8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of

The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): August 3, 2005

CALPINE CORPORATION

(A Delaware Corporation)

Commission File Number: 001-12079

I.R.S. Employer Identification No. 77-0212977

50 West San Fernando Street

San Jose, California 95113

Telephone: (408) 995-5115

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o   Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o   Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o   Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o   Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

TABLE OF CONTENTS

	ITEM 2.02. RESULTS OF OPERATIONS AND FINANCIAL CONDITION
	ITEM 9.01. FINANCIAL STATEMENTS AND EXHIBITS
SIGNATURES
EXHIBIT INDEX
EXHIBIT 99.1
EXHIBIT 99.2

SECTION 2 – FINANCIAL INFORMATION

ITEM 2.02. RESULTS OF OPERATIONS AND FINANCIAL CONDITION

On August 3, 2005, the Registrant issued the press release attached hereto as Exhibit 99.1 reporting financial and operating results for the quarter ended June 30, 2005. The registrant also attaches Exhibit 99.2 hereto the materials presented in connection with the registrant’s August 3, 2005 earnings conference call and webcast presentation.

SECTION 9 – FINANCIAL STATEMENTS AND EXHIBITS

ITEM 9.01. FINANCIAL STATEMENTS AND EXHIBITS

(a)	Financial Statements of Businesses Acquired .
	Not Applicable
(b)	Pro Forma Financial Information .
	Not Applicable
(c)	Exhibits .

Exhibit	Description
99.1	Press release
99.2	Presentation Materials

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	CALPINE CORPORATION
	By:	/s/ Charles B. Clark, Jr.
		Charles B. Clark, Jr.
Date: August 8, 2005		Senior Vice President and Controller Chief Accounting Officer

EXHIBIT INDEX

Exhibit	Description
99.1	Press release
99.2	Presentation Materials

EX-99.1

Exhibit 99.1

CONTACTS: 408-995-5115
Media Relations: Bill Highlander, Ext. 1244
Investor Relations: Karen Bunton, Ext. 1121
Lisa Poelle, Ext. 1285

CALPINE REPORTS SECOND QUARTER 2005
FINANCIAL AND OPERATING RESULTS

     (SAN JOSE, CALIF.) /PR Newswire – First Call/ August 3, 2005 – Calpine Corporation [NYSE:CPN] reported financial and operating results for the three and six months ended June 30, 2005. A conference call, set for 8:30 a.m. PDT today, will be accompanied by a comprehensive presentation of the second quarter results. The presentation will be posted on Calpine’s investor relations page at www.calpine.com prior to the conference call.

	Second Quarter
	(unaudited)
	2005			2004
Megawatt-hours Generated (millions) (a)		20.0			20.1
Megawatts in Operation at June 30 (a)		26,599			25,085
Revenue (millions) (a)	$	2,226.0		$	2,215.4
Net (Loss) (millions)	$	(298.5	)	$	(28.7	)
Basic and Diluted (Loss) Per Share	$	(0.66	)	$	(0.07	)
Operating Cash Flow (millions)	$	(124.7	)	$	185.2
EBITDA, as adjusted (millions) (b)	$	215.1		$	388.5
EBITDA, as adjusted, for non-cash and other charges (millions) (c)	$	251.4		$	446.2
Total Assets (billions)	$	27.8		$	27.4

(a)	From continuing operations.
(b)	Earnings Before Interest, Tax, Depreciation and Amortization, as adjusted; see attached Supplemental Data for reconciliation from net income.
(c)	See Supplemental Data for reconciliation from EBITDA, as adjusted.

     Peter Cartwright, Calpine president and CEO, said, “During the second quarter, spark spreads were mixed, and Calpine experienced several unplanned equipment outages in key power markets. Financial results were further impacted by power plant and development project asset impairments and service agreement cancellations, totaling just over $200 million. These were partially mitigated by approximately $129 million of income from repurchase of debt.

     “While results for the quarter were disappointing, Calpine continues to make significant progress in advancing our strategic initiative to de-lever our balance sheet and reduce interest expense and operating costs. In just over two months since our May rollout, Calpine has completed or announced over $2 billion of transactions toward attaining these goals, and since the beginning of the third quarter, we have lowered total debt by approximately $1.3 billion to $17.4 billion.

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     “Although demand in the second quarter was dampened by mild weather, especially in April and May, since June we have seen strong demand for electricity and improving spark spreads in our major power markets,” continued Cartwright. “Our recently restructured long-term service arrangements with our major equipment manufacturers will advance Calpine’s program to lower operating costs, improve plant performance and enhance our major maintenance capabilities.”

2005 Second Quarter Financial Results

     For the three months ended June 30, 2005, Calpine reported revenue of $2.2 billion, representing an increase of 0.5% over the same period in the prior year. Including the discontinued operations discussed below, Calpine recorded a net loss per share of $0.66, or a net loss of $298.5 million, compared to a net loss per share of $0.07, or a net loss of $28.7 million, for the same quarter in the prior year.

     Included in the current quarter’s results are various non-routine items, which are discussed in more detail below and in the aggregate netted to a charge of $0.11 per share, consisting of impairment charges on two power plants in operation and three in development, cancellation charges to terminate several long-term service agreements, and a net gain on the repurchase of debt.

     For the three months ended June 30, 2005, Calpine’s average capacity in operation for consolidated projects increased by 10.9% to 25,566 megawatts. Generation volume was flat from the prior year as mild weather in April and May decreased demand, and Calpine also experienced forced outages at certain of its power plants. The company generated approximately 20.0 million megawatt-hours, which equated to a baseload capacity factor of 39.9%, and realized an average spark spread of $22.57 per megawatt-hour. For the same period in 2004, Calpine generated 20.1 million megawatt-hours, which equated to a baseload capacity factor of 45.0%, and realized an average spark spread of $20.62 per megawatt-hour.

     Gross profit decreased by $58.8 million to a loss of $31.5 million in the three months ended June 30, 2005, compared to the same period in the prior year. This change is due primarily to a $106.2 million impairment charge related to the sale of the Morris Power Plant, which sale was pending at the end of the quarter. Although total spark spread margin increased by $38.6 million period-to-period, it did not increase in line with the increases in transmission purchase expense, depreciation and interest expense associated with new power plants coming on line.

     During the three months ended June 30, 2005, financial results were positively impacted by $129.2 million of income recorded from repurchase of various issuances of debt and negatively impacted by $33.9 million in long-term service agreement cancellation charges. In addition, Calpine recorded $45.5 million in project development expense due to the write-off of three projects in suspended development. Interest expense increased $63.2 million between periods primarily due to an increase in the average interest rate and lower capitalization of interest expense as fewer plants were in active construction.

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     Other expense was $25.8 million for the three months ended June 30, 2005, compared to other income of $179.5 million for the three months ended June 30, 2004. The net expense for the three months ended June 30, 2005, was due mainly to an impairment charge of $18.5 million related to the sale of Calpine’s investment in the Grays Ferry Cogeneration Facility in July 2005. Other income for the quarter ended June 30, 2004, included $171.5 million in pre-tax gains from the restructuring and sale of power purchase agreements for two of the company’s New Jersey plants, net of transaction costs and the write-off of unamortized deferred financing costs.

     The discontinued operations in the three months ended June 30, 2005, are a result of the sale of the Saltend Energy Centre and Calpine’s remaining domestic oil and gas exploration and production properties and assets. Both of these sales closed in July 2005. Discontinued operations for the three months ended June 30, 2004, also included the Lost Pines I Power Project and oil and gas sales in 2004. On August 3, 2005, Calpine will file a Form 8-K for the disposition of the Saltend Energy Centre. The Form 8-K will include a pro forma balance sheet as of March 31, 2005, and pro forma income statements for the three months ended March 31, 2005, and for the years ended December 31, 2004, 2003 and 2002, that will adjust for the effects of the sale of the Saltend Energy Centre, as well as the sale of Calpine’s remaining domestic oil and gas exploration and production properties and assets.

2005 Six-Months Results

     For the six months ended June 30, 2005, Calpine reported revenue of $4.3 billion, representing an increase of 4.2% over the same period in the prior year. Including the discontinued operations discussed below, Calpine recorded a net loss per share of $1.04, or a net loss of $467.2 million, compared to a net loss per share of $0.24, or a net loss of $99.9 million, for the same period in the prior year.

     Included in the six-months results are various non-routine items, which are discussed in more detail below and in the aggregate netted to a charge of $0.08 per share, consisting of impairment charges on two power plants in operation and three in development, cancellation charges to terminate several long-term agreements, and a net gain on the repurchase of debt.

     For the six months ended June 30, 2005, Calpine’s average capacity in operation for consolidated projects increased by 16.0% to 25,330 megawatts. The company generated approximately 40.1 million megawatt-hours, which equated to a baseload capacity factor of 40.6%, and realized an average spark spread of $22.61 per megawatt-hour. For the same period in 2004, Calpine generated 38.7 million megawatt-hours, which equated to a baseload capacity factor of 46.2%, and realized an average spark spread of $19.67 per megawatt-hour.

     Gross profit decreased by $24.8 million, or 34%, to $48.3 million in the six months ended June 30, 2005, compared to the same period in the prior year. This change is due primarily to a $106.2 million impairment charge related to the sale of the Morris Power Plant. Despite improvements in market fundamentals, total spark spread – which increased by $144.8 million, or 19%, in the six months ended June 30, 2005, compared to the same period in 2004 – did not increase in line with the increases in plant operating expense, transmission purchase expense, depreciation, and interest expense associated with new power plants coming on line.

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     During the six months ended June 30, 2005, financial results were positively impacted by $150.9 million of income recorded from repurchase of various issuances of debt and negatively impacted by $33.9 million in long-term service agreement cancellation charges. In addition, Calpine recorded $45.5 million in project development expense due to the write-off of three projects in suspended development. Interest expense increased $142.3 million between periods primarily due to an increase in the average interest rate and lower capitalization of interest expense as fewer plants were in active construction.

     Other expense was $20.8 million for the six months ended June 30, 2005, compared to other income of $191.4 million for the six months ended June 30, 2004. The net expense for the six months ended June 30, 2005, was due mainly to an impairment charge of $18.5 million related to the sale of Calpine’s interest in the Grays Ferry Cogeneration Facility in July 2005. Other income for the six months ended June 30, 2004, included $171.5 million in pre-tax gains from the restructuring and sale of power purchase agreements for two of the company’s New Jersey plants, net of transaction costs and the write-off of unamortized deferred financing costs.

     The discontinued operations in the six months ended June 30, 2005, are a result of the July 2005 sales of the Saltend Energy Centre and Calpine’s remaining domestic oil and gas exploration and production properties and assets. Discontinued operations for the six months ended June 30, 2004, also included the Lost Pines 1 Power Project and oil and gas sales in 2004.

Strategic Initiative Update

     On May 25, 2005, Calpine launched a strategic initiative aimed at reducing debt and enhancing the company’s financial strength. The program is targeting debt reduction of approximately $3 billion by the end of 2005, $275 million of annual interest savings and approximately $200 million in annual operating cost reductions. During the second quarter, Calpine entered into negotiations for the proposed sale of two gas-fired power plants, representing approximately 600 megawatts of capacity.

     Subsequent to June 30, 2005, Calpine:

• Sold all of its remaining domestic oil and gas exploration and production properties and assets for $1.05 billion, less adjustments, transaction fees and expenses, and less approximately $75 million to reflect the value of certain oil and gas properties for which the company was unable to obtain consents to assignment prior to closing. The company expects to receive the remaining consents in the near future. With the completion of this transaction, Calpine expects to record, subsequent to June 30, 2005, a pre-tax gain on the sale of assets of approximately $350.0 million;

• Completed the sale of the 1,200-megawatt Saltend Energy Centre in Hull, England, generating total gross proceeds of $862.5 million, for an estimated pre-tax gain of $6 million. The two existing series of Redeemable Preferred Shares relating to the Saltend Energy Centre were redeemed in connection with the sale;

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• Reached an agreement with Siemens Westinghouse to restructure Calpine’s long-term relationship and service agreements. The restructuring provides greater operating and turbine maintenance flexibility for Calpine, resolves outstanding issues between the companies and provides an option to purchase extended warranties for Calpine turbines in construction and in storage;

• Announced a 15-year Master Products and Services Agreement with General Electric International, Inc., which replaces the nine remaining long-term service agreements related to Calpine’s GE 7FA turbine fleet. Calpine will benefit from the ability to strengthen its major maintenance capabilities, improve power plant performance and lower operating costs;

• Sold its 50% interest in the 175-megawatt Grays Ferry Cogeneration Facility for $37.4 million;

• Completed the sale of the company’s 156-megawatt Morris Power Plant for approximately $84.5 million; and

• Purchased approximately $138.9 million of its 9 5/8% First Priority Senior Secured Notes due 2014 under the terms of a tender offer.

Other Financing Transactions

     During the second quarter, Calpine completed the following financing transactions:

• Issued $650.0 million of 7 3/4% Contingent Convertible Notes due 2015 in June 2005. The company, in July 2005, used a portion of the net proceeds to redeem the remaining $517.5 million outstanding of 5% HIGH TIDES III preferred securities, of which $115.0 million was held by Calpine. The company used the remaining net proceeds to repurchase a portion of the outstanding principal amount of its 8 1/2% Senior Unsecured Notes due 2011;

• Received funding for Metcalf Energy Center, LLC’s $155.0 million offering of 5.5-Year Redeemable Preferred Shares and five-year, $100.0 million Senior Term Loan. A portion of the net proceeds was used to repay $50.0 million outstanding on the original Metcalf project financing, with the remaining net proceeds to be used as permitted by the company’s existing indentures.

• Received funding for its $123.1 million, non-recourse project finance facility to complete the construction of the 79.9-megawatt Bethpage Energy Center 3. Approximately $55.0 million of the funding was used to reimburse Calpine for costs spent to date on the Bethpage 3 project. An additional amount of approximately $11.2 million will be released upon satisfying certain conditions. The balance of funds will be used for transaction expenses, the final completion of the project and to fund certain reserve accounts.

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     Calpine ended the quarter with cash and cash equivalents on hand of approximately $636.2 million. In addition to this amount, the company’s current portion of restricted cash totaled approximately $993.9 million, including $402.5 million used in July 2005 to redeem the remaining HIGH TIDES III preferred securities held by third parties.

     During the three months ended June 30, 2005, Calpine repurchased Senior Notes in open market transactions totaling $479.8 million in principal. The company repurchased the Senior Notes for cash totaling $337.9 million plus accrued interest as follows (in thousands):

Senior Notes	Principal		Cash Payment
10 1/2% due 2006	$	3,485.0	$	2,753.2
7 5/8% due 2006		1,335.0		1,041.3
8 3/4% due 2007		3,000.0		1,665.0
8 1/2% due 2008		25,500.0		18,297.5
7 3/4% due 2009		35,000.0		20,865.0
8 5/8% due 2010		37,468.0		24,077.4
8 1/2% due 2011		374,000.0		269,154.8
Total repurchases	$	479,788.0	$	337,854.2

     Also, in June 2005, Calpine repurchased $94.3 million in aggregate outstanding principal amount of 6% Contingent Convertible Notes due 2014 in exchange for 27,539,826 shares of Calpine common stock. The company recorded a pre-tax loss of $7.9 million on the exchange, which includes the write-off of the associated unamortized deferred financing costs and unamortized original issue discount.

     For the three months ended June 30, 2005, the company recorded an aggregate pre-tax gain of $129.2 million on the above debt repurchases after the write-off of unamortized deferred financing costs and unamortized discounts.

Operations Update

     During the second quarter Calpine experienced planned (4.7 million megawatt-hours) and unplanned (2.6 million megawatt-hours) outages that significantly impacted operations. Several major power plants were off-line in Calpine’s key power markets, including California, Arizona, Texas and New England. These extended forced outages were primarily related to equipment failure, which the company has since resolved.

     Also during the second quarter, Calpine:

• Generated 20.0 million megawatt-hours for the quarter, slightly lower than 2004 levels;

• Operated its gas-fired power plants with an average baseload heat rate of 7,294 million British thermal units per kilowatt-hour, compared to 7,265 in 2004;

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• Reduced total plant operating expense (based on a trailing 12-month period ending June 30, at an assumed 70% capacity factor) to $4.95 per megawatt-hour from $5.41 per megawatt-hour in 2004;

• Operated its natural gas-fired and geothermal power plants with an average availability of 89.0%, compared to 88.9% in 2004;

• Started-up the 600-megawatt Metcalf Energy Center for the Northern California power market. Metcalf is the first large power plant in Silicon Valley. It will be the cornerstone of energy supply and reliability for the region;

• Placed Phase I (300 megawatts) of the Fox Energy Center into operation. The new, natural gas-fired, combined-cycle power plant, located in Wisconsin, is providing approximately 150 megawatts of capacity to Wisconsin Public Service Corporation, with the remainder available for sale into the region’s wholesale power market; and

• Pledged to reduce its greenhouse gas (GHG) efficiency-based emissions rate (pounds of GHG emitted per megawatt-hour of electricity generated) by 4% from 2003 levels. Compared to the average fossil-fueled power plant in the United States, Calpine’s combined-cycle, natural gas-fired units on average release nearly 54% less carbon dioxide – the principal greenhouse gas.

     Subsequent to June 30, 2005, Calpine:

• Entered into agreements with GE Energy (GE) to begin construction this month of North America’s most advanced natural gas-fired, combined-cycle power plant at the Inland Empire site in Southern California. GE has acquired development rights for the plant from Calpine and will finance and operate the new H System ^TM power plant. Calpine will manage plant construction and will market the plant’s output and manage its fuel requirements under a long-term arrangement with GE;

• Started-up 500 megawatts of new capacity to the Pastoria Energy Center, bringing the plant’s total output to 750 megawatts. Pastoria, located in the attractive Southern California power market, is the single-largest capacity addition to occur in the state before peak summer power demand;

• Completed construction of the Bethpage Energy Center 3, the region’s first modern, natural gas-fired, combined-cycle power plant. Calpine’s new plant provides up to 79.9 megawatts of electricity to Long Island Power Authority customers under a 20-year contract for capacity, energy and other energy-related services; and

• Received an award from the U.S. Department of Labor’s Occupational Safety and Health Administration’s (OSHA) highest safety recognition for Calpine’s Tiverton, R.I. and Ontelaunee, Pa. power plants under OSHA’s Voluntary Protection Program.

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New Market Opportunities

     During the quarter, Calpine:

• Announced an agreement to supply up to 485 megawatts of electricity to Entergy from the Carville Energy Center in Louisiana. Carville is part of NewSouth Energy’s marketing network of nearly 6,000 megawatts of modern, gas-fired power plants in the Southeast United States;

• Expanded and extended its power sales to Safeway Inc. The new agreement calls for the delivery of approximately 130 megawatts, a 20-megawatt increase, and extends the term of the existing contract one additional year through mid-2008. The newly expanded Safeway contract now facilitates energy deliveries to more than 400 Safeway locations throughout California; and

• Entered into a 20-year power sales agreement in partnership with Mitsui & Co., Ltd., with the Ontario Power Authority to provide energy from a new 1,005-megawatt natural gas-fired power plant to be located in Ontario. As part of its turbine inventory deployment program, Calpine’s equity in the project will be three of the company’s gas turbines and one steam turbine.

     Included in the attached Supplemental Data to this news release is an updated report summarizing Calpine’s total estimated generation capacity and capacity currently under contract through 2009. A full detailed report is available on the company’s website at www.calpine.com.

Conference Call Information

     Calpine will host a conference call to discuss its financial and operating results for the three and six months ended June 30, 2005, on Wednesday, August 3, 2005, at 8:30 a.m. PDT. To participate via the teleconference (in listen-only mode), dial 1-888-603-6685 (1-706-634-1265 for international callers) at least five minutes before the start of the call. In addition, Calpine will simulcast the conference call and presentation live via the Internet. The webcast and presentation will be available for 30 days on Calpine’s investor relations page at www.calpine.com.

About Calpine

     A major power company, Calpine Corporation supplies customers and communities with electricity from clean, efficient, natural gas-fired and geothermal power plants. Calpine owns, leases and operates integrated systems of plants in 21 U.S. states and three Canadian provinces. Its customized products and services include wholesale and retail electricity, natural gas, gas turbine components and services, energy management, and a wide range of power plant engineering, construction and operations services. Calpine was founded in 1984. It is included in the S&P 500 Index and is publicly traded on the New York Stock Exchange under the symbol CPN. For more information, visit http://www.calpine.com.

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     This news release 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 the intent, belief or current expectations of Calpine Corporation (“the company”) and its management. Prospective investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties that could materially affect actual results. Such risks and uncertainties include, but are not limited to, (i) the timing and extent of deregulation of energy markets and the rules and regulations adopted on a transitional basis with respect thereto, (ii) the timing and extent of changes in commodity prices for energy, particularly natural gas and electricity, and the impact of related derivatives transactions, (iii) unscheduled outages of operating plants, (iv) unseasonable weather patterns that reduce demand for power, (v) economic slowdowns that can adversely affect consumption of power by businesses and consumers, (vi) various development and construction risks that may delay or prevent commercial operations of new plants, such as failure to obtain the necessary permits to operate, failure of third-party contractors to perform their contractual obligations or failure to obtain project financing on acceptable terms, (vii) uncertainties associated with cost estimates, that actual costs may be higher than estimated, (viii) development of lower-cost power plants or of a lower cost means of operating a fleet of power plants by our competitors, (ix) risks associated with marketing and selling power from power plants in the evolving energy market, (x) factors that impact the exploitation of a geothermal resource, (xi) uncertainties associated with estimates of geothermal reserves, (xii) the effects on our business resulting from reduced liquidity in the trading and power generation industry, (xiii) our ability to access the capital markets or other financing sources on attractive terms or at all, (xiv) our ability to successfully implement the various components of our strategic initiative to increase liquidity, reduce debt and reduce operating costs, (xv) uncertainties associated with estimates of sources and uses of cash, that actual sources may be lower and actual uses may be higher than estimated, (xvi) the direct or indirect effects on our business of a lowering of our credit rating (or actions we may take in response to changing credit rating criteria), including increased collateral requirements, refusal by our current or potential counterparties to enter into transactions with us and our inability to obtain credit or capital in desired amounts or on favorable terms, (xvii) present and possible future claims, litigation and enforcement actions, (xviii) effects of the application of regulations, including changes in regulations or the interpretation thereof, and (xvix) other risks identified in the company’s reports and registration statements filed with the SEC, including, but not limited to, the risk factors identified in its Annual Report on Form 10-K for the year ended Dec. 31, 2004, and for the quarter ended March 31, 2005, which can also be found on the company’s website at www.calpine.com. All information set forth in this news release is as of today’s date, and the company undertakes no obligation to update any forward-looking statements, whether as a result of new information, future developments or otherwise.

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CALPINE CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
For the Three and Six Months Ended June 30, 2005 and 2004
(in thousands, except per share amounts)
(unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue	$	1,298,973		$	1,239,147		$	2,577,252		$	2,372,342
Transmission sales revenue		3,144			4,049			6,888			9,724
Sales of purchased power for hedging and optimization		432,846			496,026			780,256			873,849
Total electric generation and marketing revenue		1,734,963			1,739,222			3,364,396			3,255,915
Oil and gas production and marketing revenue
Oil and gas sales		(34	)		1,034			27			2,016
Sales of purchased gas for hedging and optimization		456,920			481,971			877,216			834,708
Total oil and gas production and marketing revenue		456,886			483,005			877,243			836,724
Mark-to-market activities, net		2,874			(22,605	)		(657	)		(10,086	)
Other revenue		31,234			15,781			52,420			36,803
Total revenue		2,225,957			2,215,403			4,293,402			4,119,356
Cost of revenue:
Electric generation and marketing expense
Plant operating expense		201,855			204,583			384,104			370,249
Transmission purchase expense		19,807			14,651			40,681			31,078
Royalty expense		8,143			6,951			18,473			12,833
Purchased power expense for hedging and optimization		335,142			444,545			616,337			817,578
Total electric generation and marketing expense		564,947			670,730			1,059,595			1,231,738
Oil and gas operating and marketing expense
Oil and gas operating expense		1,124			2,076			2,925			3,986
Purchased gas expense for hedging and optimization		486,082			453,922			899,341			814,409
Total oil and gas operating and marketing expense		487,206			455,998			902,266			818,395
Fuel expense		913,531			899,291			1,807,839			1,676,077
Depreciation, depletion and amortization expense		127,921			112,505			248,627			216,281
Power plant impairment		106,155			—			106,155			—
Operating lease expense		25,528			26,963			50,305			54,762
Other cost of revenue		32,149			22,609			70,321			48,989
Total cost of revenue		2,257,437			2,188,096			4,245,108			4,046,242
Gross profit		(31,480	)		27,307			48,294			73,114
(Income) loss from unconsolidated investments		(3,268	)		2,085			(9,260	)		972
Equipment cancellation and impairment cost		—			7			(73	)		2,367
Long-term service agreement cancellation charge		33,918			—			33,918			—
Project development expense		52,821			4,030			61,541			11,748
Research and development expense		5,126			5,124			12,159			8,939
Sales, general and administrative expense		68,993			54,283			122,627			102,932
Income from operations		(189,070	)		(38,222	)		(172,618	)		(53,844	)
Interest expense		333,778			270,576			658,444			516,161
Interest (income)		(16,793	)		(9,508	)		(30,778	)		(21,045	)
Minority interest expense		10,172			4,724			20,786			13,159
(Income) from repurchase of various issuances of debt		(129,154	)		(2,559	)		(150,926	)		(3,394	)
Other expense (income), net		25,765			(179,533	)		20,805			(191,360	)
Income (loss) before provision or benefit for income taxes		(412,838	)		(121,922	)		(690,949	)		(367,365	)
Provision (benefit) for income taxes		(134,862	)		(73,374	)		(233,591	)		(175,233	)
Income (loss) before discontinued operations		(277,976	)		(48,548	)		(457,358	)		(192,132	)

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August 3, 2005

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
(in thousands, except per share amounts)	(Unaudited)
Discontinued operations, net of tax provision of $1,433, $12,770, $15,354 and $41,005		(20,482	)		19,850			(9,831	)		92,242
Net income (loss)	$	(298,458	)	$	(28,698	)	$	(467,189	)	$	(99,890	)
Basic and diluted earnings (loss) per common share:
Weighted average shares of common stock outstanding		449,183			417,357			448,391			416,332
Income (loss) before discontinued operations	$	(0.62	)	$	(0.12	)	$	(1.02	)	$	(0.46	)
Discontinued operations, net of tax	$	(0.04	)	$	0.05		$	(0.02	)	$	0.22
Net income (loss)	$	(0.66	)	$	(0.07	)	$	(1.04	)	$	(0.24	)

The financial information presented above and in the Supplemental Data is subject to adjustment until the company files its Form 10-Q with the United States Securities and Exchange Commission for the three and six months ended June 30, 2005.

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August 3, 2005

CALPINE CORPORATION AND SUBSIDIARIES
Supplemental Data
(unaudited)

CASH FLOW DATA

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2005			2004			2005			2004
Cash provided by (used in) operating activities	$	(124,667	)	$	185,223		$	(239,259	)	$	11,993
Cash used in investing activities		(737,787	)		(96,020	)		(958,635	)		(167,391	)
Cash provided by financing activities		756,011			180,860			1,124,721			20,769
Effect of exchange rate changes on cash and cash equivalents		(4,811	)		(8,836	)		(8,897	)		(13,146	)
Reclassification of change in cash included in Assets of discontinued operations, current portion		(26,608	)		53,911			254			10,582
Net increase (decrease) in cash and cash equivalents.	$	(137,862	)	$	315,138		$	(81,816	)	$	(137,193	)

RECONCILIATION OF GAAP CASH USED IN OPERATING ACTIVITIES TO
EBITDA, AS ADJUSTED (1)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2005			2004			2005			2004
Cash provided by (used in) operating activities	$	(124,667	)	$	185,223		$	(239,259	)	$	11,993
Less: Changes in operating assets and liabilities, net of effects of acquisitions		(31,570	)		(86,518	)		51,256			51,227
Less: Additional adjustments to reconcile net income to net cash used in operating activities, net		(142,221	)		(127,403	)		(279,186	)		(163,110	)
GAAP net income (loss)		(298,458	)		(28,698	)		(467,189	)		(99,890	)
(Income) loss from unconsolidated investments		(3,268	)		2,085			(9,260	)		972
Distributions from unconsolidated investments		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 (benefit) for income taxes, DD&A and income from unconsolidated investments from discontinued operations		52,478			69,769			113,119			151,471
EBITDA, as adjusted	$	215,110		$	388,546		$	477,528		$	681,840

RECONCILIATION OF EBITDA, AS ADJUSTED TO EBITDA, AS ADJUSTED
FOR NON-CASH AND OTHER CHARGES (2)

	Three Months Ended						Six Months Ended
	June 30,						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 on interest rate swap ineffectiveness		808			—			841			—
Unconsolidated investment impairment		18,542			—			18,542			—
Long-term service agreement cancellation charge		33,918			—			33,918			—
Write-off of deferred financing costs (not related to bonds repurchased)		5,887			19,376			5,887			19,376
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

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SUPPLEMENTARY POWER DATA

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
Generation (in MWh, in thousands) (3)		20,042		20,066		40,078		38,710
Average electric price realized (per MWh)	$	69.69	$	64.32	$	68.40	$	62.74
Average spark spread adjusted for benefits of equity gas production (per MWh)	$	22.57	$	20.62	$	22.61	$	19.67

CALPINE CONTRACTUAL PORTFOLIO – AS OF JUNE 30, 2005

	Jul - Dec
	2005			2006			2007			2008			2009
Estimated Generation Capacity (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 (in millions)	$	839		$	1,490		$	1,228		$	1,332		$	1,355

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	As of			As of
CAPITALIZATION	June 30, 2005			December 31, 2004
Cash and cash equivalents (in billions)	$	0.6		$	0.7
Total debt (in billions)	$	18.7		$	18.0
Debt to capitalization ratio		81	%		78	%
Present value of operating leases (in billions)	$	1.2		$	1.3
Unconsolidated debt of equity and cost method investments (estimated, in billions)	$	0.2		$	0.1
($ in thousands):
Short-term debt
Notes payable and borrowings under lines of credit, current portion	$	209,184		$	204,775
Convertible debentures payable to Calpine Capital Trust III		517,500			—
Preferred interests, current portion		268,819			8,641
Capital lease obligation, current portion		5,918			5,490
CCFC I financing, current portion		3,208			3,208
Construction/project financing, current portion		104,932			93,393
Senior notes and term loans, current portion		1,069,975			718,449
Total short-term debt		2,179,536			1,033,956
Long-term debt
Notes payable and borrowings under lines of credit, net of current portion		673,312			769,490
Convertible debentures payable to Calpine Capital Trust III		—			517,500
Preferred interests, net of current portion		648,246			497,896
Capital lease obligation, net of current portion		281,940			283,429
CCFC I financing, net of current portion		782,423			783,542
CalGen/CCFC II financing		2,396,257			2,395,332
Construction/project financing, net of current portion		2,283,200			1,905,658
Convertible Senior Notes Due 2006		1,311			1,326
Convertible Notes Due 2014		546,122			620,197
Convertible Notes Due 2015		650,000			—
Convertible Senior Notes Due 2023		633,775			633,775
Senior notes, net of current portion		7,584,897			8,532,664
Total long-term debt		16,481,483			16,940,809
Total debt	$	18,661,019		$	17,974,765
Minority interests		384,401			393,445
Total stockholders’ equity		4,062,974			4,587,673
Total capitalization	$	23,108,394		$	22,955,883
Debt to capitalization ratio
Total debt	$	18,661,019		$	17,974,765
Total capitalization	$	23,108,394		$	22,955,883
Debt to capitalization		81	%		78	%

(1)	This non-GAAP measure is presented not as a measure of operating results, but rather as a measure of our ability to service debt and to raise additional funds. It should not be construed as an alternative to either (i) income from operations or (ii) cash flows from operating activities. It is defined as net income less income from unconsolidated investments, plus cash received from unconsolidated investments, plus interest expense (including one-third of operating lease expense, which is management’s estimate of the component of operating lease expense that constitutes interest expense), plus provision for tax, plus DD&A. The interest, tax, DD&A and income from unconsolidated investments components of discontinued operations are added back in calculating EBITDA, as adjusted.
(2)	This non-GAAP measure is presented as a further refinement of EBITDA, as adjusted, to reflect the company’s ability to service debt with cash.
(3)	Does not include MWh generated by unconsolidated investments in power projects.

# # #

EX-99.2

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 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 Lake View California Geothermal 50.0 50.0 100.0% 50.0 50.0 Jan-82 / May-99 Greenleaf 2 Power Plant California Natural Gas 49.5 49.5 100.0% 49.5 49.5 Dec-89 / Apr-95 Greenleaf 1 Power Plant California Natural Gas 49.5 49.5 100.0% 49.5 49.5 Mar-89 / Apr-95 Wolfskill Energy Center California Natural Gas - 48.0 100.0% - 48.0 Mar-03 Yuba City Energy Center California Natural Gas - 47.0 100.0% - 47.0 Jul-02 Feather River Energy Center California Natural Gas - 47.0 100.0% - 47.0 Dec-02 Lambie Energy Center California Natural Gas - 47.0 100.0% - 47.0 Jan-03 Goose Haven Energy Center California Natural Gas - 47.0 100.0% - 47.0 Jan-03 Creed Energy Center California Natural Gas - 47.0 100.0% - 47.0 Jan-03 Riverview Energy Center California Natural Gas - 47.0 100.0% - 47.0 May-03 King City Energy Center California Natural Gas - 45.0 100.0% - 45.0 Feb-02 Grant California Geothermal 40.0 40.0 100.0% 40.0 40.0 Oct-85 / May-99 Sonoma California Geothermal 35.0 35.0 100.0% 35.0 35.0 Oct-83 / Jul-98 Watsonville Power Plant California Natural Gas 29.0 30.0 100.0% 29.0 30.0 May-90 / Jun-95 Agnews Power Plant California Natural Gas 28.0 28.0 100.0% 28.0 28.0 Apr-90 West Ford Flat California Geothermal 26.0 26.0 100.0% 26.0 26.0 Mar-88 / Jul-90 Aidlin California Geothermal 16.0 16.0 100.0% 16.0 16.0 May-89 / 5% '89, 50% Aug-89, 45% Sep-00 Bear Canyon California Geothermal 16.0 16.0 100.0% 16.0 16.0 Sep-88 / Jul-90 Fumarole #9 & #10 (cold stand-by) California Geothermal - - 100.0% - - Jul-73 / May-99 Total WECC 6,595.0 8,143.0 6,265.3 7,767.8 TOTAL OPERATING ASSETS 22,912.9 28,244.9 21,795.7 27,019.3 Operated by Whitby Cogen Limited Partnership

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