exv99w2

EX-99.2 3 f14192exv99w2.htm EXHIBIT 99.2 exv99w2

Exhibit 99.2

CALPINE CORPORATION EARNINGS CONFERENCE CALL 3RD QUARTER ENDED SEPTEMBER 30, 2005 SAN JOSE, CALIFORNIA

DISCLAIMER: This presentation has been edited and updated to reflect corrections to EBITDA, as adjusted for non-cash and other charges* for the three and nine months ended September 30, 2005. This presentation replaces Calpine's Earnings Conference Call Presentation posted earlier on November 3, 2005. Please refer to Calpine's press release issued on November 3, 2005 at 4:50 p.m. PT for further explanation of these corrections. * See Appendix A for reconciliation from EBITDA, as adjusted.

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. RICK BARRAZA Senior Vice President, 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, and our Current Report on Form 8-K filed on October 17, 2005. These documents can also be found on our web site at www.calpine.com. We undertake no duty to update any forward-looking statement. 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 September 30, 2005.

BUSINESS UPDATE PETE CARTWRIGHT CHAIRMAN, PRESIDENT AND CHIEF EXECUTIVE OFFICER

BUSINESS OVERVIEW 3rd Quarter Results Improving Spark Spreads Bottom-Line Impacted by Non-Operating, Non-Cash Items Electricity Consumption Continuing to Improve Little Damage from Hurricanes Natural Gas Price Volatility

STRATEGIC INITIATIVE UPDATE Completed $2.2 Billion of Asset Sales Repurchased, Redeemed or Repaid $2.3 Billion of Debt Evaluating Further Asset Sales Opportunities Continue Program of Reducing Operating Costs Announced Energy Marketing & Trading Venture with Bear Stearns

3RD QUARTER 2005 FINANCIAL AND OPERATING RESULTS BOB KELLY EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER

KEY FINANCIAL HIGHLIGHTS (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 (In millions, except EPS) (In millions, except EPS) (In millions, except EPS) 3rd Quarter 3rd Quarter 3rd Quarter 2005 2004 Revenue $ 3,281.6 $ 2,411.7 GAAP Basic and Diluted Income (Loss) Per Share $ (0.45) $ 0.32 Operating Cash Flow $ (168.7) $ 217.9 EBITDA, as Adjusted for Non-Cash and Other Charges (1) $ 379.6 $ 433.3 EBITDA, as Adjusted for Non-Cash and Other Charges, to Interest Expense (2) 0.95 1.41

OPERATING LOSS PER SHARE 3rd Quarter 3rd Quarter 3rd Quarter 2005 2004 Net Earnings (Loss) per Share $ (0.45) $ 0.32 Less Discontinued Operations 0.06 0.25 Income (Loss) from Continuing Operations (0.51) 0.07 Calpine Construction Finance Company (CCFC) Non-Cash Tax Reserve 0.30 - Non-Cash Foreign Exchange Transaction Costs 0.06 0.04 Long-Term Service Agreement Cancellation Costs - 0.01 Equipment Cancellation Costs - 0.01 Deferred Financing Cost Writeoff - 0.01 (Gains) on Purchases of Debt (0.02) (0.23) Loss from Continuing Operations After Other Items $ (0.17) $ (0.09)

KEY OPERATING HIGHLIGHTS (1) Total Plant Operating Expenses Include Major Maintenance Expense and are Calculated on a Trailing 12-month Basis at an Assumed 70% Capacity Factor. 3rd Quarter 3rd Quarter 3rd Quarter 9 Months 9 Months 9 Months 2005 2004 2005 2004 Average mw in Operation 26,427 24,281 25,415 23,123 Mwh Generated (000s) 28,709 26,604 68,240 64,357 Mwh Delivered (000s) 40,352 39,999 104,312 103,514 Total Spark Spread (000s) $ 595,299 $ 562,616 $ 1,512,199 $ 1,316,117 Spark Spread (per mwh) $ 20.74 $ 21.15 $ 22.16 $ 20.45 Average Heat Rate (btu/kwh) 7,171 7,178 7,202 7,208 Total Plant Operating Expenses (000s) $ 180,336 $ 159,957 $ 555,433 $ 522,237 Plant Operating Expenses (per mwh)(1) $ 4.97 $ 5.07 $ 4.97 $ 5.07

REGIONAL OPERATING STATISTICS 3rd Quarter 2005 3rd Quarter 2005 3rd Quarter 2005 3rd Quarter 2005 3rd Quarter 2005 3rd Quarter 2005 3rd Quarter 2005 3rd Quarter 2005 3rd Quarter 2005 3rd Quarter 2005 3rd Quarter 2005 3rd Quarter Totals 3rd Quarter Totals 3rd Quarter Totals CA ERCOT Southeast Northeast Midwest Other 2005 2004 Average mw in Operation 5,225 7,430 5,300 1,799 5,061 1,612 26,427 24,281 Availability Factor 96.5% 95.7% 94.5% 98.6% 98.5% 97.5% 96.5% 97.7% Capacity Factor 74.3% 60.4% 29.9% 67.5% 30.3% 63.7% 54.0% 55.4% On-Peak Capacity Factor 84.4% 85.1% 37.4% 66.1% 49.7% 67.3% 67.3% 66.1% Mwh Generated (000s) 7,685 9,910 3,345 2,559 2,427 2,783 28,709 26,604 (1) (1) Includes Other West Regions and Canada

3RD 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 3rd Quarter Spark Spreads Per Mwh 3rd Quarter Spark Spreads Per Mwh 3rd Quarter 2005 2004 NP15 $ 23.27 $ 16.86 SP15 $ 25.89 $ 20.07 ERCOT $ 43.75 $ 14.70 NEPOOL (Maine) $ 16.50 $ 5.80 Southeast $ 16.92 $ 11.41 Note: Figures Represent Average On-Peak, Day-Ahead Spark Spreads at 7,000 btu/kwh Heat Rate. Source: Company Data

2006 FORWARD CURVES Calendar 2006 Forward On-Peak Spark Spreads Per Mwh Source: Company Data, Assumes a 7,000 btu/kwh Heat Rate As of 10/27/05 As of 9/30/04 % Change NP15 $ 22.80 $ 18.03 26% SP15 $ 26.70 $ 21.11 26% ERCOT (Houston) $ 27.74 $ 13.47 106% NEPOOL (Maine) $ 21.64 $ 9.47 128% Southeast $ 11.46 $ 7.78 47%

MANAGING COLLATERAL REQUIREMENTS SUCCESSFULLY MANAGING COLLATERAL IN A RISING NATURAL GAS ENVIRONMENT $0 $5 $10 $15 442.3 482.9 525 533 Cash Deposits 248.9 291.2 285.8 273 Prepaid Gas 78 82.7 86.4 78.9 Letters of Credit 115.4 109 152.8 181.1 $ In Millions $ Per MMBTU Cash Deposits Prepaid Gas Letters of Credit Henry Hub Gas Price Last Month of Quarter (12-31-04) (3-31-05) (6-30-05) (9-30-05)

ENERGY MARKETING & TRADING VENTURE Well-Received by Counterparties Over 75 Agreements in the Hands of Customers Operational and Infrastructure Requirements Completed Risk Management and Controls Financial Reporting Received FERC Approval on October 31 Anticipate $200 Million Collateral Reduction by Mid-2006

3RD QUARTER 2005 FINANCE UPDATE BOB KELLY EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER

YEAR-TO-DATE ASSET SALE SUMMARY Sales Price Pre-Tax GAAP Gain (Loss) Saltend Energy Centre $ 862.9 $ 23.7 Domestic Oil & Gas Properties 1,050.0 366.4(1) Ontelaunee Energy Center 225.0 (137.8) Morris Power Plant 84.5 (106.6) Grays Ferry Power Plant 37.4 (18.6) Totals $ 2,259.8 $ 127.1 (In millions) (1) Includes $26 Million of Deferred Gain Associated with Non-Consent Properties in the Process of Being Transferred to Rosetta.

DEBT REPURCHASED, REDEEMED OR REPAID IN 2005(1) (In Millions) (In Millions) (In Millions) (In Millions) (In Millions) (In Millions) (In Millions) (In Millions) (In Millions) (In Millions) Q1 Q2 Q3 Q4 Total 9.625% First Priority Notes Due 2014 $ - $ - $ 138.9 $ - $ 138.9 8.25% Senior Notes Due 2005 - - 186.1 - 186.1 7.625% Senior Notes Due 2006 - 1.3 8.1 - 9.4 10.5% Senior Notes Due 2006 - 3.5 10.0 - 13.5 8.75% Senior Notes Due 2007 - 3.0 2.0 - 5.0 7.875% Senior Notes Due 2008 - - 53.5 - 53.5 8.5% Senior Notes Due 2008 - 25.5 41.0 93.3 159.8 7.75% Senior Notes Due 2009 - 35.0 6.0 - 41.0 8.625% Senior Notes Due 2010 48.7 37.5 - - 86.2 8.5% Senior Notes Due 2011 31.8 374.0 - - 405.8 6% Convertible Notes Due 2014 - 94.3 - - 94.3 High Tides III - - 517.5 - 517.5 Saltend Redeemable Preferred Shares - - 620.0 - 620.0 CCFC Holdings Redeemable Preferred Shares - - - 150.0 150.0 Total $ 80.5 $ 574.1 $ 1,583.1 $ 243.3 $ 2,481.0 (1) Includes 4th Quarter Transactions Settled On or Before Oct. 31, 2005.

PROGRESS ON DEBT REDUCTION Total Debt as of Total Debt as of Total Debt as of 3/31/05 9/30/05 Non-Recourse Financing $ 7,227.0 $ 7,154.6 First Priority Senior Secured Notes 779.1 641.5 Second Priority Senior Secured Notes 3,674.7 3,668.9 Total Senior Secured Notes 4,453.8 4,310.4 Convertible Unsecured Notes 1,258.5 1,833.8 Unsecured Senior Notes 4,687.1 3,889.2 Total Unsecured 5,945.6 5,723.0 High Tides III 517.5 - Total Debt $ 18,143.9 $ 17,188.0 Less: Construction Financing 109.7 287.6 Totals $ 18,034.2 $ 16,900.4 $ 1,133.8 (In Millions)

LIQUIDITY UPDATE Cash and Cash Equivalents $ 843.1 Current Portion of Restricted Cash Gas Proceeds $ 401.7 Saltend Proceeds 207.5 Cash Collateralized Letters of Credit 194.4 Other 303.1 1,106.7 Total Liquidity $ 1,949.8 (In Millions)

SUMMARY Strong Market On-Peak Spark Spreads Executing Asset Sales $1.1 Billion Debt Reduction

QUESTION AND ANSWER SESSION

APPENDICES

APPENDIX A: GAAP NET INCOME TO EBITDA, AS ADJUSTED FOR NON-CASH AND OTHER CHARGES Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, (In thousands) 2005 2004 2005 2004 GAAP net income (loss) $ (216,689) $ 141,125 $ (683,879) $ 41,235 (Income) loss from unconsolidated investments (5,384) 11,202 (14,644) 12,174 Distributions from unconsolidated investments 6,574 7,566 16,862 22,263 Subtotal (215,499) 159,893 (681,661) 75,672 Interest expense 380,994 285,446 1,027,382 791,242 1/3 of operating lease expense 9,597 8,602 26,366 26,856 Provision (benefit) for income taxes 17,487 (20,324) (167,866) (144,332) Depreciation, depletion, and amortization expense ("DD&A") 142,794 128,103 417,295 374,795 Subtotal 335,373 561,720 621,516 1,124,233 Discontinued operations adjustments: Interest expense 10,418 13,351 74,876 42,162 Provision for income taxes 170,514 102,282 137,629 92,061 Depreciation 3,070 40,752 56,888 144,331 Impairments 136,835 - 242,990 - Income from unconsolidated investments - (1,563) (161) (4,315) Subtotal 320,837 154,822 512,222 274,239 EBITDA, as adjusted $ 656,210 $ 716,542 $ 1,133,738 $ 1,398,472

APPENDIX A: GAAP NET INCOME TO EBITDA, AS ADJUSTED FOR NON-CASH AND OTHER CHARGES Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, (In thousands) 2005 2004 2005 2004 EBITDA, as adjusted $ 656,210 $ 716,542 $ 1,133,738 $ 1,398,472 Equipment cancellation and impairment cost 690 7,820 47,586 10,187 Foreign currency transaction loss 58,934 29,036 57,182 24,204 Unrealized mark-to-market activity loss 27,356 23,762 59,087 57,620 (Gain) on asset sales (364,665) (203,533) (360,232) (249,620) (Income) from repurchase of debt (15,530) (167,154) (166,456) (170,548) SFAS No. 123 (stock-based compensation expense) 4,215 5,218 16,429 14,508 Minority interest expense 10,977 9,990 31,763 23,149 (Income) loss or interest rate swap ineffectiveness (524) (2,369) 316 (1,421) Unconsolidated investment impairment - - 18,542 - Long-term service agreement cancellation charge 553 7,580 34,470 7,580 Write-off of deferred financing costs (not related to bonds repurchased) - 5,976 5,887 25,352 Other non-cash and other charges 1,398 458 2,123 (582) EBITDA, as adjusted, for non-cash and other charges $ 379,614 $ 433,326 $ 880,435 $ 1,138,901

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 10/1-12/31 2005 2006 2007 2008 2009 Thereafter Total Notes Payable / Lines of Credit DWR Monetization 5.2% Senior Secured Notes Due 2006 $ 78.0 $ 78.0 $ - $ 78.0 $ - $ - $ - $ - $ 78.0 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 55.2 85.0 - - - - - 85.0 85.0 Gilroy Note 119.7 119.7 1.9 8.6 9.6 10.6 11.8 77.2 119.7 BPA Monetization 35.2 35.2 5.8 23.4 6.0 - - - 35.2 Calpine Commercial Trust 29.4 31.9 2.3 9.1 9.1 6.8 2.3 2.3 31.9 Miscellaneous 15.1 15.1 12.3 0.3 0.3 0.3 0.3 1.6 15.1 Notes Payable $ 794.9 $ 827.2 $ 22.3 $ 197.3 $ 153.2 $ 115.3 $ 118.1 $ 221.0 $ 827.2 Preferred Interests Auburndale Power Plant $ 78.3 $ 78.3 $ 0.2 $ 0.7 $ 1.5 $ 3.9 $ 6.4 $ 65.6 $ 78.3 Metcalf Energy Center 155.0 155.0 - - - - - 155.0 155.0 Gilroy Energy Center 59.8 59.8 - 8.8 7.5 8.3 9.8 25.4 59.8 CCFC Preferred Holdings (A) 150.0 150.0 - 150.0 - - - - 150.0 Preferred Interests $ 443.1 $ 443.1 $ 0.2 $ 159.5 $ 9.0 $ 12.2 $ 16.2 $ 246.0 $ 443.1 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 98.2 98.2 1.2 2.5 1.5 1.4 2.1 89.5 98.2 Stony Brook Power Plant 62.9 71.7 - 1.2 1.5 1.7 1.8 65.5 71.7 Agnews Power Plant 24.2 24.2 - 3.0 3.3 3.7 4.0 10.2 24.2 Corporate 1.5 1.5 0.2 0.6 0.5 0.2 - - 1.5 Capital Lease Obligations $ 288.2 $ 297.0 $ 1.4 $ 8.4 $ 8.1 $ 10.1 $ 11.2 $ 257.8 $ 297.0 As of September 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 10/1-12/31 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 632.8 640.0 - - - 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 $ 2,396.7 $ 2,405.0 $ - $ - $ 4.2 $ 12.1 $ 829.8 $ 1,558.9 $ 2,405.0 Project Financing Gilroy Energy Center $ 223.1 $ 225.2 $ - $ 40.1 $ 34.6 $ 37.0 $ 37.7 $ 75.8 $ 225.2 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 355.3 355.3 - 3.7 3.7 3.7 3.7 340.5 355.3 Blue Spruce Energy Center 97.3 97.3 0.9 3.8 3.8 3.8 3.8 81.2 97.3 Rocky Mountain Energy Center 245.9 245.9 - 2.6 2.7 2.6 2.6 235.4 245.9 Aries Power Plant 169.5 169.5 3.0 9.9 10.6 10.7 10.9 124.4 169.5 Fox Energy Center 329.0 329.0 - 6.3 19.0 6.6 10.8 286.3 329.0 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 127.4 127.4 - - 2.0 1.8 1.6 122.0 127.4 Mankato Power Plant 117.5 117.5 - - 1.7 1.8 1.5 112.5 117.5 Bethpage Energy Center 3 123.1 123.1 - 3.6 4.0 4.2 4.2 107.1 123.1 Project Financing $ 2,447.6 $ 2,449.7 $ 9.0 $ 88.8 $ 109.1 $ 104.2 $ 108.5 $ 2,030.1 $ 2,449.7 As of September 30, 2005 (In millions)

APPENDIX B: OUTSTANDING DEBT & PRINCIPAL PAYMENT SCHEDULES (continued) As of September 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 10/1-12/31 2005 2006 2007 2008 2009 Thereafter Total CCFC I Term Loan Notes Due 2009 $ 374.8 $ 377.3 $ - $ 3.9 $ 3.9 $ 3.8 $ 365.7 $ - $ 377.3 Floating Rate Notes Due 2011 409.3 415.0 - - - - - 415.0 415.0 CCFC I $ 784.1 $ 792.3 $ - $ 3.9 $ 3.9 $ 3.8 $ 365.7 $ 415.0 $ 792.3 First Priority Senior Secured Notes 9.625% Senior Secured Notes Due 2014 $ 641.5 $ 646.1 $ - $ - $ - $ - $ - $ 646.1 $ 646.1 First Priority Senior Secured Notes $ 641.5 $ 646.1 $ - $ - $ - $ - $ - $ 646.1 $ 646.1 Second Priority Senior Secured Notes Term Loan B Notes Due 2007 $ 735.0 $ 735.0 $ 1.9 $ 7.5 $ 725.6 $ - $ - $ - $ 735.0 Floating Rate Notes Due 2007 490.0 490.0 1.2 5.0 483.8 - - - 490.0 8.5% Senior Notes Due 2010 1,150.0 1,150.0 - - - - - 1,150.0 1,150.0 9.875% Senior Notes Due 2011 393.9 400.0 - - - - - 400.0 400.0 8.75% Senior Notes Due 2013 900.0 900.0 - - - - - 900.0 900.0 Second Priority Senior Secured Notes $ 3,668.9 $ 3,675.0 $ 3.1 $ 12.5 $ 1,209.4 $ - $ - $ 2,450.0 $ 3,675.0 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 548.7 641.7 - - - - - 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 $ 1,833.8 $ 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 10/1-12/31 2005 2006 2007 2008 2009 Thereafter Total Unsecured Senior Notes 7.625% Senior Notes Due 2006 $ 102.2 $ 102.2 $ - $ 102.2 $ - $ - $ - $ - $ 102.2 10.5% Senior Notes Due 2006 139.2 139.2 - 139.2 - - - - 139.2 8.75% Senior Notes Due 2007 (Canadian) 170.4 170.7 - - 170.7 - - - 170.7 8.75% Senior Notes Due 2007 190.3 190.3 - - 190.3 - - - 190.3 7.875% Senior Notes Due 2008 173.6 173.8 - - - 173.8 - - 173.8 8.375% Senior Notes Due 2008 (Euro) 141.3 141.3 - - - 141.3 - - 141.3 8.5% Senior Notes Due 2008 1,515.3 1,515.9 - - - 1,515.9 - - 1,515.9 7.75% Senior Notes Due 2009 180.6 180.6 - - - - 180.6 - 180.6 8.625% Senior Notes Due 2010 410.9 411.2 - - - - - 411.2 411.2 8.5% Senior Notes Due 2011 652.5 682.8 - - - - - 682.8 682.8 8.875% Senior Notes Due 2011 (Sterling) 212.9 214.0 - - - - - 214.0 214.0 Unsecured Senior Notes $ 3,889.2 $ 3,922.0 $ - $ 241.4 $ 361.0 $ 1,831.0 $ 180.6 $ 1,308.0 $ 3,922.0 Total Debt $ 17,188.0 $ 17,384.2 $ 186.0 $ 563.1 $ 1,857.9 $ 2,088.7 $ 1,630.1 $ 11,058.4 $ 17,384.2 APPENDIX B: OUTSTANDING DEBT & PRINCIPAL PAYMENT SCHEDULES (continued) As of September 30, 2005 (In millions) (A) CCFC Redeemable Preferred Shares redeemed in full in October.

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 508.0 594.0 100.0% 508.0 594.0 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 6,781.0 7,537.0 6,674.0 7,430.0 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 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 148.0 197.0 148.0 193.1 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) 7,430.0 28.1% 250.0 6.7% 7,680.0 25.4% FRCC (Florida Reliability Coordinating Council) FRCC (Florida Reliability Coordinating Council) FRCC (Florida Reliability Coordinating Council) 875.0 3.3% - 0.0% 875.0 2.9% MAAC (Mid-Atlantic Area Council) MAAC (Mid-Atlantic Area Council) MAAC (Mid-Atlantic Area Council) 193.1 0.7% - 0.0% 193.1 0.6% 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 7.1% 260.0 6.9% 2,136.0 7.1% 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 4.8% - 0.0% 1,272.0 4.2% 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 1.3% - 0.0% 333.9 1.1% SERC (Southeastern Electric Reliability Council) SERC (Southeastern Electric Reliability Council) SERC (Southeastern Electric Reliability Council) 5,030.0 19.0% 1,335.0 35.6% 6,365.0 21.1% SPP (Southwest Power Pool) SPP (Southwest Power Pool) SPP (Southwest Power Pool) 1,674.0 6.3% - 0.0% 1,674.0 5.5% WECC (Western Electricity Coordinating Council) WECC (Western Electricity Coordinating Council) WECC (Western Electricity Coordinating Council) 7,767.8 29.4% 593.0 15.8% 8,360.8 27.7% Mexico Mexico Mexico - 0.0% 236.3 6.3% 236.3 0.0% TOTAL CALPINE 26,459.3 100.0% 3,749.3 100.0% 30,208.5 100.0% # 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 73 21,659.9 26,934.9 20,542.7 25,709.3 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 100 25,950.9 31,722.9 24,544.9 30,208.5 TOTAL PROJECTS IN OPERATION OPERATED BY CALPINE (91) TOTAL PROJECTS IN OPERATION OPERATED BY CALPINE (91) TOTAL PROJECTS IN OPERATION OPERATED BY CALPINE (91) TOTAL PROJECTS IN OPERATION OPERATED BY CALPINE (91) 22,359.9 27,634.9 21,285.2 26,451.8

APPENDIX D: CONTRACTUAL PORTFOLIO SUMMARY 145 Contracts / 108 Customers Weighted Average Credit: A- 7-Year Weighted Average Life

APPENDIX D: CONTRACTUAL PORTFOLIO CONTRACT TYPE 2006 2007 2008 2009 2010 Fixed Price 23% 16% 16% 17% 6% Heat Rate 76% 79% 72% 72% 81% Other 1% 5% 12% 11% 13%

APPENDIX D: CONTRACTUAL PORTFOLIO DEFINITIONS The following detailed reports represent several data points for Calpine's power generation portfolio, primarily, as of September 30, 2005. Reported data reflects completed power plant and oil and gas property sales. 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 September 30, 2005 Contracts that have been announced and, or signed subsequent to September 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.

APPENDIX D: CONTRACTUAL PORTFOLIO TOTAL Estimated Generation (In Millions of mwh) - Baseload 183.6 195.0 205.5 208.7 208.7 - Peaking 25.9 26.4 26.9 26.9 26.9 Total 209.5 221.4 232.4 235.6 235.6 Contractual Generation (In Millions of mwh) - Baseload 90.2 66.3 59.6 60.2 48.9 - Peaking 18.9 18.7 18.0 15.0 13.3 Total 109.1 85.0 77.6 75.2 62.2 % Sold - Baseload 49% 34% 29% 29% 23% - Peaking 73% 71% 67% 56% 49% Total 52% 38% 33% 32% 26% Contractual Spark Spread $1,313 $1,153 $1,334 $1,359 $1,150 (In Millions) 2006 2007 2008 2009 2010 Data as of 9/30/05 Note: 2006 contractual spark spread is down from June 30, 2005 by approximately $175 million due primarily to gas price increases. However, the un- contracted portfolio increased by approximately $125 million during the same period due to spark spread expansion, which largely resulted from the same gas price movement.

Estimated Generation (In Millions of mwh) - Baseload 53.0 53.7 57.4 57.2 57.2 - Peaking 6.7 6.7 6.9 6.9 6.9 Total 59.7 60.4 64.3 64.1 64.1 Contractual Generation (In Millions of mwh) - Baseload 30.3 24.8 24.7 23.6 14.4 - Peaking 4.2 4.1 4.1 4.1 4.1 Total 34.5 28.9 28.8 27.5 18.5 % Sold - Baseload 57% 46% 43% 41% 25% - Peaking 63% 61% 59% 59% 59% Total 58% 48% 45% 43% 29% APPENDIX D: CONTRACTUAL PORTFOLIO WECC 2006 2007 2008 2009 2010 Data as of 9/30/05

APPENDIX D: CONTRACTUAL PORTFOLIO ERCOT Estimated Generation (In Millions of mwh) - Baseload 56.5 56.6 56.8 56.6 56.6 - Peaking 2.3 2.3 2.3 2.3 2.3 Total 58.8 58.9 59.1 58.9 58.9 Contractual Generation (In Millions of mwh) - Baseload 29.0 15.3 14.2 14.0 14.0 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 29.0 15.3 14.2 14.0 14.0 % Sold - Baseload 51% 27% 25% 25% 25% - Peaking 0% 0% 0% 0% 0% Total 49% 26% 24% 24% 24% 2006 2007 2008 2009 2010 Data as of 9/30/05

APPENDIX D: CONTRACTUAL PORTFOLIO NORTHEAST Estimated Generation (In Millions of mwh) - Baseload 14.2 14.2 14.6 18.4 18.4 - Peaking 0.2 0.2 0.2 0.2 0.2 Total 14.4 14.4 14.8 18.6 18.6 Contractual Generation (In Millions of mwh) - Baseload 3.1 1.8 1.9 5.6 5.6 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 3.1 1.8 1.9 5.6 5.6 % Sold - Baseload 22% 13% 13% 30% 30% - Peaking 0% 0% 0% 0% 0% Total 22% 13% 13% 30% 30% 2006 2007 2008 2009 2010 Data as of 9/30/05 Includes Ontario and the Following NERC Regions: NEPOOL, NYPOOL, MAAC, NPCC

APPENDIX D: CONTRACTUAL PORTFOLIO SOUTHEAST Estimated Generation (In Millions of mwh) - Baseload 26.2 29.6 32.2 32.1 32.1 - Peaking 8.5 8.6 8.7 8.7 8.7 Total 34.7 38.2 40.9 40.8 40.8 Contractual Generation (In Millions of mwh) - Baseload 17.3 14.1 8.7 6.8 4.7 - Peaking 6.6 6.6 6.6 6.6 6.6 Total 23.9 20.7 15.3 13.4 11.3 % Sold - Baseload 66% 48% 27% 21% 15% - Peaking 78% 77% 76% 76% 76% Total 69% 54% 37% 33% 28% 2006 2007 2008 2009 2010 Data as of 9/30/05 Includes the Following NERC Regions: SERC, FRCC

APPENDIX D: CONTRACTUAL PORTFOLIO MIDWEST Estimated Generation (In Millions of mwh) - Baseload 32.6 38.8 42.6 42.4 42.4 - Peaking 8.2 8.6 8.8 8.8 8.8 Total 40.8 47.4 51.4 51.2 51.2 Contractual Generation (In Millions of mwh) - Baseload 9.4 8.3 8.1 8.1 8.1 - Peaking 8.1 8.1 7.4 4.4 2.6 Total 17.5 16.4 15.5 12.5 10.7 % Sold - Baseload 29% 21% 19% 19% 19% - Peaking 99% 94% 84% 50% 30% Total 43% 35% 30% 24% 21% 2006 2007 2008 2009 2010 Data as of 9/30/05 Includes the Following NERC Regions/Sub-Region: MAPP, MAIN, ECAR, SPP and Entergy

APPENDIX D: CONTRACTUAL PORTFOLIO MEXICO Estimated Generation (In Millions of mwh) - Baseload 1.2 2.0 2.0 2.0 2.0 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 1.2 2.0 2.0 2.0 2.0 Contractual Generation (In Millions of mwh) - Baseload 1.2 2.0 2.0 2.0 2.0 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 1.2 2.0 2.0 2.0 2.0 % Sold - Baseload 100% 100% 100% 100% 100% - Peaking 0% 0% 0% 0% 0% Total 100% 100% 100% 100% 100% 2006 2007 2008 2009 2010 Data as of 9/30/05 Includes the Valladolid III Project