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): May 5, 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 May 5, 2005, the Registrant issued the press release attached hereto as Exhibit 99.1 reporting financial and operating results for the quarter ended March 31, 2005. The registrant also attaches Exhibit 99.2 hereto the materials presented in connection with the registrant’s May 5, 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: May 6, 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: Rick Barraza, Ext. 1125
Karen Bunton, Ext. 1121
Lisa Poelle, Ext. 1285

CALPINE REPORTS FIRST QUARTER 2005
FINANCIAL AND OPERATING RESULTS

     (SAN JOSE, CALIF.) /PR NEWSWIRE-First Call/ May 5, 2005 — Calpine Corporation [NYSE:CPN] reported financial and operating results for the three months ended March 31, 2005. A conference call, set for 8:30 a.m. PDT today, will be accompanied by a comprehensive presentation of the first quarter results. The presentation will be posted on Calpine’s investor relations page at www.calpine.com prior to the conference call.

	First Quarter
	(unaudited)
	2005			2004			% Chg
Megawatt-hours Generated (millions)(a)		22.4			21.1			6	%
Megawatts in Operation at March 31		26,649			23,179			15	%
Revenue (millions)	$	2,212.7		$	2,032.3			9	%
Net (Loss) (millions)	$	(168.7	)	$	(71.2	)		(137	)%
Basic and Diluted (Loss) Per Share	$	(0.38	)	$	(0.17	)		(124	)%
Operating Cash Flow (millions)	$	(114.6	)	$	(173.2	)		34	%
EBITDA, as adjusted (millions) (b)	$	262.4		$	293.3			(11	)%
EBITDA, as adjusted, for non-cash and other charges (millions) (c)	$	244.6		$	303.0			(19	)%
Total Assets (billions)	$	27.6		$	27.4			0.7	%

(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.

     Pete Cartwright, Calpine president and chief executive officer, stated, “Traditionally, we experience seasonably low revenue and spark spread during the first quarter. And, while Calpine operated at a loss for the quarter, results were in-line with our expectations and we remain on target for our year-end financial results.

     “Let’s begin with where we were for the quarter. Calpine’s total spark spread and power production increased over 2004 levels; however, financial results continued to be impacted by higher operating and interest expense associated with new plants coming on line. As a result, Calpine recorded a net loss per share of $0.38.

CALPINE REPORTS FIRST QUARTER 2005 FINANCIAL AND OPERATING RESULTS
Page 2
May 5, 2005

     “Nearer-term, market conditions continue to improve, and Calpine is pursuing opportunities to further leverage our operating fleet, especially in California and Texas where forward pricing for the summer is strong. And we remain on track to complete our previously announced programs of raising nearly $900 million of liquidity-enhancing transactions and repurchasing over $1 billion of corporate debt.”

2005 First Quarter Financial Results

     For the three months ended March 31, 2005, Calpine reported revenue of $2.2 billion, representing an increase of 9% over the same period in the prior year, and a net loss per share of $0.38, or a net loss of $168.7 million, compared to a net loss per share of $0.17, or a net loss of $71.2 million, for the same quarter in the prior year.

     For the three months ended March 31, 2005, Calpine’s average capacity in operation for consolidated projects increased by 21% to 26,368 megawatts. The company generated approximately 22.4 million megawatt-hours, which equated to a baseload capacity factor of 44%, and realized an average spark spread of $24.10 per megawatt-hour. For the same period in 2004, Calpine generated 21.1 million megawatt-hours, which equated to a capacity factor of 50%, and realized an average spark spread of $20.65 per megawatt-hour.

     Gross profit increased by $28.5 million, or 25%, to $140.6 million in the three months ended March 31, 2005, over the same period in the prior year. Despite improvements in market fundamentals, total spark spread—which increased by $104.2 million, or 24%, in the first quarter of 2005, compared to the same period in 2004—did not increase commensurately with the increases in plant operating expense, transmission purchase expense, depreciation, and interest expense associated with new power plants coming on line. In the first quarter of 2005, gross profit was reduced by transaction fees of $17.3 million associated with prepaid commodity transactions at Calpine’s Deer Park Energy Center.

     During the three months ended March 31, 2005, financial results were affected by a $100.5 million increase in interest expense, as compared to the same period in 2004. This occurred as a result of higher average interest rates and lower capitalization of interest expense as new plants entered commercial operation. During the quarter, the company recorded a $21.8 million gain from the repurchase of debt.

     Other expense was $4.0 million for the three months ended March 31, 2005, compared to other income of $18.4 million for the three months ended March 31, 2004. The difference includes a $4.7 million decrease in foreign currency transaction gain between periods and, in addition, in 2004 Calpine recorded non-recurring gains on the sale of a variety of oil and gas properties to the Calpine Natural Gas Trust of $6.2 million and a favorable warranty settlement in the amount of $5.1 million.

     In the first quarter of 2004, Calpine recognized $36.0 million of income from discontinued operations, net of tax primarily resulting from the gain from the sale of the Lost Pines 1 Power Project. There was no corresponding income from discontinued operations in the first quarter of 2005 and no assets held for sale as of March 31, 2005.

- more -

CALPINE REPORTS FIRST QUARTER 2005 FINANCIAL AND OPERATING RESULTS
Page 3
May 5, 2005

Liquidity and Financing Highlights

     During the quarter, as part of its 2005 liquidity program, Calpine:

•   Completed a $503 million, non-recourse project finance facility to complete construction of its 375-megawatt Mankato and 250-megawatt Freeport power plants. Upon closing, Calpine received approximately $97 million for construction costs spent to date on the two projects. The remaining amount available under the facility will be used to fund completion of the projects; and

•   Entered into a 650-megawatt, six-year power sales agreement with Merrill Lynch Commodities, Inc. As part of the transaction, Calpine’s Deer Park Energy Center received an upfront payment, net of fees, of approximately $195 million for future power deliveries, and expects to receive approximately $70 million in additional up-front payments over the next several months.

     Calpine ended the quarter with cash and cash equivalents on hand of approximately $800 million. In addition to this amount, the company’s current portion of restricted cash totaled approximately $500 million.

     During the first quarter, Calpine repurchased $80.6 million of the principal amount of its outstanding debt as listed below:

-	8 5/8% Senior Notes Due 2010	$	48,725,000
-	8 1/2% Senior Notes Due 2011	$	31,843,000

     The securities were repurchased in exchange for $58.1 million in cash. After the write-off of deferred financing costs and unamortized discounts on the notes, Calpine recorded a pre-tax gain on the repurchase of debt totaling $21.8 million.

     Subsequent to March 31, 2005, Calpine has repurchased $94.3 million of the principal amount of its outstanding debt as listed below:

-	10 1/2% Senior Notes Due 2006	$	3,485,000
-	7 5/8% Senior Notes Due 2006	$	1,335,000
-	8 3/4% Senior Notes Due 2007	$	3,000,000
-	7 3/4% Senior Notes Due 2009	$	26,000,000
-	8 5/8% Senior Notes Due 2010	$	29,468,000
-	8 1/2% Senior Notes Due 2011	$	31,000,000

     The securities were repurchased in exchange for approximately $56.1 million in cash. After the write-off of deferred financing costs and unamortized discounts on the notes, Calpine recorded a pre-tax gain on the repurchase of debt totaling approximately $37 million, which will be reflected in the second quarter financial results.

- more -

CALPINE REPORTS FIRST QUARTER 2005 FINANCIAL AND OPERATING RESULTS
Page 4
May 5, 2005

Additional Opportunities

     In addition to its liquidity-enhancing transactions and debt repurchases described above, Calpine is moving forward on a number of opportunities that it expects will provide additional liquidity and reduce debt. These transactions include:

•   A $130 million project financing of Calpine’s 80-megawatt Bethpage power plant, which is projected to close by May 31. This financing will provide for $10 million of letters of credit and will provide approximately $60 million to Calpine for construction costs spent to date on this plant. The balance will be used to complete construction of Bethpage, currently scheduled for commercial operation in July; and

•   The potential sale of the company’s 1,200-megawatt Saltend Energy Centre. Final bids are expected on May 6. While the company has not made a final decision to sell Saltend, if the bids meet Calpine’s expectations, the company expects the sale to be completed by July 31, 2005. Proceeds from the potential sale would be used to repay the two outstanding preferred securities totaling $620 million, with the balance of the proceeds to be used to repurchase debt.

Operations Update

     Calpine continues to improve power plant efficiencies and lower operating costs. During the first quarter, Calpine:

•   Decreased its average baseload heat rate to 7,091 million British thermal units per kilowatt-hour for the year, compared to 7,115 in 2004;

•   Reduced total plant operating expense (based on a trailing 12-month period at an assumed 70% capacity factor) to $5.15 per megawatt-hour from $5.24 per megawatt-hour in 2004;

•   Operated its natural gas-fired and geothermal power plants with an average availability of 90%, compared to 92% in 2004;

•   Was awarded three patents from the U.S. Patents and Trademark Office to Power Systems Manufacturing (PSM), Calpine’s turbine parts manufacturing subsidiary, bringing PSM’s total patents held to 35; and

•   Continued to reduce its fleetwide emissions and improve operating efficiencies with the installation of two newly designed PSM combustion systems at Calpine’s Texas City 501D5 and the South Point 501F combined-cycle power plants. These systems will reduce nitrogen oxide and carbon monoxide emissions to single-digit levels without the need for selective catalytic reduction and will enhance fuel efficiencies.

- more -

CALPINE REPORTS FIRST QUARTER 2005 FINANCIAL AND OPERATING RESULTS
Page 5
May 5, 2005

New Market Opportunities

     For the quarter, Calpine signed one renegotiated and 23 new power contracts, representing more than 1,340 megawatts of capacity and approximately 4.0 million megawatt-hours. The weighted average on-peak spark spread for these contracts is approximately $16.50 per megawatt-hour, with a two-year weighted average life.

     Calpine recently announced:

•   A contract to provide 75 megawatts of transmission must-run services to the Alberta Electric System Operator to help provide voltage support to the transmission system in southern Alberta; and

•   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 first quarter 2005 financial and operating results on Thursday, May 5, 2005, at 8:30 a.m. PDT. To participate via the teleconference (in listen-only mode), dial 1-888-603-6685 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 web cast and presentation will be available for 30 days on Calpine’s investor relations page at www.calpine.com.

- more -

CALPINE REPORTS FIRST QUARTER 2005 FINANCIAL AND OPERATING RESULTS
Page 6
May 5, 2005

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, three Canadian provinces and the United Kingdom. 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.

     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 as, but 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; (iii) commercial operations of new plants that may be delayed or prevented because of various development and construction risks, such as a failure to obtain the necessary permits to operate, failure of third-party contractors to perform their contractual obligations or failure to obtain financing on acceptable terms; (iv) unscheduled outages of operating plants; (v) a competitor’s development of lower cost generating gas-fired power plants; (vi) risks associated with marketing and selling power from power plants in the newly-competitive energy market; (vii) the successful exploitation of an oil or gas resource that ultimately depends upon the geology of the resource, the total amount and costs to develop recoverable reserves and operations factors relating to the extraction of natural gas; (viii) the effects on the company’s business resulting from reduced liquidity in the trading and power industry; (ix) the company’s ability to access the capital markets or obtain bank financing on attractive terms; (x) the direct or indirect effects on the company’s business of a lowering of its credit rating (or actions it may take in response to changing credit rating criteria), including, increased collateral requirements, refusal by the company’s current or potential counterparties to enter into transactions with it and its inability to obtain credit or capital in desired amounts or on favorable terms; and (xi) other risks identified from time-to-time in the company’s reports and registration statements filed with the SEC, including the risk factors identified in its Annual Report on Form 10-K for the year ended Dec. 31, 2004, 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 duty to update this information.

- more -

CALPINE REPORTS FIRST QUARTER 2005 FINANCIAL AND OPERATING RESULTS
Page 7
May 5, 2005

CALPINE CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
For the Three Months Ended March 31, 2005 and 2004
(in thousands, except per share amounts)
(unaudited)

	Three Months Ended
	March 31,
	2005			2004
Revenue:
Electric generation and marketing revenue Electricity and steam revenue	$	1,403,549		$	1,245,887
Transmission sales revenue		3,744			5,675
Sales of purchased power for hedging and optimization		356,130			380,028
Total electric generation and marketing revenue		1,763,423			1,631,590
Oil and gas production and marketing revenue Oil and gas sales		10,820			14,135
Sales of purchased gas for hedging and optimization		420,296			352,737
Total oil and gas production and marketing revenue		431,116			366,872
Mark-to-market activities, net		(3,531	)		12,518
Other revenue		21,670			21,312
Total revenue		2,212,678			2,032,292
Cost of revenue:
Electric generation and marketing expense Plant operating expense		195,626			172,777
Transmission purchase expense		23,510			19,483
Royalty expense		10,329			5,882
Purchased power expense for hedging and optimization		288,787			374,939
Total electric generation and marketing expense		518,252			573,081
Oil and gas operating and marketing expense Oil and gas operating expense		13,000			13,236
Purchased gas expense for hedging and optimization		413,259			360,487
Total oil and gas operating and marketing expense		426,259			373,723
Fuel expense		921,349			789,749
Depreciation, depletion and amortization expense		143,228			129,407
Operating lease expense		24,777			27,799
Other cost of revenue		38,171			26,380
Total cost of revenue		2,072,036			1,920,139
Gross profit		140,642			112,153
(Income) loss from unconsolidated investments		(6,064	)		(1,185	)
Equipment cancellation and impairment cost		(73	)		2,360
Project development expense		8,720			7,717
Research and development expense		7,034			3,816
Sales, general and administrative expense		57,137			54,328
Income from operations		73,888			45,117
Interest expense		348,937			248,466
Interest (income)		(14,331	)		(12,060	)
Minority interest expense		10,614			8,435
(Income) from repurchase of various issuances of debt		(21,772	)		(835	)
Other expense (income), net		3,980			(18,425	)
Income (loss) before provision or benefit for income taxes		(253,540	)		(180,464	)
Provision (benefit) for income taxes		(84,809	)		(73,232	)
Income (loss) before discontinued operations		(168,731	)		(107,232	)

- table continues -

CALPINE REPORTS FIRST QUARTER 2005 FINANCIAL AND OPERATING RESULTS
Page 8
May 5, 2005

	Three Months Ended
	March 31,
	2005			2004
(in thousands, except per share amounts)	(Unaudited)
Discontinued operations, net of tax provision (benefit) of $— and $(392)		—			36,040
Net income (loss)	$	(168,731	)	$	(71,192	)
Basic and diluted earnings (loss) per common share:
Weighted average shares of common stock outstanding		447,599			415,308
Income (loss) before discontinued operations	$	(0.38	)	$	(0.26	)
Discontinued operations, net of tax	$	—		$	0.09
Net income (loss)	$	(0.38	)	$	(0.17	)

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 months ended March 31, 2005.

- table continues -

CALPINE REPORTS FIRST QUARTER 2005 FINANCIAL AND OPERATING RESULTS
Page 9
May 5, 2005

CALPINE CORPORATION AND SUBSIDIARIES
Supplemental Data
(unaudited)

CASH FLOW DATA

	Three Months Ended
	March 31,
	2005			2004
(in thousands)
Cash used in operating activities	$	(114,592	)	$	(173,230	)
Cash used in investing activities		(220,848	)		(71,371	)
Cash provided by (used in) financing activities		368,710			(160,091	)
Effect of exchange rate changes on cash and cash equivalents		(4,086	)		(4,310	)
Net increase (decrease) in cash and cash equivalents.	$	29,184		$	(409,002	)

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

	Three Months Ended
	March 31,
	2005			2004
(in thousands)
Cash used in operating activities	$	(114,592	)	$	(173,230	)
Less: Changes in operating assets and liabilities, excluding the effects of acquisitions		(82,826	)		(137,745	)
Less: Additional adjustments to reconcile net income to net cash used in operating activities, net		136,965			35,707
GAAP net income (loss)		(168,731	)		(71,192	)
(Income) loss from unconsolidated investments		(6,064	)		(1,185	)
Distributions from unconsolidated investments		4,872			5,140
Subtotal		(169,923	)		(67,237	)
Interest expense		348,937			248,466
1/3 of operating lease expense		8,259			9,266
Provision (benefit) for income taxes		(84,809	)		(73,232	)
Depreciation, depletion and amortization expense (“DD&A”)		159,954			151,396
Interest expense, provision (benefit) for income taxes, DD&A and income from unconsolidated investments from discontinued operations		—			24,633
EBITDA, as adjusted	$	262,418		$	293,292

- table continues -

CALPINE REPORTS FIRST QUARTER 2005 FINANCIAL AND OPERATING RESULTS
Page 10
May 5, 2005

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

	Three Months Ended
	March 31,
	2005			2004
(in thousands)
EBITDA, as adjusted	$	262,418		$	293,292
Equipment cancellation and impairment cost		(73	)		2,360
Foreign currency transaction (gain) loss		(5,240	)		(9,984	)
Unrealized mark-to-market activity (gain) loss		(8,838	)		4,945
(Income) from repurchase of various issuances of debt		(21,772	)		(835	)
SFAS No. 123 (stock-based compensation expense)		7,136			4,266
Minority interest expense		10,614			8,435
(Income) loss on interest rate swap ineffectiveness		33			398
Other non-cash and other charges		338			168
EBITDA, as adjusted, for non-cash and other charges	$	244,616		$	303,045

SUPPLEMENTARY POWER DATA

	Three Months Ended
	March 31,
	2005		2004
Generation (in MWh, in thousands) (3)		22,360		21,050
Average electric price realized (per MWh)	$	65.78	$	59.43
Average spark spread adjusted for benefits of equity gas production (per MWh)	$	24.10	$	20.65

SUPPLEMENTARY EQUIVALENT NATURAL GAS PRODUCTION DATA (4)

	Three Months Ended
	March 31,
	2005		2004
(in Bcfe)
Natural Gas Production
United States		8		11
Canada		—		—
Total		8		11
Average daily production rate (millions of cfe)		88		118
Average realized price per Mcfe	$	6.36	$	5.80
Average unit production cost per Mcfe (excluding interest expense)	$	1.45	$	0.91
Average unit DD&A cost per Mcfe (excluding impairment and interest expense)	$	1.92	$	1.76

- table continues -

CALPINE REPORTS FIRST QUARTER 2005 FINANCIAL AND OPERATING RESULTS
Page 11
May 5, 2005

CALPINE CONTRACTUAL PORTFOLIO – AS OF MARCH 31, 2005

	Apr - Dec
	2005			2006			2007			2008			2009
Estimated Generation Capacity
(in millions of MWh)
- Baseload		143.5			200.3			211.6			221.8			221.2
- Peaking		19.2			25.8			26.3			26.9			26.8
Total		162.7			226.1			237.9			248.7			248.0
Contractual Generation
(in millions of MWh)
- Baseload		80.0			78.1			60.0			58.0			55.2
- Peaking		14.9			18.9			18.7			18.0			15.0
Total		94.9			97.0			78.7			76.0			70.2
% Sold
- Baseload		56	%		39	%		28	%		26	%		25	%
- Peaking		78	%		73	%		71	%		67	%		56	%
Total		58	%		43	%		33	%		31	%		28	%
Contractual Spark Spread (in millions)	$	1,474		$	1,851		$	1,602		$	1,526		$	1,439

- table continues -

CALPINE REPORTS FIRST QUARTER 2005 FINANCIAL AND OPERATING RESULTS
Page 12
May 5, 2005

	As of			As of
CAPITALIZATION	March 31, 2005			December 31, 2004
Cash and cash equivalents (in billions)	$	0.8		$	0.8
Total debt (in billions)	$	18.1		$	18.0
Debt to capitalization ratio		79	%		78	%
Present value of operating leases (in billions)	$	1.2		$	1.3
Unconsolidated debt of equity and cost method investments (estimated, in billions) (5)	$	0.2		$	0.1
($ in thousands):
Short-term debt
Notes payable and borrowings under lines of credit, current portion	$	209,652		$	204,775
Preferred interests, current portion		268,794			8,641
Capital lease obligation, current portion		5,780			5,490
CCFC I financing, current portion		3,208			3,208
Construction/project financing, current portion		100,773			93,393
Senior notes and term loans, current portion		711,769			718,449
Total short-term debt		1,299,976			1,033,956
Long-term debt
Notes payable and borrowings under lines of credit, net of current portion		682,429			769,490
Notes payable to Calpine Capital Trust		517,500			517,500
Preferred interests, net of current portion		493,396			497,896
Capital lease obligation, net of current portion		281,756			283,429
CCFC I financing, net of current portion		782,020			783,542
CalGen/CCFC II financing		2,395,795			2,395,332
Construction/project financing, net of current portion		2,003,443			1,905,658
Convertible Senior Notes Due 2006		1,311			1,326
Convertible Senior Notes Due 2014		623,429			620,197
Convertible Senior Notes Due 2023		633,775			633,775
Senior notes, net of current portion		8,429,128			8,532,664
Total long-term debt		16,843,982			16,940,809
Total debt	$	18,143,958		$	17,974,765
Minority interests		388,499			393,445
Total stockholders’ equity		4,349,852			4,587,673
Total capitalization	$	22,882,309		$	22,955,883
Debt to capitalization ratio Total debt	$	18,143,958		$	17,974,765
Total capitalization	$	22,882,309		$	22,955,883
Debt to capitalization		79	%		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.
(4)	From continuing operations.
(5)	Amounts based on Calpine’s ownership percentage.

EX-99.2

Exhibit 99.2

CALPINE CORPORATION EARNINGS CONFERENCE CALL 1st QUARTER ENDED MARCH 31, 2005

CALPINE PARTICIPANTS PETE CARTWRIGHT Chairman, President and Chief Executive Officer BOB KELLY Executive Vice President and Chief Financial Officer PAUL POSOLI Executive Vice President 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, 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 Securities and Exchange Commission for the quarter ended March 31, 2005.

BUSINESS UPDATE Pete Cartwright Chairman, President and Chief Executive Officer

ADDRESSING RECENT MARKET ISSUES Unfounded Rumors False Claims of a Calpine Bankruptcy Recent Market Pressure Has Not Had an Impact on Calpine's Ability to Manage its Power and Gas Assets

1st QUARTER OVERVIEW Financial Results In-Line With Our Expectations Operating Performance On Target Completed Liquidity-Enhancing Transactions Focus on $1 Billion Plus De-Levering Program Positive Market Trends Continue

PROJECT PORTFOLIO UPDATE 93 Plants in Operation; 26,900 mw Construction Program Moving Forward on Eight Economic Projects 2,000 mw Entering Operation in 2005 Two Plants to Provide Needed Power to California Power Markets Pastoria - 750 mw Metcalf - 602 mw

AWARDED ONTARIO 1,005-mw 20-YEAR AGREEMENT Calpine/Mitsui Partnership Successful in Bid for New 1,005-mw Project Attractive 20-Year Power Sales Agreement Project to Utilize Three Gas Turbines and One Steam Turbine From Calpine's Existing Pool of Equipment Represents Calpine's Equity in Project 14 "F" Class Turbines Remaining to be Deployed

1st QUARTER 2005 FINANCIAL & OPERATING RESULTS Bob Kelly Executive Vice President and Chief Financial Officer

(In millions, except EPS) (In millions, except EPS) 1st Qtr. Ended Mar. 31, 2005 Revenue $ 2,212.7 GAAP Net Loss $ (168.7) GAAP Basic and Diluted Loss Per Share $ (0.38) Operating Cash Flow $ (114.6) EBITDA, as Adjusted for Non-Cash and Other Charges (1) $ 244.6 EBITDA, as Adjusted for Non-Cash and Other Charges to Interest Expense (2) 0.70x 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

GENERATION AND SPARK SPREADS 1st Quarter 1st Quarter 1st Quarter 2004 2005 Average mw in Operation 22,117 26,649 Mwh Generated (000s) 21,050 22,360 Mwh Delivered (000s) 32,885 33,774 Total Spark Spread (000s) $ 434,705 $ 538,879 Spark Spread (per mwh) $ 20.65 $ 24.10

POWER PLANT STATISTICS 1st Quarter 1st Quarter 1st Quarter 2004 2005 Plant Availability Factor 92.0% 90.0% Plant Baseload Capacity Factor 50.3% 43.8% Average Heat Rate (btu/kwh) 7,115 7,091 Total Plant Operating Expenses (000s) $ 172,777 $ 195,626 Plant Operating Expenses (per mwh) (1) $ 5.24 $ 5.15 (1) Total plant operating expenses include major maintenance expense and are calculated on a trailing 12-month basis at an assumed 70% capacity factor (1) Total plant operating expenses include major maintenance expense and are calculated on a trailing 12-month basis at an assumed 70% capacity factor (1) Total plant operating expenses include major maintenance expense and are calculated on a trailing 12-month basis at an assumed 70% capacity factor (1) Total plant operating expenses include major maintenance expense and are calculated on a trailing 12-month basis at an assumed 70% capacity factor

PLANT OPERATING EXPENSES Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Regular Operating Expense 5.39 5.22 5.03 4.96 4.81 4.71 4.51 4.56 4.5 Major Maintenance Expense 0.32 0.3 0.35 0.42 0.43 0.7 0.65 0.68 0.65 2003 2004 (per mwh) 2005 Trailing 12-Month Plant Operating Expenses at an Assumed 70% Capacity Factor $5.72 $5.15

UPDATE ON CASH Cash and Cash Equivalents Current Portion of Restricted Cash Calpine Energy Management Facility CalGen

TRANSACTIONS UPDATE Bethpage Project Financing Potential Sale of Saltend Energy Centre Other Asset Sales Contract Portfolio

UPCOMING FINANCING ACTIVITY Obligation to Repurchase Debt HIGH TIDES III 2007 Secured Debt 2008 Unsecured Debt

1st QUARTER 2005 POWER MARKETS UPDATE Paul Posoli Executive Vice President

MANAGING COLLATERAL REQUIREMENTS CES Total Collateral 12/31/04 $442.3 Million 3/31/05 $482.9 Million 4/30/05 $448.6 Million Fully Collateralized With Most Counterparties Focused on $150 Million Collateral Reduction by 9/30/05

POWER MARKETS UPDATE Spark Spreads Per mwh Generally Trending Up Note: Figures Represent Average On-Peak, Day-Ahead Spark Spreads at 7,000 btu/kwh Heat Rate Source: Company Data 1st Quarter 1st Quarter 1st Quarter 2004 2005 NP15 $ 7.71 $ 11.22 SP15 $ 11.57 $ 13.60 ERCOT (Houston) $ 5.39 $ 8.03 Southeast $ 1.33 $ 2.17 NEPOOL (Mass Hub) $ 18.77 $ 16.95

2006 FORWARD CURVES Calendar 2006 Forward Spark Spreads Per mwh Source: Company Data, Assumes a 7,000 btu/kwh Heat Rate 2006 On-Peak 2006 On-Peak 2006 On-Peak 2006 On-Peak 2006 On-Peak 2006 Off-Peak 2006 Off-Peak 2006 Off-Peak 2006 Off-Peak 2006 Off-Peak As of 9/30/04 As of 2/18/05 As of 4/27/05 As of 9/30/04 As of 2/18/05 As of 4/27/05 NP15 $ 18.03 $ 20.44 $ 21.96 $ 1.14 $ 4.44 $ 2.71 SP15 $ 21.11 $ 24.32 $ 25.83 $ 2.15 $ 5.57 $ 3.58 ERCOT (Houston) $ 13.47 $ 15.17 $ 17.49 $ (1.26) $ 0.47 $ (0.59) NEPOOL (Mass Hub) $ 16.30 $ 18.26 $ 18.32 $ 0.71 $ 1.32 $ 0.84 Southeast $ 7.78 $ 7.63 $ 9.79 $ (8.07) $ (9.25) $ (11.77)

QUESTION AND ANSWER SESSION

APPENDICES

APPENDIX A: GAAP NET INCOME TO EBITDA, AS ADJUSTED

APPENDIX A: EBITDA, AS ADJUSTED TO EBITDA, AS ADJUSTED FOR NON-CASH AND OTHER CHARGES

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 4/1-12/31 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 52.7 85.0 - - - - - 85.0 85.0 Gilroy Note 123.5 123.5 5.8 8.6 9.6 10.6 11.8 77.1 123.5 BPA Monetization 46.6 46.6 17.2 23.4 6.0 - - - 46.6 Calpine Commercial Trust 32.1 35.1 6.6 8.8 8.8 6.6 2.2 2.1 35.1 Miscellaneous 22.9 22.9 19.1 0.6 0.9 0.3 0.3 1.7 22.9 Notes Payable $ 892.1 $ 927.4 $ 122.7 $ 197.3 $ 153.5 $ 115.1 $ 118.0 $ 220.8 $ 927.4 Preferred Interests Auburndale Power Plant $ 78.5 $ 78.5 $ 0.4 $ 0.7 $ 1.5 $ 3.9 $ 6.4 $ 65.6 $ 78.5 Saltend Redeemable Preferred Shares - 1 360.0 360.0 - 360.0 - - - - 360.0 Saltend Redeemable Preferred Shares - 2 260.0 260.0 260.0 - - - - - 260.0 Gilroy Energy Center 63.7 63.7 3.9 8.8 7.5 8.3 9.8 25.4 63.7 Preferred Interests $ 762.2 $ 762.2 $ 264.3 $ 369.5 $ 9.0 $ 12.2 $ 16.2 $ 91.0 $ 762.2 Capital Lease Obligations Hidalgo Energy Center $ 101.4 $ 101.4 $ - $ 1.1 $ 1.3 $ 3.1 $ 3.2 $ 92.7 $ 101.4 King City Power Plant 95.4 95.4 1.2 1.2 1.5 1.4 2.0 88.1 95.4 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 1.1 1.1 0.6 0.3 0.2 - - - 1.1 Capital Lease Obligations $ 287.5 $ 296.3 $ 4.3 $ 6.8 $ 7.7 $ 9.9 $ 11.0 $ 256.6 $ 296.3 As of March 31, 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 4/1-12/31 2005 2006 2007 2008 2009 Thereafter Total CCFC I Term Loan Notes Due 2009 $ 376.4 $ 379.2 $ 1.9 $ 3.9 $ 3.9 $ 3.8 $ 365.7 $ - $ 379.2 Floating Rate Notes Due 2011 408.8 415.0 - - - - - 415.0 415.0 CCFC I $ 785.2 $ 794.2 $ 1.9 $ 3.9 $ 3.9 $ 3.8 $ 365.7 $ 415.0 $ 794.2 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 632.0 640.0 - - - 3.2 6.4 630.4 640.0 Term Loan Notes Due 2010 98.8 100.0 - - - 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 $ 2,395.8 $ 2,405.0 $ - $ - $ 4.2 $ 12.1 $ 829.8 $ 1,558.9 $ 2,405.0 Project Financing Gilroy Energy Center $ 242.2 $ 244.6 $ 19.5 $ 40.1 $ 34.6 $ 37.0 $ 37.7 $ 75.7 $ 244.6 Broad River Energy Center 275.1 275.1 9.9 12.1 14.2 16.6 12.6 209.7 275.1 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 172.9 172.9 6.4 9.9 10.6 10.7 10.9 124.4 172.9 Fox Energy Center 292.5 292.5 26.6 6.9 21.1 8.4 12.7 216.8 292.5 Otay Mesa Energy Center 7.0 7.0 - - - - - 7.0 7.0 Metcalf Energy Center 15.5 15.5 0.1 0.2 0.3 14.9 - - 15.5 Freeport Energy Center 54.7 54.7 - - 0.9 0.8 0.7 52.3 54.7 Mankato Power Plant 48.0 48.0 - - 0.7 0.7 0.6 46.0 48.0 Project Financing $ 2,104.2 $ 2,106.6 $ 67.5 $ 85.9 $ 105.3 $ 114.6 $ 104.3 $ 1,629.0 $ 2,106.6 As of March 31, 2005 (In millions)

APPENDIX B: OUTSTANDING DEBT & PRINCIPAL PAYMENT SCHEDULES (continued) As of March 31, 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 4/1-12/31 2005 2006 2007 2008 2009 Thereafter Total First Priority Senior Secured Notes 9.625% Senior Secured Notes Due 2014 $ 779.1 $ 785.0 $ - $ - $ - $ - $ - $ 785.0 $ 785.0 First Priority Senior Secured Notes $ 779.1 $ 785.0 $ - $ - $ - $ - $ - $ 785.0 $ 785.0 Second Priority Senior Secured Notes Term Loan B Notes Due 2007 $ 738.8 $ 738.8 $ 5.6 $ 7.5 $ 725.7 $ - $ - $ - $ 738.8 Floating Rate Notes Due 2007 492.5 492.5 3.8 5.0 483.7 - - - 492.5 8.5% Senior Notes Due 2010 1,150.0 1,150.0 - - - - - 1,150.0 1,150.0 9.875% Senior Notes Due 2011 393.4 400.0 - - - - - 400.0 400.0 8.75% Senior Notes Due 2013 900.0 900.0 - - - - - 900.0 900.0 Second Priority Senior Secured Notes $ 3,674.7 $ 3,681.3 $ 9.4 $ 12.5 $ 1,209.4 $ - $ - $ 2,450.0 $ 3,681.3 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 623.4 736.0 - - - - - 736.0 736.0 4.75% Convertible Senior Notes Due 2023 633.8 633.8 - - - - - 633.8 633.8 Convertible Unsecured Senior Notes $ 1,258.5 $ 1,371.1 $ - $ 1.3 $ - $ - $ - $ 1,369.8 $ 1,371.1

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 4/1-12/31 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 111.6 111.6 - 111.6 - - - - 111.6 10.5% Senior Notes Due 2006 152.7 152.7 - 152.7 - - - - 152.7 8.75% Senior Notes Due 2007 (Canadian) 163.9 164.3 - - 164.3 - - - 164.3 8.75% Senior Notes Due 2007 195.3 195.3 - - 195.3 - - - 195.3 7.875% Senior Notes Due 2008 227.1 227.3 - - - 227.3 - - 227.3 8.375% Senior Notes Due 2008 (Euro) 151.6 151.6 - - - 151.6 - - 151.6 8.5% Senior Notes Due 2008 1,581.6 1,582.4 - - - 1,582.4 - - 1,582.4 7.75% Senior Notes Due 2009 221.5 221.6 - - - - 221.6 - 221.6 8.625% Senior Notes Due 2010 448.3 448.6 - - - - - 448.6 448.6 8.5% Senior Notes Due 2011 1,020.7 1,056.8 - - - - - 1,056.8 1,056.8 8.875% Senior Notes Due 2011 (Sterling) 226.8 228.1 - - - - - 228.1 228.1 Unsecured Senior Notes $ 4,687.1 $ 4,726.4 $ 186.1 $ 264.3 $ 359.6 $ 1,961.3 $ 221.6 $ 1,733.5 $ 4,726.4 Notes Payable to Calpine Capital Trust High Tides III $ 517.5 $ 402.5 $ - $ - $ - $ - $ - $ 402.5 $ 402.5 Notes Payable to Calpine Capital Trust $ 517.5 $ 402.5 $ - $ - $ - $ - $ - $ 402.5 $ 402.5 Total Debt $ 18,143.9 $ 18,258.0 $ 656.2 $ 941.5 $ 1,852.6 $ 2,229.0 $ 1,666.6 $ 10,912.1 $ 18,258.0 Scheduled Principal Payments $ 210.1 $ 315.9 $ 283.6 $ 267.7 $ 256.9 Final Principal Payments 446.1 625.6 1,569.0 1,961.3 1,409.7 Total $ 656.2 $ 941.5 $ 1,852.6 $ 2,229.0 $ 1,666.6 APPENDIX B: OUTSTANDING DEBT & PRINCIPAL PAYMENT SCHEDULES (continued) As of March 31, 2005 (In millions)

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 392.0 392.0 78.5% 307.7 307.7 Jun-00 Total ERCOT 6,616.0 7,406.0 6,531.7 7,321.7 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 Grays Ferry Power Plant (1) Pennsylvania Natural Gas 166.0 175.0 50.0% 83.0 87.5 Jan-98 / 40% Dec-99, 10% 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 875.0 956.0 792.0 864.6 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 Morris Power Plant Illinois Natural Gas 137.0 156.0 100.0% 137.0 156.0 Nov-98 127.5 mw; Mar-00 50 mw / 86% Dec-99, 14% Mar-04 Total MAIN 655.0 1,732.0 655.0 1,732.0

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 (2) 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 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 199.0 254.0 199.0 254.0 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 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 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 Pastoria Energy Center, Phase I (CalGen) California Natural Gas 250.0 250.0 100% 250.0 250.0 May-05 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 5,541.0 7,043.0 5,211.3 6,667.8 UNITED KINGDOM Saltend Energy Centre United Kingdom Natural Gas 1,200.0 1,200.0 100.0% 1,200.0 1,200.0 Nov-00 / Aug-01 Total United Kingdom 1,200.0 1,200.0 1,200.0 1,200.0 TOTAL OPERATING ASSETS 22,930.0 28,189.0 21,752.5 26,898.6 Operated by Trigen 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 Sep-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 1 Wisconsin Natural Gas 245.0 300.0 100.0% 245.0 300.0 Jun-05 Fox Energy Center, Phase 2 Wisconsin Natural Gas 245.0 260.0 100.0% 245.0 260.0 Dec-05 Total MAIN 490.0 560.0 490.0 560.0 NYPOOL Bethpage Energy Center 3 New York Natural Gas 79.9 79.9 100.0% 79.9 79.9 Jul-05 Total NYPOOL 79.9 79.9 79.9 79.9 SERC Hillabee Energy Center Alabama Natural Gas 710.0 770.0 100.0% 710.0 770.0 Jun-07 Washington Parish Energy Center Louisiana Natural Gas 509.0 565.0 100.0% 509.0 565.0 Jun-07 Total SERC 1,219.0 1,335.0 1,219.0 1,335.0 WECC Pastoria Energy Center, Phase II (CalGen) California Natural Gas 500.0 500.0 100.0% 500.0 500.0 Jun-05 Metcalf Energy Center California Natural Gas 556.0 602.0 100.0% 556.0 602.0 Jun-05 Otay Mesa Project California Natural Gas 510.0 593.0 100.0% 510.0 593.0 Nov-07 Total WECC 1,566.0 1,695.0 1,566.0 1,695.0 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 4,921.9 5,519.9 4,633.2 5,231.2

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 13.4% 700.0 2.2% ERCOT (Electric Reliability Council of Texas) ERCOT (Electric Reliability Council of Texas) ERCOT (Electric Reliability Council of Texas) 7,321.7 27.2% 250.0 4.8% 7,571.7 23.6% FRCC (Florida Reliability Coordinating Council) FRCC (Florida Reliability Coordinating Council) FRCC (Florida Reliability Coordinating Council) 875.0 3.3% - 0.0% 875.0 2.7% MAAC (Mid-Atlantic Area Council) MAAC (Mid-Atlantic Area Council) MAAC (Mid-Atlantic Area Council) 864.6 3.2% - 0.0% 864.6 2.7% MAPP (Mid-Continent Area Power Pool) MAPP (Mid-Continent Area Power Pool) MAPP (Mid-Continent Area Power Pool) - 0.0% 375.0 7.2% 375.0 1.2% MAIN (Mid-America Interconnected Network) MAIN (Mid-America Interconnected Network) MAIN (Mid-America Interconnected Network) 1,732.0 6.4% 560.0 10.7% 2,292.0 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 4.7% - 0.0% 1,272.0 4.0% 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) 254.0 0.9% 79.9 1.5% 333.9 1.0% SERC (Southeastern Electric Reliability Council) SERC (Southeastern Electric Reliability Council) SERC (Southeastern Electric Reliability Council) 5,030.0 18.7% 1,335.0 25.5% 6,365.0 19.8% SPP (Southwest Power Pool) SPP (Southwest Power Pool) SPP (Southwest Power Pool) 1,674.0 6.2% - 0.0% 1,674.0 5.2% WECC (Western Electricity Coordinating Council) WECC (Western Electricity Coordinating Council) WECC (Western Electricity Coordinating Council) 6,667.8 24.8% 1,695.0 32.4% 8,362.8 26.0% United Kingdom United Kingdom United Kingdom 1,200.0 4.5% - 0.0% 1,200.0 3.7% Mexico Mexico Mexico - 0.0% 236.3 4.5% 236.3 0.0% TOTAL CALPINE 26,898.6 100.0% 5,231.2 100.0% 32,129.7 100.0% # 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 22,180.0 27,439.0 21,002.5 26,148.6 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 10 4,921.9 5,519.9 4,633.2 5,231.2 Total Project Portfolio 103 27,851.9 33,708.9 26,385.7 32,129.8 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) 22,714.0 27,964.0 21,662.0 26,803.6

APPENDIX D: CONTRACTUAL PORTFOLIO SUMMARY 147 Contracts / 102 Customers Weighted Average Credit: BBB+ 7-Year Weighted Average Life

APPENDIX D: CONTRACTUAL PORTFOLIO CONTRACT TYPE 2005 2006 2007 2008 2009 Fixed Price 30% 25% 17% 16% 18% Heat Rate 68% 73% 77% 71% 69% Other 2% 2% 6% 13% 13%

APPENDIX D: CONTRACTUAL PORTFOLIO DEFINITIONS The following detailed reports represent several data points for Calpine's power generation portfolio as of March 31, 2005. 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 March 31, 2005 Contracts that have been announced and, or signed subsequent to March 31, 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 2005 2006 2007 2008 2009 Estimated Generation (In Millions of mwh) - Baseload 143.5 200.3 211.6 221.8 221.2 - Peaking 19.2 25.8 26.3 26.9 26.8 Total 162.7 226.1 237.9 248.7 248.0 Contractual Generation (In Millions of mwh) - Baseload 80.0 78.1 60.0 58.0 55.2 - Peaking 14.9 18.9 18.7 18.0 15.0 Total 94.9 97.0 78.7 76.0 70.2 % Sold - Baseload 56% 39% 28% 26% 25% - Peaking 78% 73% 71% 67% 56% Total 58% 43% 33% 31% 28% Contractual Spark Spread $1,474 $1,851 $1,602 $1,526 $1,439 (In Millions) Data as of 3/31/05 Apr-Dec

APPENDIX D: CONTRACTUAL PORTFOLIO WECC Estimated Generation (In Millions of mwh) - Baseload 37.4 53.0 53.7 57.5 57.3 - Peaking 5.1 6.8 6.8 6.9 6.9 Total 42.5 59.8 60.5 64.4 64.2 Contractual Generation (In Millions of mwh) - Baseload 25.7 30.1 24.1 24.2 23.4 - Peaking 3.9 4.2 4.1 4.1 4.1 Total 29.6 34.3 28.2 28.3 27.5 % Sold - Baseload 69% 57% 45% 42% 41% - Peaking 76% 62% 60% 59% 59% Total 70% 57% 47% 44% 43% 2005 2006 2007 2008 2009 Data as of 3/31/05 Apr-Dec

APPENDIX D: CONTRACTUAL PORTFOLIO ERCOT Estimated Generation (In Millions of mwh) - Baseload 41.3 56.3 56.5 56.7 56.5 - Peaking 1.6 2.2 2.2 2.2 2.2 Total 42.9 58.5 58.7 58.9 58.7 Contractual Generation (In Millions of mwh) - Baseload 28.8 25.5 14.3 13.9 13.8 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 28.8 25.5 14.3 13.9 13.8 % Sold - Baseload 70% 45% 25% 25% 24% - Peaking 0% 0% 0% 0% 0% Total 67% 44% 24% 24% 24% 2005 2006 2007 2008 2009 Data as of 3/31/05 Apr-Dec

APPENDIX D: CONTRACTUAL PORTFOLIO NORTHEAST Estimated Generation (In Millions of mwh) - Baseload 14.2 19.0 19.0 19.1 19.0 - Peaking 0.3 0.4 0.4 0.4 0.4 Total 14.5 19.4 19.4 19.5 19.4 Contractual Generation (In Millions of mwh) - Baseload 6.9 3.4 2.5 2.1 2.0 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 6.9 3.4 2.5 2.1 2.0 % Sold - Baseload 49% 18% 13% 11% 11% - Peaking 0% 0% 0% 0% 0% Total 48% 18% 13% 11% 10% 2005 2006 2007 2008 2009 Data as of 3/31/05 Includes the Following NERC Regions: NEPOOL, NYPOOL, MAAC, NPCC Apr-Dec

APPENDIX D: CONTRACTUAL PORTFOLIO SOUTHEAST Estimated Generation (In Millions of mwh) - Baseload 19.7 26.2 29.6 32.2 32.1 - Peaking 6.4 8.5 8.6 8.7 8.6 Total 26.1 34.7 38.2 40.9 40.7 Contractual Generation (In Millions of mwh) - Baseload 7.0 9.8 8.3 7.2 5.4 - Peaking 5.0 6.6 6.6 6.6 6.6 Total 12.0 16.4 14.9 13.8 12.0 % Sold - Baseload 36% 37% 28% 22% 17% - Peaking 78% 78% 77% 76% 77% Total 46% 47% 39% 34% 29% 2005 2006 2007 2008 2009 Data as of 3/31/05 Includes the Following NERC Regions: SERC, FRCC Apr-Dec

APPENDIX D: CONTRACTUAL PORTFOLIO MIDWEST Estimated Generation (In Millions of mwh) - Baseload 23.3 34.5 40.7 44.4 44.3 - Peaking 5.9 8.0 8.4 8.6 8.6 Total 29.2 42.5 49.1 53.0 52.9 Contractual Generation (In Millions of mwh) - Baseload 7.0 5.9 8.1 7.9 7.9 - Peaking 5.9 8.0 8.1 7.4 4.4 Total 12.9 13.9 16.2 15.3 12.3 % Sold - Baseload 30% 17% 20% 18% 18% - Peaking 100% 100% 96% 86% 51% Total 44% 33% 33% 29% 23% 2005 2006 2007 2008 2009 Data as of 3/31/05 Includes the Following NERC Regions/Sub-Region: MAPP, MAIN, ECAR, SPP and Entergy Apr-Dec

APPENDIX D: CONTRACTUAL PORTFOLIO UNITED KINGDOM Estimated Generation (In Millions of mwh) - Baseload 7.5 10.0 10.0 10.0 10.0 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 7.5 10.0 10.0 10.0 10.0 Contractual Generation (In Millions of mwh) - Baseload 4.6 2.2 0.7 0.7 0.7 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 4.6 2.2 0.7 0.7 0.7 % Sold - Baseload 61% 22% 7% 7% 7% - Peaking 0% 0% 0% 0% 0% Total 61% 22% 7% 7% 7% 2005 2006 2007 2008 2009 Data as of 3/31/05 Includes the Saltend Energy Centre Apr-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 3/31/05 Includes the Valladolid III Project Apr-Dec

CALPINE(r)