Calpine (CPNLQ) 8-K Calpine Reports 2004 Financial and Operating Results

EXHIBIT 99.1

CONTACTS: 408-995-5115

Media Relations: Bill Highlander, Ext. 1244

Investor Relations: Rick Barraza, Ext. 1125

CALPINE REPORTS 2004 FINANCIAL AND OPERATING RESULTS

     (SAN JOSE, CALIF.) /PR NEWSWIRE-First Call/ Feb. 24, 2005 – Calpine Corporation [NYSE:CPN] reported financial and operating results for the three and twelve months ended Dec. 31, 2004. A conference call, set for 8:30 a.m. PST today, will be accompanied by a comprehensive presentation of the 2004 results and 2005 guidance. The presentation will be posted on Calpine’s investor relations page atwww.calpine.com prior to the conference call.

	Fourth Quarter								Year-End
	(unaudited)								(unaudited)
	2004			2003		% Chg			2004			2003		% Chg
Megawatt-hours Generated (millions)(a)		24.0			20.4		18	%		96.5			82.4		17	%
Megawatts in Operation at Dec. 31		26,560			22,130		20	%		26,560			22,130		20	%
Revenue (millions)	$	2,336.2		$	1,909.6		22	%	$	9,229.9		$	8,871.0		4	%
Net Income (Loss) (millions)	$	(172.8	)	$	119.6		(245	)%	$	(221.2	)	$	282.0		(178	)%
Diluted Earnings (Loss) Per Share	$	(0.39	)	$	0.29		(234	)%	$	(0.51	)	$	0.71		(172	)%
Operating Cash Flow (millions)	$	(220.0	)	$	119.2		(285	)%	$	9.9		$	290.6		(97	)%
EBITDA, as adjusted (millions)(b)	$	255.4		$	545.1		(53	)%	$	1,653.9		$	1,799.3		(8	)%
EBITDA, as adjusted, for non-cash and other charges (millions)(c)	$	232.2		$	422.9		(45	)%	$	1,630.4		$	1,577.1		3	%
Total Assets (billions)	$	27		$	27		—	%	$	27		$	27		—	%

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

     For the quarter ended Dec. 31, 2004, the company reported a loss per share of $0.39, or a net loss of $172.8 million, compared to earnings per share of $0.29, or net income of $119.6 million for the quarter ended Dec. 31, 2003.

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	Fourth Quarter
	(unaudited)
	2004			2003
GAAP fully diluted earnings (loss) per share (EPS)	$	(0.39	)	$	0.29
Significant items included in GAAP EPS:
Impairment charges on proved natural gas reserves	$	(0.29	)	$	—
Equipment failure costs		(0.06	)		—
Equipment and service agreement cancellation		(0.05	)		(0.09	)
Foreign currency transaction gain (loss)		(0.03	)		(0.01	)
DIG C-20(1) accounting change		(0.01	)		0.39
Income from the sale of natural gas assets		—			0.09
Income from the termination of power purchase agreement		—			0.08
Unrealized mark-to-market activity gain (loss)		0.03			(0.05	)
Income on the repurchase of various issuances of existing debt		0.10			0.09
Repatriation tax charge partially reversed in Q4 2004		0.15			—

     For the twelve months ended Dec. 31, 2004, the company reported a loss per share of $0.51, or a net loss of $221.2 million, compared to earnings per share of $0.71, or net income of $282.0 million, for the year ended Dec. 31, 2003. The year-end results include a correction to the tax provision within discontinued operations previously recorded in the consolidated statements of operations for the three and nine months ended Sept. 30, 2004. The company will restate earnings for the three and nine months ended Sept. 30, 2004 to make the correction, which will lower the effective tax rate on discontinued operations and improve net results by approximately $36.5 million, or $0.09 per share, for the nine months ended Sept. 30, 2004.

     Pete Cartwright, Calpine president and chief executive officer, stated, “Despite ongoing business challenges, Calpine enhanced the value of the enterprise through successful financing activities, advancement of our business strategy and the strengthening of our commercial operations. During the year, we completed $2.1 billion of liquidity-enhancing transactions, repurchased or refinanced approximately $1.8 billion of corporate debt, redeemed in full our HIGH TIDES I and II preferred securities and refinanced $2.4 billion of maturing project debt. Calpine also increased power production by 17% and improved plant efficiencies.

     “Earnings were disappointing for the year,” continued Cartwright. “Although we continued to see improvements in spark spreads, the margins for our product remained low in certain markets and were offset by increased operating costs, depreciation and interest expense associated with additional capacity coming into service. And while our gas portfolio remains strong, we recorded a non-cash impairment charge associated with certain oil and gas fields in South Texas and Offshore Louisiana. Also, during the quarter, earnings were impacted by equipment failures on some of Calpine’s gas and steam turbines.

(1) Derivatives Implementation Group (“DIG”) Issue No. C-20,“Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature”

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     “I expect Calpine will continue to face its share of challenges in 2005, but I am confident that we will successfully execute our programs to further enhance liquidity, reduce corporate debt and strengthen our core operations. Today, we are evaluating the potential sale of certain power plants, including our Saltend facility in the United Kingdom. We expect these opportunities, together with the completion of nearly $900 million of liquidity-enhancing transactions, will allow us to to repurchase more than $1 billion of corporate debt.

     “We will continue to focus on increasing the value of our contractual portfolio, Calpine Energy Services’ activities, and our power services and parts manufacturing businesses. Longer-term, Calpine will work to advance open, competitive markets and enhance value for our customers.”

Restatement of Third Quarter 2004 Results

     As indicated above, the company will restate earnings for the three and nine months ended Sept. 30, 2004 to make a correction to the tax provision within discontinued operations. The correction will lower the effective tax rate on discontinued operations and improve net results by approximately $36.5 million, or $0.09 per share, for the nine months ended Sept. 30, 2004. The company had provided for taxes on the discontinued operations income at statutory rates, rather than a lower effective rate, to reflect the benefits of permanent differences associated with tax laws versus GAAP accounting rules. See the schedule included inSupplemental Datafor further details of the impact. The company will also make reclassifications of the tax provision between continuing and discontinued operations for prior reporting periods, which will not change total net income in these prior periods. The company detected the error in the first quarter of 2005 and has made changes to its internal controls. The company intends to file an amended Form 10-Q for the period ended Sept. 30, 2004, on or prior to the date that it files its Form 10-K for the year ended Dec. 31, 2004, to restate the tax provision within discontinued operations for the affected periods and to amend its disclosure in Part I, Item 4 “Controls and Procedures” to report its conclusion that its controls over the recording of the tax provision at Sept. 30, 2004 were ineffective due to the error, which constituted a “material weakness” under Public Company Accounting Oversight Board standards. In accordance with Section 404 of the Sarbanes-Oxley Act, the company and its auditors continue to assess the overall controls environment and its effectiveness. As a result of the third quarter error, the company may conclude that, with respect to the recording of taxes within discontinued operations, its controls environment as of Dec. 31, 2004 was ineffective, and the company’s external auditors may issue an adverse opinion on the company’s controls environment as of Dec. 31, 2004 because of this issue. The auditors’ opinion on controls will be provided with the company’s year-end audited financial statements when they are completed and filed, which is expected to be on or before March 16, 2005.

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2004 Fourth Quarter and Year-End Financial Results

     For the three months ended Dec. 31, 2004, the company reported revenue of $2.3 billion, representing an increase of 22% over the same period in the prior year, and a net loss per share of $0.39, or a net loss of $172.8 million, compared to earnings per share of $0.29, or net income of $119.6 million for the same quarter in the prior year.

     For the three months ended Dec. 31, 2004, average capacity in operation increased by 23% to 26,435 megawatts. The company generated approximately 24.0 million megawatt-hours, which equated to a baseload capacity factor of 45.6%, and realized an average spark spread of $21.36 per megawatt-hour. For the same period in 2003, Calpine generated 20.4 million megawatt-hours, which equated to a capacity factor of 48.9%, and realized an average spark spread of $23.90 per megawatt-hour.

     Despite improvements in market fundamentals, total spark spread, which increased by $25.3 million, or 5%, in the fourth quarter of 2004 compared to the same period in 2003, 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.

     Calpine recorded an impairment charge of approximately $201.5 million for certain oil and gas reserves, most notably on South Texas properties, following the receipt of the independent engineer’s report for year-end 2004, which reduced proved reserves 6% below Calpine’s year-end projection before receiving the engineer’s report. Following the reduction in proved reserves and the non-cash impairment charge, Calpine’s estimated total proved reserves of 389 billion cubic feet equivalent (bcfe) will have an estimated value of approximately $912 million (based on the present value of estimated future cash flows discounted at 10% in accordance with SEC guidelines), compared to a carrying value of approximately $607 million.

     In addition, during the fourth quarter of 2004 Calpine recorded approximately $45.3 million for equipment failure costs and a charge of $28.6 million for the cancellation of heat recovery steam generator orders on two of its development projects. The company also recognized gains totaling $76.4 million on debt repurchases of $394.0 million.

     As a result of provisions inThe American Jobs Creation Act of 2004signed into law on Oct. 22, 2004, Calpine recorded a reduction of $66.9 million, or $0.15 per share, in tax expense in the fourth quarter of 2004 on repatriated funds, which is mostly netted within the discontinued operations gain. The company had recorded approximately $78.8 million of tax expense in the third quarter of 2004 related to the repatriation of net cash proceeds from Canada to the United States following the sale of oil and gas assets in Canada.

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2004 Twelve-Month Results

     For the twelve months ended Dec. 31, 2004, the company reported revenue of $9.2 billion, representing an increase of 4% over the same period in the prior year. For the twelve months ended Dec. 31, 2004, Calpine netted approximately $1.7 billion of sales of purchased power for hedging and optimization with purchased power expense, compared to $0.3 billion in the prior year (netting in 2003 occurred only in the fourth quarter). This was due to the adoption on Oct. 1, 2003, on a prospective basis, of new accounting rules related to presentation of non-trading derivative activity. Adjusted for the netting, total revenue would have grown by approximately 19% versus the reported 4% growth in revenue. For the twelve months ended Dec. 31, 2004, the company reported a loss per share of $0.51, or a net loss of $221.2 million, compared to earnings per share of $0.71, or net income of $282.0 million, for the same period in the prior year.

     For the twelve months ended Dec. 31, 2004, the company generated 96.5 million megawatt-hours, which equated to a baseload capacity factor of 49.8%, and realized an average spark spread of $21.24 per megawatt-hour. For the same period in 2003, Calpine generated 82.4 million megawatt-hours, which equated to a capacity factor of 53.2%, and realized an average spark spread of $23.90 per megawatt-hour.

     Gross profit decreased by $409.1 million, or 54%, to $355.1 million in the twelve months ended Dec. 31, 2004, over the same period in the prior year, primarily due to: i) $202.1 million of impairment charges for certain oil and gas reserves; ii) non-recurring other revenue of $67.3 million recognized in the twelve months ended Dec. 31, 2003 from the settlement of contract disputes with, and claims against, Enron Corp.; iii) the recording of approximately $54.3 million for equipment failure costs within plant operating expense in 2004, compared to $11.0 million in 2003; iv) the amortization of $29.0 million in the twelve months of 2004 of the DIG C-20 gain recorded in the fourth quarter of 2003 due to the cumulative effect of a change in accounting principle; and v) market fundamentals, which caused total spark spread, despite a total increase of $79.2 million, or 4%, to not increase commensurately with additional plant operating expense, transmission purchase expense and depreciation costs associated with new power plants coming on-line.

     During the twelve months ended Dec. 31, 2004, financial results were affected by a $387.9 million increase in interest expense and distributions on trust preferred securities, as compared to the same period in 2003. This occurred as a result of higher debt balances, higher average interest rates and lower capitalization of interest expense as new plants entered commercial operation. In addition, prior year results benefited from recording $52.8 million in income from unconsolidated investments in power projects, from the termination of a power purchase agreement by the Acadia joint venture.

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     Other income increased by $103.0 million to $149.1 million during the twelve months ended Dec. 31, 2004, as compared to the same period in 2003, primarily due to: i) pre-tax income in the amount of $171.5 million, net of transaction costs and the write-off of unamortized deferred financing costs, associated with the restructuring of power purchase agreements for the Newark and Parlin power plants and the sale of an entity holding a power purchase agreement; ii) a $16.4 million pre-tax gain from the restructuring of a long-term gas supply contract net of transaction costs; and iii) a $12.3 million pre-tax gain from the King City restructuring transaction related to the sale of the company’s debt securities that had served as collateral under the King City lease, net of transaction costs. In 2003, the company recorded a gain of $62.2 million on the sale of oil and gas properties and a gain of $57.0 million from a contract termination at the RockGen facility.

     In 2004, the company recorded a charge of $42.4 million for equipment cancellation costs, primarily related to cancellation of heat recovery steam generator orders on two of its development projects. In 2003, there were $64.4 million in equipment cancellation charges. Also, during the twelve months ended Dec. 31, 2004, foreign currency transaction losses were $25.1 million, compared to losses of $33.3 million in the corresponding period in 2003.

     The company also recognized gains totaling $246.9 million on repurchases of debt for the twelve months ended Dec. 31, 2004 compared to $278.6 million for the twelve months ended Dec. 31, 2003. Loss before discontinued operations and cumulative effect of a change in accounting principle was $418.0 million, or $0.97 per share, in 2004.

     Income from discontinued operations, net of tax increased by $181.9 million during the twelve months ended Dec. 31, 2004, as compared to the same period in 2003, as a result of the sale of its Canadian and certain U.S. oil and gas assets during the third quarter of 2004 and the sale of the company’s interest in the Lost Pines facility in the first quarter of 2004.

Liquidity and Finance Program Highlights

     Enhancing liquidity, reducing corporate debt and addressing near-term debt maturities continued to drive Calpine’s financing program in 2004. During the year, Calpine successfully enhanced its financial position through a significant number of transactions:

•   Refinanced Calpine Construction Finance Company II project debt through the issuance of $2.4 billion of Calpine Generating Company bonds and term loans;

•   Completed approximately $2.1 billion of liquidity transactions including the sale of its Canadian and certain U.S. natural gas reserves for $847.8 million;

•   Redeemed in full $598.5 million of HIGH TIDES I and II, and a portion of HIGH TIDES III, totaling $115.0 million; and

•   Repurchased approximately $1.8 billion of existing corporate debt, resulting in a net gain of $246.9 million after the write-off of unamortized discounts and deferred financing costs.

     A detailed listing of debt repurchased along with the current outstanding debt is included in the appendices to the conference call presentation.

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     During the past several months, Calpine:

•   Obtained a $100 million, non-recourse credit facility to complete construction of the Metcalf Energy Center in San Jose, Calif. This is the first single-asset, merchant project financing in California since the energy crisis;

•   Received funding on Calpine European Funding (Jersey) Limited’s $260 million offering of Redeemable Preferred Shares due on July 30, 2005. The net proceeds from this offering will ultimately be used as permitted by Calpine’s existing bond indentures;

•   Completed a $400 million, 25-year, non-recourse sale/leaseback transaction for the 560-megawatt Fox Energy Center under construction in Kaukauna, Wis.; and

•   Completed a $195 million, non-recourse project financing for construction of the 525-megawatt Valladolid III Energy Center in Valladolid, Mexico.

     Calpine ended the year with approximately $1.6 billion of cash and credit available upon meeting certain conditions. This included cash and cash equivalents on hand of approximately $0.8 billion, the current portion of restricted cash of approximately $0.6 billion and approximately $0.2 billion of borrowing capacity available under the company’s various credit facilities upon meeting certain conditions.

2004 Operations Update

     The company turned in another strong year of operations, adding more than 4,400 megawatts of power generation capacity, improving plant performance and reducing turbine inventory. Today, Calpine owns or leases 92 natural gas-fired and geothermal power plants. These efficient, reliable power plants can generate more than 26,560 megawatts of electricity for wholesale and retail customers. In 2004, Calpine:

•   Exceeded the industry average safety performance, with a 0.48 Lost Time Accident (LTA) rate for all Calpine employees – well below the Bureau of Labor Statistics LTA industry benchmark of 0.80;

•   Operated its natural gas-fired and geothermal power plants with an average availability of 92.6%, compared to 91.2% in 2003;

•   Generated a record 96.5 million megawatt-hours, representing a 17% increase over 2003 levels, and delivered 147.7 million megawatt-hours to load-serving and end-use customers;

•   Lowered Calpine’s average baseload heat rate to 7,120 million British thermal units per kilowatt-hour for the year, compared to 7,253 in 2003;

•   Benefited from productivity improvements and economies of scale, with regular plant operating expense (based on a trailing 12-month period at an assumed 70% capacity factor) declining to $4.56 per megawatt-hour from $4.96 per megawatt-hour in 2003;

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•   Decreased total plant operating expense, including major maintenance expense, (based on a trailing 12-month period at an assumed 70% capacity factor) to $5.24 per megawatt-hour from $5.38 per megawatt-hour in 2003;

•   Completed construction of five power plants, totaling more than 2,700 megawatts, and two expansion projects, representing an additional 930 megawatts of capacity;

•   Acquired the 570-megawatt Brazos Valley power plant in ERCOT under a tax-deferred exchange with the sale of the Lost Pines power plant;

•   Reduced the company’s F technology turbine inventory from 22 to 17, as units were placed into four projects currently under construction, all four of which have long-term power sales agreements; and

•   Produced 46 bcfe of proved natural gas reserves, representing approximately 7% of Calpine’s fuel consumption. Total proved reserves as of Dec. 31, 2004 were 389 bcfe.

New Power Contracts

     Throughout 2004, Calpine continued to enhance its portfolio of contracted generation with the addition of new power contracts. Today, the company is pursuing more than 22,000 megawatts of power sales opportunities throughout the North American market. As of Dec. 31, 2004, Calpine’s contractual portfolio included:

•   A total of 149 power sales contracts with an average life of approximately eight years. These represent power sales to 97 customers with an average credit rating of BBB+;

•   More than $1.9 billion of estimated spark spread to be generated from Calpine’s 2005 contracted power sales (55% of total 2005 generation capacity under contract); and

•   A backlog of more than 900 million megawatt-hours.

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     For the year, the company signed 90 new power contracts representing nearly 7,200 megawatts of capacity and approximately 315 million megawatt-hours. These sales increased the contractual backlog by nearly 200 million megawatt-hours. The weighted average on-peak spark spread for these contracts is approximately $17 per megawatt-hour, with an average life of approximately four years.

     During the fourth quarter of 2004, Calpine entered into 23 new power contracts representing nearly 1,500 megawatts of generation.

     Included in the attachedSupplemental Datato 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 atwww.calpine.com.

New Market Opportunities

     As market conditions have improved in several major U.S. power markets, so have Calpine’s commercial operations, including its power services and parts and manufacturing businesses. In 2004, Calpine:

•   Signed a letter of intent for the joint construction of the first North American power plant utilizing General Electric’s (GE) new H-System gas turbine technology at Calpine’s Inland Empire site in southern California. GE will purchase development rights and fund construction for a 775-megawatt combined-cycle plant. Calpine will provide program management services during construction, market electricity from the plant and, after an extended period of GE ownership and operation, ultimately purchase the plant;

•   Launched NewSouth Energy LLC (NSE). This new Atlanta, Ga.-based energy venture was created to better focus on wholesale power customers and energy markets in the Southeast. NSE will have access to Calpine’s 7,100-megawatt portfolio of efficient, gas-fired power plants in operation and under construction throughout the Southeast.

•   Entered into 20 new power services transactions of various lengths, a 25% increase over 2003, most recently entering into a three-year agreement to provide operations and maintenance services to two Indiana generation and transmission cooperatives;

•   Achieved a performance milestone for Power Systems Mfg., LLC’s (PSM’s) new 501F transition piece. Completed a successful first phase of inspection of its transition pieces at the Channel Energy Center after more than 8,000 hours of operation and 60 equivalent starts; and

•   Enhanced PSM’s competitive advantage. Calpine’s parts and manufacturing subsidiary was awarded 14 patents in 2004, bringing its total patents held to 31.

2005 Earnings Guidance

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     For the year ending Dec. 31, 2005, Calpine is expecting its GAAP loss per share to be in the range of ($0.80) – ($0.90). EBITDA, as adjusted for non-cash and other charges, is expected to be in the range of $1.6 – $1.7 billion.

     In addition, the company has outlined a comprehensive program for 2005 that includes the completion of identified liquidity transactions, the repurchase of more than $1 billion of corporate debt, credit enhancement for Calpine Energy Services, additional power sales contracts, reductions in plant operating costs, turbine deployment and the expansion of its services business. The impact from these transactions has not been included in the above guidance. Further details regarding the company’s 2005 outlook will be provided in today’s conference call and is included in the conference call presentation.

Conference Call Information

     Calpine will host a conference call to discuss its fourth quarter and year-end 2004 financial and operating results on Thursday, Feb. 24, 2005, at 8:30 a.m. PST. 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 atwww.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, 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, visithttp://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 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 onForm 10-K/A, amendment number 2, for the year ended Dec. 31, 2003 and in its Quarterly Report onForm 10-Q for the quarter ended Sept. 30, 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.

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CALPINE CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
For the Three and Twelve Months Ended Dec. 31, 2004 and 2003
(unaudited)

	Three Months Ended						Twelve Months Ended
	Dec. 31,						Dec. 31,
	2004			2003			2004			2003
				(In thousands, except
				per share amounts)
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue	$	1,453,059		$	1,117,203		$	5,683,063		$	4,680,397
Transmission sales revenue		5,851			2,109			20,003			15,347
Sales of purchased power for hedging and optimization		344,511			445,085			1,651,767			2,714,187
Total electric generation and marketing revenue		1,803,421			1,564,397			7,354,833			7,409,931
Oil and gas production and marketing revenue
Oil and gas sales		15,682			13,762			63,153			59,156
Sales of purchased gas for hedging and optimization		469,859			359,250			1,728,301			1,320,902
Total oil and gas production and marketing revenue		485,541			373,012			1,791,454			1,380,058
Mark-to-market activities, net		28,724			(37,698	)		13,532			(26,439	)
Other revenue		18,495			9,887			70,069			107,483
Total revenue		2,336,181			1,909,598			9,229,888			8,871,033
Cost of revenue:
Electric generation and marketing expense
Plant operating expense		220,144			166,926			795,975			663,045
Royalty expense		7,352			6,093			28,673			24,932
Transmission purchase expense		23,634			8,963			85,514			46,455
Purchased power expense for hedging and optimization		315,760			435,508			1,487,020			2,690,069
Total electric generation and marketing expense		566,890			617,490			2,397,182			3,424,501
Oil and gas operating and marketing expense
Oil and gas operating expense		13,979			21,811			56,843			75,453
Purchased gas expense for hedging and optimization		472,933			338,257			1,716,714			1,279,568
Total oil and gas operating and marketing expense		486,912			360,068			1,773,557			1,355,021
Fuel expense		947,538			630,334			3,731,108			2,665,620
Depreciation, depletion and amortization expense		153,794			131,256			574,200			504,383
Oil and gas impairment		201,475			2,931			202,120			2,931
Operating lease expense		25,319			27,772			105,886			112,070
Other cost of revenue		22,567			21,768			90,742			42,270
Total cost of revenue		2,404,495			1,791,619			8,874,795			8,106,796
Gross profit		(68,314	)		117,979			355,093			764,237
Loss (income) from unconsolidated investments in power projects and oil and gas properties		1,862			(7,220	)		13,525			(75,804	)
Equipment cancellation and impairment cost		32,186			44,443			42,374			64,384
Long-term service agreement cancellation charge		3,754			16,355			11,334			16,355
Project development expense		9,295			7,667			24,409			21,804
Research and development expense		5,474			2,921			18,396			10,630
Sales, general and administrative expense		68,357			73,631			239,347			216,470
Income from operations		(189,242	)		(19,818	)		5,708			510,398
Interest expense		325,445			223,068			1,140,802			706,307
Distributions on trust preferred securities		—			—			—			46,610
Interest income		(17,246	)		(11,937	)		(56,412	)		(39,716	)
Minority interest expense		11,586			17,149			34,735			27,330
Income from repurchase of various issuances of debt		(76,401	)		(64,611	)		(246,949	)		(278,612	)
Other expense (income)		27,997			(110,695	)		(149,093	)		(46,126	)
Income (loss) before provision (benefit) for income taxes		(460,623	)		(72,792	)		(717,375	)		94,605
Provision (benefit) for income taxes		(217,406	)		(3,438	)		(299,360	)		8,495
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle		(243,217	)		(69,354	)		(418,015	)		86,110

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	Three Months Ended						Twelve Months Ended
	Dec. 31,						Dec. 31,
	2004			2003			2004			2003
	(In thousands, except per share amounts)
	(Unaudited)
Discontinued operations, net of tax provision (benefit) of $(67,665), $(16,682), $51,618, and $(14,416)		70,408			8,561			196,843			14,969
Cumulative effect of a change in accounting principle, net of tax provision of $—, $110,463, $—and $110,913		—			180,414			—			180,943
Net income (loss)	$	(172,809	)	$	119,621		$	(221,172	)	$	282,022
Basic earnings (loss) per common share:
Weighted average shares of common stock outstanding		446,056			412,747			430,775			390,772
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle	$	(0.55	)	$	(0.17	)	$	(0.97	)	$	0.22
Discontinued operations, net of tax	$	0.16		$	0.02		$	0.46		$	0.04
Cumulative effect of a change in accounting principle, net of tax	$	—		$	0.44		$	—		$	0.46
Net income (loss)	$	(0.39	)	$	0.29		$	(0.51	)	$	0.72
Diluted earnings per common share:
Weighted average shares of common stock outstanding before dilutive effect of certain convertible securities		446,056			412,747			430,775			396,219
Income (loss) before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle	$	(0.55	)	$	(0.17	)	$	(0.97	)	$	0.21
Dilutive effect of certain convertible securities		—			—			—			—
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle		(0.55	)		(0.17	)		(0.97	)		0.21
Discontinued operations, net of tax		0.16			0.02			0.46			0.04
Cumulative effect of a change in accounting principle, net of tax		—			0.44			—			0.46
Net income (loss)	$	(0.39	)	$	0.29		$	(0.51	)	$	0.71

__________

The financial information presented above and in theSupplemental Datais subject to adjustment until the company files its Form 10-Q/A for the nine months ended Sept. 30, 2004 and its Form 10-K for the year ended Dec. 31, 2004 with the United States Securities and Exchange Commission.

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CALPINE CORPORATION AND SUBSIDIARIES
Supplemental Data
(unaudited)

CASH FLOW DATA

	Three Months Ended						Twelve Months Ended
	Dec. 31,						Dec. 31,
(in thousands)	2004			2003			2004			2003
Cash provided by (used by) operating activities	$	(219,975	)	$	119,227		$	9,895		$	290,559
Cash used in investing activities		(25,450	)		(678,784	)		(407,384	)		(2,515,365	)
Cash provided by (used by) financing activities		(466,598	)		577,497			167,105			2,623,986
Effect of exchange rate changes on cash and cash equivalents		7,629			4,194			22,006			13,140
Net increase (decrease) in cash and cash equivalents	$	(704,394	)	$	22,134		$	(208,378	)	$	412,320

RECONCILIATION OF GAAP CASH PROVIDED BY OPERATING ACTIVITIES TO
EBITDA, AS ADJUSTED (1)

	Three Months Ended						Twelve Months Ended
	Dec. 31,						Dec. 31,
(in thousands)	2004			2003			2004			2003
Cash provided by operating activities	$	(219,975	)	$	119,227		$	9,895		$	290,559
Less: Changes in operating assets and liabilities, excluding the effects of acquisitions		(137,730	)		28,206			(149,069	)		(609,840	)
Less: Additional adjustments to reconcile net income to net cash provided by operating activities, net		90,564			(28,600	)		380,136			618,377
GAAP net income (loss)		(172,809	)		119,621			(221,172	)		282,022
(Income) loss from unconsolidated investments in power projects and oil and gas properties		1,862			(7,220	)		13,525			(75,804	)
Distributions from unconsolidated investments in power projects and oil and gas properties		7,622			15,948			29,869			141,627
Subtotal		(163,325	)		128,349			(177,778	)		347,845
Interest expense		325,445			223,068			1,140,802			706,307
1/3 of operating lease expense		8,440			9,257			35,295			37,357
Distributions on trust preferred securities		—			—			—			46,610
Provision (benefit) for income taxes		(217,406	)		(3,438	)		(299,360	)		8,495
Depreciation, depletion and amortization expense		369,945			167,402			840,916			568,204
Interest expense, provision (benefit) for income taxes and depreciation, depletion and income from unconsolidated investments in power projects from discontinued operations		(67,665	)		20,416			114,009			84,489
EBITDA, as adjusted	$	255,434		$	545,054		$	1,653,884		$	1,799,307

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

	Three Months Ended						Twelve Months Ended
	Dec. 31,						Dec. 31,
(in thousands)	2004			2003			2004			2003
EBITDA, as adjusted	$	255,434		$	545,054		$	1,653,884		$	1,799,307
Equipment cancellation and impairment cost		32,186			44,443			42,374			64,384
(Gain) from cumulative effect of a change in accounting principle		—			(180,414	)		—			(180,943	)
Foreign currency transaction (gain) loss		21,029			(2,888	)		45,232			33,346
Unrealized mark-to-market activity (gain) loss		(22,895	)		31,851			34,726			50,773
Income from repurchases of various issuances of debt		(76,401	)		(64,611	)		(246,949	)		(278,612	)
Write-off of deferred financing costs (not related to bonds repurchased)		3,000			1,446			37,333			16,478
Long-term service agreement cancellation charge		3,754			16,355			11,334			16,355
SFAS No. 123 (stock-based compensation expense)		4,936			4,044			19,444			16,072
Minority interest expense		11,586			17,149			34,735			27,330
(Income) loss on interest rate swap ineffectiveness		(71	)		229			(1,492	)		974
Other non-cash and other charges		(335	)		10,225			(240	)		11,668
EBITDA, as adjusted, for non-cash and other charges	$	232,223		$	422,883		$	1,630,381		$	1,577,132

SUPPLEMENTARY POWER DATA

	Three Months Ended				Twelve Months Ended
	Dec. 31,				Dec. 31,
	2004		2003		2004		2003
Generation (in MWh, in thousands) (3)		23,967		20,355		96,489		82,423
Average electric price realized (per MWh)	$	61.83	$	55.36	$	60.61	$	57.08
Average spark spread adjusted for benefits of equity gas production (per MWh)	$	21.36	$	23.90	$	21.24	$	23.90

SUPPLEMENTARY EQUIVALENT NATURAL GAS PRODUCTION DATA (4)

	Three Months Ended				Twelve Months Ended
	Dec. 31,				Dec. 31,
(in Bcfe)	2004		2003		2004		2003
Natural Gas Production
United States		9.5		12.2		40.9		52.2
Canada		—		1.8		5.5		12.3
Total		9.5		14.0		46.4		64.5
Average daily production rate		104		152		127		177
Average realized price per Mcfe	$	6.23	$	4.78	$	5.50	$	5.21
Average unit production cost per Mcfe (excluding interest expense)	$	1.05	$	0.90	$	0.96	$	0.81
Average unit DD&A cost per Mcfe (excluding impairment and interest expense)	$	2.13	$	1.60	$	1.77	$	1.42

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CALPINE CONTRACTUAL PORTFOLIO – AS OF DEC. 31, 2004

	2005			2006			2007			2008			2009
Estimated Generation Capacity (in millions of MWh)
- Baseload		188.2			213.5			221.2			221.8			221.2
- Peaking		25.4			26.5			26.8			26.9			26.8
Total		213.6			240.0			248.0			248.7			248.0
Contractual Generation (in millions of MWh)
- Baseload		96.2			67.0			54.3			52.3			49.6
- Peaking		19.3			18.9			18.7			18.0			15.0
Total		115.5			85.9			73.0			70.3			64.6
% Sold
- Baseload		51	%		31	%		25	%		24	%		22	%
- Peaking		76	%		71	%		70	%		67	%		56	%
Total		54	%		36	%		29	%		28	%		26	%
Contractual Spark Spread (in millions)	$	1,912		$	1,818		$	1,516		$	1,464		$	1,373

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	As of			As of
CAPITALIZATION	Dec. 31, 2004			Dec. 31, 2003
Cash and cash equivalents (in billions)	$	0.8		$	1.0
Total debt (in billions)	$	18.0		$	17.7
Debt to capitalization ratio		78	%		78	%
Present value of operating leases (in billions)	$	1.3		$	1.3
Unconsolidated debt of equity method investments (estimated, in billions) (5)	$	0.1		$	0.1
(in thousands):
Short-term debt
Notes payable and borrowings under lines of credit, current portion	$	204,775		$	254,292
Preferred interests, current portion		8,641			11,220
Capital lease obligation, current portion		5,490			4,008
CCFC I financing, current portion		3,208			3,208
Construction/project financing, current portion		93,393			61,900
Senior notes and term loans, current portion		198,449			14,500
Total short-term debt		513,956			349,128
Long-term debt
Notes payable and borrowings under lines of credit, net of current portion		769,490			873,572
Notes payable to Calpine Capital Trusts, net of current portion		517,500			1,153,500
Preferred interests, net of current portion		497,896			232,412
Capital lease obligation, net of current portion		283,429			193,741
CCFC I financing, net of current portion		783,542			785,781
CalGen/CCFC II financing		2,395,332			2,200,358
Construction/project financing, net of current portion		1,905,658			1,209,505
Convertible Senior Notes Due 2014		620,197			—
Convertible Senior Notes Due 2006, net of current portion		1,326			660,059
Convertible Senior Notes Due 2023		633,775			650,000
Senior notes, net of current portion		9,052,664			9,369,253
Total long-term debt		17,460,809			17,328,181
Total debt	$	17,974,765		$	17,677,309
Minority interests	$	393,445		$	410,892
Total stockholders’ equity	$	4,531,976		$	4,621,253
Total capitalization	$	22,900,186		$	22,709,454
Debt to capitalization ratio
Total debt	$	17,974,765		$	17,677,309
Total capitalization	$	22,900,186		$	22,709,454
Debt to capitalization		78	%		78	%

IMPACT OF RESTATEMENT FOR NINE MONTHS ENDED SEPT. 30, 2004 RESULTS

	Nine Months Ended
(In thousands except for earnings per share)	Sept. 30, 2004
Reported net income for September 2004	$	(84,871	)
Weighted average common shares outstanding		425,682
Reported earnings per share	$	(0.20	)
Reported discontinued operations, net of tax	$	89,927
Correction to discontinued operations tax expense		36,507
Corrected discontinued operations, net of tax	$	126,434
Corrected net income for YTD September 2004	$	(48,364	)
Corrected earnings per share	$	(0.11	)

(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 provision for tax, plus interest expense (including distributions on trust preferred securities and one-third of operating lease expense, which is management’s estimate of the component of operating lease expense that constitutes interest expense), plus depreciation, depletion and amortization. The interest, tax and depreciation and amortization 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.

CALPINE CORPORATION EARNINGS CONFERENCE CALL 4th QUARTER AND YEAR ENDED DECEMBER 31, 2004

CALPINE PARTICIPANTS PETE CARTWRIGHT Chairman, President and Chief Executive Officer BOB KELLY Executive Vice President and Chief Financial Officer PAUL POSOLI Senior Vice President, Calpine Energy Services 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/A, amendment number 2, for the year ended December 31, 2003 and our Quarterly Report on Form 10-Q for the quarter ended September 30, 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 Annual Report on Form 10-K with the Securities and Exchange Commission for the year ended December 31, 2004.

2004 BUSINESS UPDATE Pete Cartwright Chairman, President and Chief Executive Officer

2004 BUSINESS UPDATE FINANCIAL OVERVIEW 2004 Financial Results - - Although Improving, Low Spark Spreads Continue in Certain Markets - - Gas Impairment - - 4th Quarter Equipment Problems + Reduced Plant and Overhead Costs Per mwh (1) Successfully Enhanced Financial Position + Refinanced $2.4 Billion of Maturing CCFC II Project Debt + Completed $2.1 Billion of Liquidity Transactions + Redeemed in Full High Tides I and II; Portion of High Tides III + Repurchased or Refinanced $1.8 Billion of Existing Debt (1) Trailing 12-month costs at an assumed 70% capacity factor

2004 BUSINESS UPDATE POWER PORTFOLIO OVERVIEW Increased Fleet of Efficient Plants + Added Over 4,400 mw + 6 New Plants, 2 Expansions Improved Plant Performance + 2004 Plant Availability Reached 92.6%; 91.2% in 2003 + Heat Rate Reduced to 7,120 btu/kwh; 7,253 in 2003 + Plant Operating Costs Reduced to $4.56/mwh; $4.96 in 2003 (1) (1) Trailing 12-month plant operating costs (excluding major maintenance) at an assumed 70% capacity factor

2004 BUSINESS UPDATE MARKETING AND SALES OVERVIEW 2004 Marketing and Sales Highlights 90 New Power Contracts 17 Contracts Won Through RFPs 73 Contracts Executed Through Unsolicited Proposals Reduced F Technology Turbine Inventory to 17 From 22 7,190 mw 41/2-Year Weighted Average Life $17 Weighted Average On-Peak Spark Spread Per mwh Over 300 Million mwh From New Contracts Backlog Up 28% to 908 Million mwh

2004 BUSINESS UPDATE GE H SYSTEM Signed LOI With GE for the Joint Construction of the First North American Power Plant Utilizing GE's State-of-the-Art Gas-Fired Turbines - the H System Permitting in Process for 775-mw Plant to be Located in Attractive Southern California Market Benefits to Calpine: GE to Purchase Development Rights From Calpine GE to Fund Construction Costs Calpine to Provide Program Management Services During Construction Calpine Will Market Electricity From the Plant Calpine Will Purchase the Facility After an Extended Period of GE Ownership

2004 BUSINESS UPDATE 2004 ELECTRICITY CONSUMPTION Source: Edison Electric Institute and Company Data Electricity Consumption in 2004 vs 2003 United States Total 4th Quarter: 2.8% United States Total YTD 12/25/04: 1.9% PACIFIC SOUTHWEST SOUTH CENTRAL SOUTHEAST

2004 FINANCIAL RESULTS Bob Kelly Executive Vice President and Chief Financial Officer

(In millions, except EPS) (In millions, except EPS) (In millions, except EPS) 4th Quarter Ended Dec. 31, 2004 Year Ended Dec. 31, 2004 Revenue $ 2,336.2 $ 9,229.9 GAAP Net Income (Loss) $ (172.8) $ (221.2) GAAP Fully Diluted Loss Per Share $ (0.39) $ (0.51) Operating Cash Flow $ (220.0) $ 9.9 EBITDA, as Adjusted for Non-Cash and Other Charges (1) $ 232.2 $ 1,630.4 EBITDA, as Adjusted for Non-Cash and Other Charges to Interest Expense (2) 0.70x 1.39x 2004 FINANCIAL RESULTS KEY FINANCIAL HIGHLIGHTS (1) Earnings Before Interest, Tax, Depreciation and Amortization, as Adjusted for Non-Cash Items; 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 and Distributions on Trust Preferred Securities

2004 FINANCIAL RESULTS SPARK SPREADS 4th Quarter 4th Quarter 4th Quarter Year Year Year 2003 2004 2003 2004 Average mw in Operation 22,079 26,558 20,692 25,077 mwh Generated (000s) 20,355 23,967 82,423 96,489 mwh Delivered (000s) (1) 36,699 35,985 159,655 147,664 Spark Spread: Total (000s) $ 486,494 $ 511,832 $ 1,970,201 $ 2,049,374 Per mwh $ 23.90 $ 21.36 $ 23.90 $ 21.24 (1) After netting volumes per EITF 03-11 commencing Oct. 1, 2003. Mwh for the year 2003 only reflect netted volumes for the 4th quarter

2004 FINANCIAL RESULTS POWER PLANT STATISTICS 4th Quarter 4th Quarter 4th Quarter Year Year Year 2003 2004 2003 2004 Plant Availability Factor Plant Availability Factor 91.4% 92.2% 91.2% 92.6% Plant Baseload Capacity Factor Plant Baseload Capacity Factor 48.9% 45.6% 53.2% 49.8% Average Heat Rate (btu/kwh) Average Heat Rate (btu/kwh) 7,409 7,026 7,253 7,120 Plant Operating Expenses (000s) Plant Operating Expenses (000s) $ 166,926 $220,144 $663,045 $795,975 Plant Operating Expenses (per mwh) (1) Plant Operating Expenses (per mwh) (1) $5.01 $5.39 $5.38 $5.24 (1) Plant operating expenses include major maintenance expense and is calculated on a trailing 12-month basis at an assumed 70% capacity factor (1) Plant operating expenses include major maintenance expense and is calculated on a trailing 12-month basis at an assumed 70% capacity factor (1) Plant operating expenses include major maintenance expense and is calculated on a trailing 12-month basis at an assumed 70% capacity factor (1) Plant operating expenses include major maintenance expense and is calculated on a trailing 12-month basis at an assumed 70% capacity factor (1) Plant operating expenses include major maintenance expense and is calculated on a trailing 12-month basis at an assumed 70% capacity factor (1) Plant operating expenses include major maintenance expense and is calculated on a trailing 12-month basis at an assumed 70% capacity factor (1) Plant operating expenses include major maintenance expense and is calculated on a trailing 12-month basis at an assumed 70% capacity factor (1) Plant operating expenses include major maintenance expense and is calculated on a trailing 12-month basis at an assumed 70% capacity factor (1) Plant operating expenses include major maintenance expense and is calculated on a trailing 12-month basis at an assumed 70% capacity factor

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

2004 FINANCIAL RESULTS FUELS COMPANY HIGHLIGHTS Sale of Canadian and Certain U.S. Gas Reserves Generated $848 Million in Total Proceeds 4th Quarter Impairment Charge of $201.5 Million Current Gas Statistics: Total Proved Reserves at 12/31/04, 389 bcfe 2004 Production, 46 bcfe 2004 Average Production Per Day, 127 mmcfe Production as a Percentage of Calpine's Consumption, 7%

2004 FINANCIAL RESULTS LIQUIDITY OVERVIEW Liquidity Update Completed Transactions Totaling $2.1 Billion in 2004 Moving Forward on Transactions Totaling $865 Million Year-End Balance Targeted: $2-$2.5 Billion Actual: $1.6 Billion (1) Difference Comprised of: Liquidity Transactions Pushed into 2005 $136 Million of Increased Collateral Required at CES Repurchased, Refinanced or Redeemed Nearly $2.4 Billion of Debt (2) (1) Includes cash and cash equivalents on hand of approximately $0.8 billion, the current portion of restricted cash of approximately $0.6 billion and approximately $0.2 billion of borrowing capacity available under the company's various credit facilities upon meeting certain conditions (2) Detailed schedule provided in Appendix C

2005 FINANCIAL OUTLOOK Bob Kelly Executive Vice President and Chief Financial Officer

2005 FINANCIAL OUTLOOK FINANCIAL FOCUS FOR 2005 Complete Remaining Liquidity Transactions Focus on Corporate Debt Reduction Evaluate CES Credit Enhancement Execute Long-Term Sales Agreements Focus on Plant Cost Reduction Deploy Remaining Turbines Expand Services Business

2005 FINANCIAL OUTLOOK FINANCIAL HIGHLIGHTS (In millions, except EPS) Total Revenue $ 11,800 EBITDA, as Adjusted for Non-Cash and Other Charges (1) $ 1,600-1,700 GAAP Fully Diluted Loss Per Share $ (0.80)-($0.90) (1) Earnings Before Interest, Tax, Depreciation and Amortization, as Adjusted for Non-Cash Items; See Appendix A for Reconciliation from Net Loss, Which is the Most Directly Comparable GAAP Measure

2005 FINANCIAL OUTLOOK CASH FLOW HIGHLIGHTS (In millions) (In millions) (In millions) EBITDA, as Adjusted for Non-Cash and Other Charges $ 1,700 Cash Interest (1,500) Capital Expenditures - Maintenance and Drilling 150 - Non-Project Financed Construction Costs 50 (200) Cash Flow From Operations 0 Debt Service - Lease Payments 185 - Scheduled Principal Payments 330 - Maturing Senior Notes Due 2005 186 (701) Refinancing Transactions 500 Net Change in Cash $ (201)

2005 FINANCIAL OUTLOOK CORPORATE DEBT REDUCTION Evaluate Sale of Certain Projects, Including Saltend Power Plant Complete Liquidity Transactions Totaling $865 Million Other Opportunities 2005 TARGET Repurchase More Than $1 Billion of Debt

POWER MARKETS UPDATE Paul Posoli Senior Vice President - Calpine Energy Services

POWER MARKETS UPDATE POSITIVE MOVEMENT IN SPARK SPREADS Spark Spreads Per mwh Trending Up 1st Quarter 1st Quarter 1st Quarter 2nd Quarter 2nd Quarter 2nd Quarter 3rd Quarter 3rd Quarter 3rd Quarter 4th Quarter 4th Quarter 4th Quarter 2003 2004 2003 2004 2003 2004 2003 2004 NP15 $ 13.08 $ 7.71 $ 8.59 $ 13.42 $ 18.56 $ 19.26 $ 12.10 $ 20.76 SP15 $ 15.10 $ 11.57 $ 13.38 $ 14.67 $ 19.93 $ 20.07 $ 12.98 $ 19.18 ERCOT $ 11.00 $ 5.39 $ 15.26 $ 12.06 $ 11.90 $ 12.97 $ 5.37 $ 9.08 Southeast $ 5.95 $ 1.33 $ 0.54 $ 9.54 $ 7.43 $ 10.32 $ (3.14) $ 3.24 NEPOOL $ 11.89 $ 12.82 $ 9.90 $ 15.13 $ 14.33 $ 12.37 $ 13.22 $ 9.09 Note: Figures Represent Average On-Peak, Day-Ahead Spark Spreads at 7,000 btu/kwh Heat Rate Source: Company Data

POWER MARKETS UPDATE OTHER POSITIVE TRENDS Declining Reserve Margins 2003 2006 California (1) 20.0% 13.0% ERCOT (2) 26.1% 11.2% NEPOOL (3) 25.0% 20.2% Announced Plans to Mothball Plants ERCOT California Southeast Reserve Margins Remain High (1) Source: "California's Electricity Demand and Supply Outlook," July 8, 2004; California Energy Commission (2) Source: ERCOT Technical Advisory Committee, assuming the intended mothballed units remain offline and 1,600 mw of other units are retired (3) Source: "NEPOOL 2004-2013 Forecast Report of Capacity, Energy, Loads, and Transmission," April 2004; ISO-NE

POWER MARKETS UPDATE 2006 FORWARD CURVES Calendar 2006 Forward Spark Spreads Per mwh 2006 On-Peak 2006 On-Peak 2006 On-Peak 2006 Off-Peak 2006 Off-Peak 2006 Off-Peak As of 9/30/04 As of 2/18/05 As of 9/30/04 As of 2/18/05 NP-15 $ 18.03 $ 20.44 $ 1.14 $ 4.44 SP-15 $ 21.11 $ 24.32 $ 2.15 $ 5.57 ERCOT $ 13.47 $ 15.17 $ (1.26) $ 0.47 NEPOOL $ 16.30 $ 18.26 $ 0.71 $ 1.32 Southeast $ 7.78 $ 7.63 $ (8.07) $ (9.25) Source: Company data

2005 OUTLOOK Pete Cartwright Chairman, President and Chief Executive Officer

2005 OUTLOOK NEW CONTRACTING OPPORTUNITIES Pursuing Over 22,000 mw of Opportunities 8,300 Through RFPs 13,700 Through Unsolicited Proposals Actively Pursuing California Market Opportunities Additional California Generation On-Line in 2005 602-mw Metcalf Energy Center, 6/05 769-mw Pastoria Energy Center, 3/05 & 7/05 Opportunities Could Significantly Enhance 2005 and 2006 Contracted Portfolio

2005 OUTLOOK FORMATION OF NEWSOUTH ENERGY Newly Formed Entity Will Focus on Southeast Power Markets Calpine's Southeast Portfolio In Operation, 12 Plants, Over 5,800 mw In Construction, 2 Plants, Over 1,300 mw Committed Team of Professionals Will Focus on: Marketing of Generation Political and Regulatory Affairs NewSouth Energy Will Enhance Short-Term and Long-Term Value for Calpine and Our Customers in the Southeast

2005 OUTLOOK REDUCING VOLATILITY Contracted Power & Steam Sales - Agreements Natural Gas Components and Services Calpine Energy Services Growing Business Activities to Reduce Volatility

QUESTION AND ANSWER SESSION

APPENDICES

APPENDIX A:CALPINEGAAP NET INCOME TO EBITDA, AS ADJUSTEDThree Months Ended Year Ended December 31, December 31, 2004 2003 2004 2003(In thousands) GAAP net Income (loss) $ (172,809) $ 119,621 $ (221,172) $ 282,022 (Income) loss from unconsolidated investments in power projects and oil and gas properties 1,862 (7,220) 13,525 (75,804) Distributions from unconsolidated investments in power projects and oil and gas properties 7,622 15,948 29,869 141,627 Subtotal (163,325) 128,349 (177,778) 347,845 Interest expense 325,445 223,068 1,140,802 706,307 1/3 of operating lease expense 8,440 9,257 35,295 37,357 Distributions on trust preferred securities — — — 46,610 Provision (benefit) for income taxes (217,406) (3,438) (299,360) 8,495 Depreciation, depletion and amortization expense 369,945 167,402 840,916 568,204 Interest expense, provision (benefit) for income taxes and depreciation, depletion and income from unconsolidated investments in power projects from discontinued operations (67,665) 20,416 114,009 84,489 EBITDA, as adjusted $ 255,434 $ 545,054 $ 1,653,884 $ 1,799,307 R02050231February 24, 2005

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 2005 2006 2007 2008 2009 Thereafter Total Notes Payable / Lines of Credit DWR Monetization 5.2% Senior Secured Notes Due 2006 $ 226.0 $ 226.0 $ 148.1 $ 77.9 $ - $ - $ - $ - $ 226.0 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 51.6 85.0 - - - - - 85.0 85.0 Gilroy Note 125.5 125.5 7.8 8.6 9.6 10.6 11.8 77.1 125.5 BPA Monetization 52.3 52.3 22.9 23.4 6.0 - - - 52.3 Calpine Commercial Trust 34.3 37.7 8.9 8.9 8.9 6.7 2.2 2.1 37.7 Miscellaneous 22.3 22.3 18.5 0.6 0.9 0.3 0.3 1.7 22.3 Notes Payable $ 974.3 $ 1,011.1 $ 206.2 $ 197.3 $ 153.6 $ 115.2 $ 118.0 $ 220.8 $ 1,011.1 Preferred Interests Auburndale Power Plant $ 79.1 $ 79.1 $ 1.0 $ 0.7 $ 1.5 $ 3.9 $ 6.4 $ 65.6 $ 79.1 Saltend Redeemable Preferred Shares 360.0 360.0 - 360.0 - - - - 360.0 Gilroy Energy Center 67.4 67.4 7.6 8.8 7.5 8.3 9.8 25.4 67.4 Preferred Interests $ 506.5 $ 506.5 $ 8.6 $ 369.5 $ 9.0 $ 12.2 $ 16.2 $ 91.0 $ 506.5 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 95.9 95.9 1.2 1.2 1.5 1.4 2.0 88.6 95.9 Stony Brook Power Plant 63.8 72.7 1.0 1.2 1.5 1.7 1.8 65.5 72.7 Agnews Power Plant 27.0 27.0 2.8 3.0 3.2 3.7 4.0 10.3 27.0 Corporate 0.7 0.7 0.6 0.1 - - - - 0.7 Capital Lease Obligations $ 288.8 $ 297.7 $ 5.6 $ 6.6 $ 7.5 $ 9.9 $ 11.0 $ 257.1 $ 297.7 As of December 31, 2004 (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 2005 2006 2007 2008 2009 Thereafter Total CCFC I Term Loan Notes Due 2009 $ 378.2 $ 381.1 $ 3.9 $ 3.8 $ 3.9 $ 3.8 $ 365.7 $ - $ 381.1 Floating Rate Notes Due 2011 408.6 415.0 - - - - - 415.0 415.0 CCFC I $ 786.8 $ 796.1 $ 3.9 $ 3.8 $ 3.9 $ 3.8 $ 365.7 $ 415.0 $ 796.1 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 631.6 640.0 - - - 3.2 6.4 630.4 640.0 Term Loan Notes Due 2010 98.7 100.0 - - - 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 $ 2,395.3 $ 2,405.0 $ - $ - $ 4.2 $ 12.1 $ 829.8 $ 1,558.9 $ 2,405.0 Project Financing Gilroy Energy Center $ 261.4 $ 264.0 $ 38.9 $ 40.1 $ 34.6 $ 37.0 $ 37.7 $ 75.7 $ 264.0 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 282.9 282.9 0.7 6.8 13.1 15.7 19.5 227.1 282.9 Riverside Energy Center 368.5 368.5 3.7 3.7 3.7 3.7 3.7 350.0 368.5 Blue Spruce Energy Center 98.3 98.3 1.9 3.8 3.8 3.8 3.8 81.2 98.3 Rocky Mountain Energy Center 264.9 264.9 2.6 2.6 2.6 2.6 2.6 251.9 264.9 Aries Power Plant 174.9 174.9 8.1 9.9 10.6 10.7 10.9 124.7 174.9 Fox Energy Center 266.1 266.1 27.6 10.4 20.8 10.2 14.5 182.6 266.1 Otay Mesa Energy Center 7.0 7.0 - - - - - 7.0 7.0 Project Financing $ 1,999.1 $ 2,001.7 $ 93.4 $ 89.4 $ 103.4 $ 100.3 $ 105.3 $ 1,509.9 $ 2,001.7 As of December 31, 2004 (In millions)

APPENDIX B: OUTSTANDING DEBT & PRINCIPAL PAYMENT SCHEDULES (continued) As of December 31, 2004 (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 2005 2006 2007 2008 2009 Thereafter Total First Priority Senior Secured Notes 9.625% Senior Secured Notes Due 2014 $ 779.0 $ 785.0 $ - $ - $ - $ - $ - $ 785.0 $ 785.0 First Priority Senior Secured Notes $ 779.0 $ 785.0 $ - $ - $ - $ - $ - $ 785.0 $ 785.0 Second Priority Senior Secured Notes Term Loan B Notes Due 2007 $ 740.6 $ 740.6 $ 7.5 $ 7.5 $ 725.6 $ - $ - $ - $ 740.6 Floating Rate Notes Due 2007 493.7 493.7 5.0 5.0 483.7 - - - 493.7 8.5% Senior Notes Due 2010 1,150.0 1,150.0 - - - - - 1,150.0 1,150.0 9.875% Senior Notes Due 2011 393.2 400.0 - - - - - 400.0 400.0 8.75% Senior Notes Due 2013 900.0 900.0 - - - - - 900.0 900.0 Second Priority Senior Secured Notes $ 3,677.5 $ 3,684.3 $ 12.5 $ 12.5 $ 1,209.3 $ - $ - $ 2,450.0 $ 3,684.3 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 620.2 736.0 - - - - - 736.0 736.0 4.75% Convertible Senior Notes Due 2023 633.8 633.8 - - - - - 633.8 633.8 Convertible Unsecured Senior Notes $ 1,255.3 $ 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 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) 165.6 166.0 - - 166.0 - - - 166.0 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) 160.0 160.0 - - - 160.0 - - 160.0 8.5% Senior Notes Due 2008 1,581.5 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 497.0 497.3 - - - - - 497.3 497.3 8.5% Senior Notes Due 2011 1,063.8 1,088.6 - - - - - 1,088.6 1,088.6 8.875% Senior Notes Due 2011 (Sterling) 232.6 233.9 - - - - - 233.9 233.9 Unsecured Senior Notes $ 4,794.7 $ 4,822.8 $ 186.1 $ 264.3 $ 361.3 $ 1,969.7 $ 221.6 $ 1,819.8 $ 4,822.8 Notes Payable to Calpine Capital Trust High Tides I (1) $ - $ - $ - $ - $ - $ - $ - $ - $ - High Tides II (1) - - - - - - - - - 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 $ 17,974.8 $ 18,083.8 $ 516.3 $ 944.7 $ 1,852.2 $ 2,223.2 $ 1,667.6 $ 10,879.8 $ 18,083.8 Scheduled Principal Payments $ 330.2 $ 319.1 $ 281.6 $ 253.5 $ 257.9 Final Principal Payments 186.1 625.6 1,570.6 1,969.7 1,409.7 Total $ 516.3 $ 944.7 $ 1,852.2 $ 2,223.2 $ 1,667.6 APPENDIX B: OUTSTANDING DEBT & PRINCIPAL PAYMENT SCHEDULES (continued) As of December 31, 2004 (In millions) (1) Notes were redeemed in full on Oct. 20, 2004

APPENDIX C: 2004 CORPORATE DEBT REPURCHASES (In millions) Face Amount of Debt Repurchased in 2004 Face Amount of Debt Repurchased in 2004 Face Amount of Debt Repurchased in 2004 Face Amount of Debt Repurchased in 2004 Face Amount of Debt Repurchased in 2004 Face Amount of Debt Repurchased in 2004 Face Amount of Debt Repurchased in 2004 Security 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter 2004 Total Unsecured Senior Notes 8.5% Senior Notes Due 2008 $ - $ - $ 279.8 $ 64.5 $ 344.3 8.5% Senior Notes Due 2011 9.0 - - 107.9 116.9 7.625% Senior Notes Due 2006 - - 23.8 79.3 103.1 7.875% Senior Notes Due 2008 - - 50.0 28.4 78.4 8.25% Senior Notes Due 2005 - 38.9 - - 38.9 8.75% Senior Notes Due 2007 - - - 30.8 30.8 10.5% Senior Notes Due 2006 - 7.7 - 6.2 13.9 7.75% Senior Notes Due 2009 11.0 - - - 11.0 8.375% Senior Notes Due 2008 (Euro) - - - 6.1 6.1 Subtotal $ 20.0 $ 46.6 $ 353.6 $ 323.2 $ 743.4 Convertible Unsecured Senior Notes 4% Convertible Senior Notes Due 2006 $ 587.9 $ - $ - $ 70.8 $ 658.7 4.75% Convertible Senior Notes Due 2023 - - 266.2 - 266.2 Subtotal $ 587.9 $ - $ 266.2 $ 70.8 $ 924.9 Notes Payable to Calpine Capital Trust High Tides I $ - $ 20.0 $ 20.0 $ 198.5 $ 238.5 High Tides II - 75.0 - 285.0 360.0 High Tides III - - 115.0 - 115.0 Subtotal $ - $ 95.0 $ 135.0 $ 483.5 $ 713.5 Total Debt Repurchased in 2004 $ 607.9 $ 141.6 $ 754.8 $ 877.5 $ 2,381.8 Cost to Repurchase Write-Off of Deferred Financing Cost 2,134.9 Gain on Repurchased Debt $ 246.9

APPENDIX D: 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 D: 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 - 779.0 100.0% - 779.0 Jun-00 540 mw; Aug-01 239 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 5,567.0 3,649.0 4,962.0

APPENDIX D: 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 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 122.0 122.0 100.0% 122.0 122.0 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 D: 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 5,293.0 6,795.0 4,963.3 6,419.8 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 22,682.0 27,873.0 21,504.5 26,582.6 Operated by Trigen Operated by Whitby Cogen Limited Partnership

APPENDIX D: 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-06 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 Jun-05, COD Nov-06 Total ERCOT 200.0 250.0 200.0 250.0 MAPP Mankato Power Plant Minnesota Natural Gas 280.0 365.0 100.0% 280.0 365.0 Jun-06 Total MAPP 280.0 365.0 280.0 365.0 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 May-06 Washington Parish Energy Center Louisiana Natural Gas 509.0 565.0 100.0% 509.0 565.0 Jun-06 Total SERC 1,219.0 1,335.0 1,219.0 1,335.0 WECC Pastoria Energy Center, Phase I (CalGen) California Natural Gas 259.0 269.0 100.0% 259.0 269.0 Mar-05 Pastoria Energy Center, Phase II (CalGen) California Natural Gas 500.0 500.0 100.0% 500.0 500.0 Aug-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 TBD Total WECC 1,825.0 1,964.0 1,825.0 1,964.0 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 5,168.9 5,778.9 4,880.2 5,490.2

APPENDIX D: 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 12.8% 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 27.5% 250.0 4.6% 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 3.3% - 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% 365.0 6.6% 365.0 1.1% MAIN (Mid-America Interconnected Network) MAIN (Mid-America Interconnected Network) MAIN (Mid-America Interconnected Network) 1,732.0 6.5% 560.0 10.2% 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 4.8% - 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 1.0% 79.9 1.5% 333.9 1.0% SERC (Southeastern Electric Reliability Council) SERC (Southeastern Electric Reliability Council) SERC (Southeastern Electric Reliability Council) 4,962.0 18.7% 1,335.0 24.3% 6,297.0 19.6% SPP (Southwest Power Pool) SPP (Southwest Power Pool) SPP (Southwest Power Pool) 1,674.0 6.3% - 0.0% 1,674.0 5.2% WECC (Western Electricity Coordinating Council) WECC (Western Electricity Coordinating Council) WECC (Western Electricity Coordinating Council) 6,419.8 24.2% 1,964.0 35.8% 8,383.8 26.1% 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 4.3% 236.3 0.0% TOTAL CALPINE 26,582.6 100.0% 5,490.2 100.0% 32,072.7 100.0% # 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 73 21,932.0 27,123.0 20,754.5 25,832.6 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 11 5,168.9 5,778.9 4,880.2 5,490.2 Total Project Portfolio 103 27,850.9 33,651.9 26,384.6 32,072.7 TOTAL PROJECTS IN OPERATION OPERATED BY CALPINE (90) TOTAL PROJECTS IN OPERATION OPERATED BY CALPINE (90) TOTAL PROJECTS IN OPERATION OPERATED BY CALPINE (90) TOTAL PROJECTS IN OPERATION OPERATED BY CALPINE (90) 22,466.0 27,648.0 21,414.0 26,487.6

APPENDIX E: CONTRACTUAL PORTFOLIO SUMMARY 149 Contracts / 97 Customers Weighted Average Credit: BBB+ 8-Year Weighted Average Life

APPENDIX E: CONTRACTUAL PORTFOLIO CONTRACT TYPE 2005 2006 2007 2008 2009 Fixed Price 31% 22% 19% 18% 19% Heat Rate 68% 75% 76% 77% 75% Other 1% 3% 5% 5% 6%

APPENDIX E: CONTRACTUAL PORTFOLIO DEFINITIONS The following detailed reports represent several data points for Calpine's power generation portfolio as of December 31, 2004. 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 E: 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 December 31, 2004 Contracts that have been announced and, or signed subsequent to December 31, 2004 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 E: CONTRACTUAL PORTFOLIO TOTAL 2005 2006 2007 2008 2009 Estimated Generation (In Millions of mwh) - Baseload 188.2 213.5 221.2 221.8 221.2 - Peaking 25.4 26.5 26.8 26.9 26.8 Total 213.6 240.0 248.0 248.7 248.0 Contractual Generation (In Millions of mwh) - Baseload 96.2 67.0 54.3 52.3 49.6 - Peaking 19.3 18.9 18.7 18.0 15.0 Total 115.5 85.9 73.0 70.3 64.6 % Sold - Baseload 51% 31% 25% 24% 22% - Peaking 76% 71% 70% 67% 56% Total 54% 36% 29% 28% 26% Contractual Spark Spread $1,912 $1,818 $1,516 $1,464 $1,373 (In Millions) Data as of 12/31/04

APPENDIX E: CONTRACTUAL PORTFOLIO WECC Estimated Generation (In Millions of mwh) - Baseload 48.0 55.2 57.3 57.5 57.3 - Peaking 6.6 6.8 6.9 6.9 6.9 Total 54.6 62.0 64.2 64.4 64.2 Contractual Generation (In Millions of mwh) - Baseload 31.4 26.2 24.1 24.2 23.4 - Peaking 4.9 4.2 4.1 4.1 4.1 Total 36.3 30.4 28.2 28.3 27.5 % Sold - Baseload 65% 47% 42% 42% 41% - Peaking 74% 62% 59% 59% 59% Total 66% 49% 44% 44% 43% 2005 2006 2007 2008 2009 Data as of 12/31/04

APPENDIX E: CONTRACTUAL PORTFOLIO ERCOT Estimated Generation (In Millions of mwh) - Baseload 54.9 56.3 56.5 56.7 56.5 - Peaking 2.0 2.2 2.2 2.2 2.2 Total 56.9 58.5 58.7 58.9 58.7 Contractual Generation (In Millions of mwh) - Baseload 32.2 19.4 8.6 8.1 8.1 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 32.2 19.4 8.6 8.1 8.1 % Sold - Baseload 59% 34% 15% 14% 14% - Peaking 0% 0% 0% 0% 0% Total 57% 33% 15% 14% 14% 2005 2006 2007 2008 2009 Data as of 12/31/04

APPENDIX E: CONTRACTUAL PORTFOLIO NORTHEAST Estimated Generation (In Millions of mwh) - Baseload 18.7 19.0 19.0 19.1 19.0 - Peaking 0.4 0.4 0.4 0.4 0.4 Total 19.1 19.4 19.4 19.5 19.4 Contractual Generation (In Millions of mwh) - Baseload 9.2 2.6 2.5 2.1 2.0 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 9.2 2.6 2.5 2.1 2.0 % Sold - Baseload 49% 14% 13% 11% 11% - Peaking 0% 0% 0% 0% 0% Total 48% 13% 13% 11% 10% 2005 2006 2007 2008 2009 Data as of 12/31/04 Includes the Following NERC Regions: NEPOOL, NYPOOL, MAAC, NPCC

APPENDIX E: CONTRACTUAL PORTFOLIO SOUTHEAST Estimated Generation (In Millions of mwh) - Baseload 26.2 30.2 32.1 32.2 32.1 - Peaking 8.5 8.6 8.6 8.7 8.6 Total 34.7 38.8 40.7 40.9 40.7 Contractual Generation (In Millions of mwh) - Baseload 9.5 9.8 8.3 7.2 5.4 - Peaking 6.6 6.6 6.6 6.6 6.6 Total 16.1 16.4 14.9 13.8 12.0 % Sold - Baseload 36% 32% 26% 22% 17% - Peaking 78% 77% 77% 76% 77% Total 46% 42% 37% 34% 29% 2005 2006 2007 2008 2009 Data as of 12/31/04 Includes the Following NERC Regions: SERC, FRCC

APPENDIX E: CONTRACTUAL PORTFOLIO MIDWEST Estimated Generation (In Millions of mwh) - Baseload 30.5 41.6 44.3 44.4 44.3 - Peaking 7.8 8.5 8.6 8.6 8.6 Total 38.3 50.1 52.9 53.0 52.9 Contractual Generation (In Millions of mwh) - Baseload 8.8 5.9 8.1 7.9 7.9 - Peaking 7.8 8.1 8.1 7.4 4.4 Total 16.6 14.0 16.2 15.3 12.3 % Sold - Baseload 29% 14% 18% 18% 18% - Peaking 100% 95% 94% 86% 51% Total 43% 28% 31% 29% 23% 2005 2006 2007 2008 2009 Data as of 12/31/04 Includes the Following NERC Regions/Sub-Region: MAPP, MAIN, ECAR, SPP and Entergy

APPENDIX E: CONTRACTUAL PORTFOLIO UNITED KINGDOM Estimated Generation (In Millions of mwh) - Baseload 10.0 10.0 10.0 10.0 10.0 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 10.0 10.0 10.0 10.0 10.0 Contractual Generation (In Millions of mwh) - Baseload 5.1 1.9 0.7 0.7 0.7 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 5.1 1.9 0.7 0.7 0.7 % Sold - Baseload 51% 19% 7% 7% 7% - Peaking 0% 0% 0% 0% 0% Total 51% 19% 7% 7% 7% 2005 2006 2007 2008 2009 Data as of 12/31/04 Includes the Saltend Energy Centre

APPENDIX E: 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 12/31/04 Includes the Valladolid III Project

CALPINE