.1 58.8 Contractual Generation (In Millions of mwh) - Baseload 19.0 28.1 14.9 14.1 14.0 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 19.0 28.1 14.9 14.1 14.0 % Sold - Baseload 69% 50% 26% 25% 25% - Peaking 0% 0% 0% 0% 0% Total 66% 48% 25% 24% 24% 2005 2006 2007 2008 2009 Data as of 6/30/05 Jul-Dec

APPENDIX D: CONTRACTUAL PORTFOLIO NORTHEAST Estimated Generation (In Millions of mwh) - Baseload 9.6 19.0 19.0 19.5 23.2 - Peaking 0.1 0.3 0.3 0.3 0.3 Total 9.7 19.3 19.3 19.8 23.5 Contractual Generation (In Millions of mwh) - Baseload 4.8 2.9 1.9 1.9 5.9 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 4.8 2.9 1.9 1.9 5.9 % Sold - Baseload 50% 15% 10% 10% 25% - Peaking 0% 0% 0% 0% 0% Total 49% 15% 10% 10% 25% 2005 2006 2007 2008 2009 Data as of 6/30/05 Includes Ontario and the Following NERC Regions: NEPOOL, NYPOOL, MAAC, NPCC Jul-Dec

APPENDIX D: CONTRACTUAL PORTFOLIO SOUTHEAST Estimated Generation (In Millions of mwh) - Baseload 13.2 26.2 29.6 32.2 32.1 - Peaking 4.3 8.5 8.6 8.7 8.6 Total 17.5 34.7 38.2 40.9 40.7 Contractual Generation (In Millions of mwh) - Baseload 4.8 9.8 8.3 7.2 5.4 - Peaking 3.3 6.6 6.6 6.6 6.6 Total 8.1 16.4 14.9 13.8 12.0 % Sold - Baseload 36% 37% 28% 22% 17% - Peaking 77% 78% 77% 76% 77% Total 46% 47% 39% 34% 29% 2005 2006 2007 2008 2009 Data as of 6/30/05 Includes the Following NERC Regions: SERC, FRCC Jul-Dec

APPENDIX D: CONTRACTUAL PORTFOLIO MIDWEST Estimated Generation (In Millions of mwh) - Baseload 15.4 33.8 40.0 43.7 43.6 - Peaking 4.1 8.2 8.6 8.9 8.8 Total 19.5 42.0 48.6 52.6 52.4 Contractual Generation (In Millions of mwh) - Baseload 6.6 8.2 8.3 8.1 8.1 - Peaking 4.1 8.1 8.1 7.4 4.4 Total 10.7 16.3 16.4 15.5 12.5 % Sold - Baseload 43% 24% 21% 19% 19% - Peaking 100% 99% 94% 83% 50% Total 55% 39% 34% 29% 24% 2005 2006 2007 2008 2009 Data as of 6/30/05 Includes the Following NERC Regions/Sub-Region: MAPP, MAIN, ECAR, SPP and Entergy Jul-Dec

APPENDIX D: CONTRACTUAL PORTFOLIO MEXICO Estimated Generation (In Millions of mwh) - Baseload 0.0 1.2 2.0 2.0 2.0 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 0.0 1.2 2.0 2.0 2.0 Contractual Generation (In Millions of mwh) - Baseload 0.0 1.2 2.0 2.0 2.0 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 0.0 1.2 2.0 2.0 2.0 % Sold - Baseload 0% 100% 100% 100% 100% - Peaking 0% 0% 0% 0% 0% Total 0% 100% 100% 100% 100% 2005 2006 2007 2008 2009 Data as of 6/30/05 Includes the Valladolid III Project Jul-Dec