EXHIBIT 99.1

CONTACTS: 408-995-5115
Media Relations: Bill Highlander, Ext. 1244
Investor Relations: Rick Barraza, Ext. 1125

Calpine Reports Third Quarter 2004 Financial and Operating Results

Financial Results Impacted by Mild Weather

Completed Transactions Adding $1.5 Billion of Liquidity

Redeemed HIGH TIDES I & II Preferred Securities

     (SAN JOSE, CALIF.) /PR NEWSWIRE – First Call/ Nov. 4, 2004 – Calpine Corporation [NYSE:CPN] today announced financial and operating results for the three and nine months ended Sept. 30, 2004. A conference call, set for 8:30 a.m. PST today, will be accompanied by a comprehensive presentation of the financial and operating results for the quarter. The presentation will be located on Calpine’s investor relations page at www.calpine.com.

     For the three months ended Sept. 30, 2004, the company reported earnings per share of $0.05, or net income of $22.3 million, compared to earnings per share of $0.51, or net income of $237.8 million for the quarter ended Sept. 30, 2003.

	Third Quarter
	(unaudited)
	2004			2003
GAAP diluted earnings per share (EPS)	$	0.05		$	0.51
Tax charge to be reversed in Q4 2004		0.15			—
Total		0.20			0.51
Other significant items included in GAAP EPS:
Income from the sale of natural gas assets		0.14			—
Income on the repurchase of various issuances of existing debt		0.23			0.23
Income from settlement of claims and disputes of commodity contracts		—			0.11
Equipment cancellation and service agreement cancellation		(0.02	)		—
Foreign currency transaction gain/(loss)		(0.04	)		0.01
Unrealized mark-to-market activity gain/(loss)		(0.03	)		(0.02	)

-more-

CALPINE REPORTS THIRD QUARTER 2004 FINANCIAL AND OPERATING RESULTS
Page 2
Nov. 4, 2004

	Third Quarter
	(unaudited)
	2004		2003		% Chg
Megawatt-hours generated (millions) (a)		29.4		25.4		16	%
Megawatts in operation at Sept. 30		26,489		22,244		19	%
Revenue (millions)	$	2,557.2	$	2,656.6		(4	)%
Net income (millions)	$	22.3	$	237.8		(91	)%
Operating cash flow (millions)	$	224.6	$	58.0		287	%
EBITDA, as adjusted (millions)(b)	$	716.5	$	663.1		8	%
EBITDA, as adjusted, for non-cash and other charges (millions) (c)	$	636.9	$	480.7		32	%
Total assets (billions)	$	28	$	26		8	%

(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.

     “During the quarter, Calpine’s power plant operations remained strong, with 97% availability,” stated Calpine CEO and President Peter Cartwright. “Earnings, however, fell short of our expectations – primarily as a result of low market spark spreads attributed in part to mild, below normal weather in several U.S. power markets.

     “We made significant progress on our announced liquidity enhancing program, completing $1.5 billion of liquidity transactions. A portion of these proceeds was used to repurchase $735 million of existing debt. In October, we also redeemed our HIGH TIDES I and II preferred securities.

     “While we cannot predict when power prices will normalize, we are encouraged by an improvement in spark spreads in several of Calpine’s major power markets. Moving forward, Calpine remains committed to advancing our strategy of selling power under long-term contracts, improving our balance sheet through the repurchasing of debt, and enhancing liquidity.”

2004 Third Quarter Results

     In the quarter ended Sept. 30, 2004, Calpine netted approximately $563.3 million of sales of purchased power for hedging and optimization with purchased power expense for hedging and optimization. This was due to the adoption on October 1, 2003, on a prospective basis, of new accounting rules related to presentation of non-trading derivative activity. Without this netting, total revenue would have grown by approximately 17% versus the reported 4% reduction in revenue. For the three months ended Sept. 30, 2004, the company reported earnings per share of $0.05, or net income of $22.3 million, compared to earnings per share of $0.51, or net income of $237.8 million, for the same quarter in the prior year. The results for the third quarter of 2004 include additional tax expense of approximately $78.8 million, which is attributable to the

-more-

CALPINE REPORTS THIRD QUARTER 2004 FINANCIAL AND OPERATING RESULTS
Page 3
Nov. 4, 2004

repatriation of net cash proceeds from Canada to the United States following the sale of oil and gas assets in Canada and which is mostly netted within the discontinued operations gain. The company expects to record a reduction of approximately $66.9 million, or $0.15 per share, of this tax expense, in the fourth quarter of 2004 because of provisions in The American Jobs Creation Act of 2004 signed into law on October 22, 2004.

     Calpine recognized an after-tax gain of $62.6 million, or $0.14 per share, in discontinued operations associated with the sale of the company’s Canadian natural gas reserves and petroleum assets and the sale of its gas reserves in the Colorado Piceance Basin and New Mexico San Juan Basin. The company also recognized an after-tax gain of $0.23 per share on the repurchase of certain debt issuances, compared to a gain of $0.23 per share in the same quarter in 2003.

     Gross profit decreased by $84.5 million, or 25%, to $254.4 million in the three months ended Sept. 30, 2004, primarily due to: i) non-recurring other revenue of $69.4 million recognized in the third quarter of 2003 from the settlement of contract disputes with, and claims against, Enron Corp.; ii) the amortization of $6.2 million in the third quarter 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; iii) soft market fundamentals, which caused total spark spread to not increase commensurately with additional transmission purchase expense, and depreciation costs associated with new power plants coming on-line. During the three months ended Sept. 30, 2004, financial results were affected by a $79.7 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. Loss before discontinued operations and cumulative effect of a change in accounting principle was $40.2 million, or $0.09 per share. This loss is primarily due to an effective tax rate increase, which occurred as a result of the sale of oil and gas assets in Canada and due to the repatriation of cash to the United States.

     For the three months ended Sept. 30, 2004, the company generated 29.4 million megawatt-hours, which equated to a baseload capacity factor of 56%, and realized an average spark spread of $21.40 per megawatt-hour. For the same period in 2003, Calpine generated 25.4 million megawatt-hours, which equated to a capacity factor of 60%, and realized an average spark spread of $23.88 per megawatt-hour.

2004 Nine-Month Results

     In the nine months ended Sept. 30, 2004, Calpine netted approximately $1.26 billion of sales of purchased power for hedging and optimization with purchased power expense. This was due to the adoption on October 1, 2003, on a prospective basis, of new accounting rules related to presentation of non-trading derivative activity. Without this netting, total revenue would have grown by approximately 17% versus the reported 1% reduction in revenue. For the nine months ended Sept. 30, 2004, the company reported a loss per share of $0.18, or a net loss of $77.6 million, compared to earnings per share of $0.41, or net income of $162.4 million, for the same period in the prior year. The year to date results for 2004 include additional tax expense of approximately $78.8 million, which is attributable to the repatriation of net cash proceeds from Canada to the United States following the sale of oil and gas assets in Canada and which is mostly netted within the discontinued operations gain. Calpine expects to record a reduction of

-more-

CALPINE REPORTS THIRD QUARTER 2004 FINANCIAL AND OPERATING RESULTS
Page 4
Nov. 4, 2004

approximately $66.9 million, or $0.15 per share, of this tax expense in the fourth quarter of 2004 because of provisions in The American Jobs Creation Act of 2004 signed into law on October 22, 2004.

     Gross profit decreased by $222.9 million, or 34%, to $423.4 million in the nine months ended Sept. 30, 2004, primarily due to: i) non-recurring other revenue of $69.4 million recognized in the third quarter of 2003 from the settlement of contract disputes with, and claims against, Enron Corp.; ii) the amortization of $22.9 million in the first nine 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; iii) soft market fundamentals, which caused total spark spread to not increase commensurately with additional plant operating expense and transmission purchase expense, and depreciation costs associated with new power plants coming on-line. During the nine months ended Sept. 30, 2004, financial results were affected by a $285.5 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. Prior year results benefited from recording $52.8 million (in income from unconsolidated investments in power projects) from termination of a power purchase agreement by the Acadia joint venture.

     Other income increased by $241.7 million during the nine months ended Sept. 30, 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 company’s 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. Also, during the nine months ended Sept. 30, 2004, foreign currency transaction losses were $7.5 million, compared to a loss of $36.2 million in the corresponding period in 2003. Calpine recognized a gain of $0.24 per share in the nine months ended Sept. 30, 2004 on the repurchase of certain debt issuances, compared to a gain of $0.25 per share in the same nine-month period in 2003, and loss before discontinued operations and cumulative effect of a change in accounting principle was $167.5 million, or $0.39 per share, in 2004.

     Discontinued operations, net of tax increased by $84.4 million during the nine months ended Sept. 30, 2004, as compared to the same period in 2003, as a result of the sale of oil and gas assets in the United States and Canada 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.

     For the nine months ended Sept. 30, 2004, the company generated 72.5 million megawatt-hours, which equated to a baseload capacity factor of 51%, and realized an average spark spread of $21.19 per megawatt-hour. For the same period in 2003, Calpine generated 62.1 million megawatt-hours, which equated to a capacity factor of 55%, and realized an average spark spread of $23.90 per megawatt-hour.

-more-

CALPINE REPORTS THIRD QUARTER 2004 FINANCIAL AND OPERATING RESULTS
Page 5
Nov. 4, 2004

Liquidity and Finance Program Highlights

     Calpine continues to advance on its announced program to enhance liquidity, address near-term debt maturities and repurchase existing indebtedness. During the past several months, Calpine has:

• Completed the sale of all of its Canadian natural gas reserves and petroleum assets for approximately $625 million and sold its natural gas reserves in the Colorado Piceance Basin and New Mexico San Juan Basin for approximately $223 million. A portion of the net proceeds was used to repay $500 million of the company’s first lien indebtedness.

• Received funding on a preferred equity interest relating to Calpine’s Saltend power plant. Calpine Jersey Limited (Calpine Jersey) issued $360 million of two-year, Redeemable Preferred Shares at U.S. LIBOR, plus 700 basis points. Calpine Jersey is an indirect, wholly owned subsidiary of Calpine. The net proceeds from the offering were loaned to Calpine’s 1,200-megawatt Saltend cogeneration power plant located in Hull, Yorkshire, England, and will be used as permitted by the company’s indentures.

• Completed its $785 million offering of 9.625% first-priority senior secured notes due 2014, offered at 99.212% of par. These notes are secured, directly and indirectly, by substantially all of the assets owned by Calpine, including its natural gas and power assets and the stock of Calpine Energy Services and other subsidiaries. Net proceeds from this offering will be used to redeem or repurchase existing indebtedness through open-market purchases, and as otherwise permitted by the company’s indentures.

• Issued $736 million of 6% unsecured contingent convertible notes due 2014, offered at 83.9% of par. A portion of the net proceeds were used to redeem in full Calpine’s HIGH TIDES I and HIGH TIDES II preferred securities. The balance of net proceeds was used to repurchase $115.0 million of its HIGH TIDES III preferred securities.

• In transactions initiated and completed during the third quarter, the company repurchased $734.8 million of the principal amount of its outstanding debt and its HIGH TIDES preferred securities as listed below:

-	7.625% Senior Notes Due 2006	$	23,845,000
-	8.5% Senior Notes Due 2008		279,770,000
-	7.875% Senior Notes Due 2008		50,000,000
-	4.75% Convertible Senior Notes Due 2023		266,225,000
-	HIGH TIDES III		115,000,000
	Total	$	734,840,000

These securities were repurchased in exchange for $553.8 million in cash.

-more-

CALPINE REPORTS THIRD QUARTER 2004 FINANCIAL AND OPERATING RESULTS
Page 6
Nov. 4, 2004

• During October 2004, the company repurchased an additional $620.8 million of the principal amount of its outstanding debt and its HIGH TIDES preferred securities as listed below:

-	10.5% Senior Notes Due 2006	$	2,230,000
-	7.625% Senior Notes Due 2006		23,000,000
-	8.75% Senior Notes Due 2007		10,820,000
-	8.5% Senior Notes Due 2008		58,500,000
-	8.375% Senior Notes Due 2008		7,750,000
-	7.875% Senior Notes Due 2008		7,000,000
-	8.5% Senior Notes Due 2011		28,000,000
-	HIGH TIDES I		198,500,000
-	HIGH TIDES II		285,000,000
	Total	$	620,800,000

     These securities were repurchased in exchange for $581.1 million in cash.

     On Sept. 30, 2004, the company’s liquidity totaled approximately $2.7 billion. This included cash and cash equivalents on hand of approximately $1.5 billion, current portion of restricted cash of approximately $0.9 billion and approximately $0.3 billion of borrowing capacity under various credit facilities.

Power Plant and Natural Gas Operations

     Calpine’s geographically diversified portfolio of 73 natural gas-fired, combined-cycle power generation facilities represents one of the cleanest and most fuel-efficient fleets in North America. Together with its 19 geothermal power plants, Calpine can deliver 26,489 megawatts of generation to power customers in 21 states, Canada and in the United Kingdom.

     During the quarter, Calpine:

• Operated its natural gas-fired and geothermal power plants with an average plant availability factor of 97.3%, off slightly compared to an 98.1% average availability for the same period a year ago;

• Generated 29.4 million megawatt-hours, a 16% increase over the third quarter of 2003. Through hedging and optimization activity at its Calpine Energy Services subsidiary, the company delivered an additional 25.4 million megawatt-hours;

• Achieved an average heat rate of 7,140 British thermal units per kilowatt-hour, compared to a heat rate of 7,159 for the same period in 2003;

• Lowered plant operating expenses to $5.16 per megawatt-hour (assuming a 70% capacity factor) for the trailing twelve-month period ending Sept. 30, 2004, compared to $5.31 for the same period ending Sept. 30, 2003; and

• Completed construction of the 271-megawatt Goldendale Energy Center, located in Goldendale, Wash.

-more-

CALPINE REPORTS THIRD QUARTER 2004 FINANCIAL AND OPERATING RESULTS
Page 7
Nov. 4, 2004

New Power Contract Opportunities

     Calpine serves more than 100 load-serving, retail and industrial customers across North America and in the United Kingdom. The company is currently pursuing nearly 27,200 megawatts of contract opportunities, with an eight-year weighted average term.

     During the quarter, the company entered into 26 new power contracts, representing approximately 1,400 megawatts of generation for sale to large wholesale customers.

     Through Sept. 30, 2004, the company has signed 67 power contracts. The sales represent approximately 5,700 megawatts of capacity and approximately 224 million megawatt-hours. The weighted average on-peak spark spread for these contracts is approximately $17.00 per megawatt-hour, with a five-year weighted average life.

     Calpine is pursuing additional opportunities in the emerging energy services sector. The company is helping meet the needs of traditional power and retail customers as well as new entrants to the market, including financial and banking institutions. Most recently, Calpine signed an agreement to provide a variety of services – including fuel management, power marketing and gas supply – for three gas-fired, cogeneration power plants in New Jersey.

     Included in the Supplemental Data with 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 on its investor relations page at www.calpine.com.

2004 Earnings and Cash Flow Guidance

     For 2004, the company remains on track to achieve its $1.7 billion of EBITDA, as adjusted for non-cash and other charges. Calpine continues to target breakeven GAAP earnings, with the assumption of additional bond repurchases during the fourth quarter.

Conference Call Information

     Calpine will host a conference call to discuss its financial and operating results for the three and nine months ended Sept. 30, 2004, this morning, Thursday, Nov. 4, 2004, 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 a PowerPoint 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.

About Calpine

     Calpine Corporation, celebrating its 20th year in power, is a North American power company dedicated to providing electric power to customers from clean, efficient, natural gas-fired and geothermal power plants. The company generates power at plants it owns or leases in 21 states in the United States, three provinces in Canada and in the United Kingdom. The company is listed on the S&P 500 and was named FORTUNE’s Most Admired Energy Company in America for 2004. Calpine was founded in 1984 and is publicly traded on the New York Stock Exchange under the symbol CPN. For more information, visit www.calpine.com.

-more-

CALPINE REPORTS THIRD QUARTER 2004 FINANCIAL AND OPERATING RESULTS
Page 8
Nov. 4, 2004

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) changes in legislation and regulation of energy markets and the rules and regulations adopted from time to time 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 dynamic energy markets; (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 its Annual Report on Form 10-K/A, amendment 2, for the year ended Dec. 31, 2003, and its Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, which can also be found on the company’s website at www.calpine.com. This news release includes certain non-GAAP financial measures as defined under SEC rules. As required by SEC rules, we have provided a reconciliation of those measures to the most directly comparable GAAP measures, which can be found in the Supplemental Data tables in this release. 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 CORPORATION AND SUBSIDIARIES
Consolidated Condensed Statements of Operations
For the Three and Nine Months Ended September 30, 2004 and 2003
(unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
	(In thousands, except
	per share amounts)
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue	$	1,671,147		$	1,416,866		$	4,230,004		$	3,563,193
Transmission sales revenue		4,427			3,952			14,152			13,239
Sales of purchased power for hedging and optimization		430,576			843,013			1,307,256			2,269,102
Total electric generation and marketing revenue		2,106,150			2,263,831			5,551,412			5,845,534
Oil and gas production and marketing revenue
Oil and gas sales		17,687			16,578			47,472			45,394
Sales of purchased gas for hedging and optimization		423,733			305,706			1,258,441			961,652
Total oil and gas production and marketing revenue		441,420			322,284			1,305,913			1,007,046
Mark-to-market activities, net		(5,106	)		(11,023	)		(15,192	)		11,259
Other revenue		14,736			81,496			51,573			97,596
Total revenue		2,557,200			2,656,588			6,893,706			6,961,435
Cost of revenue:
Electric generation and marketing expense
Plant operating expense		176,333			183,458			575,830			505,032
Transmission purchase expense		30,803			8,422			61,880			28,578
Royalty expense		8,488			7,022			21,321			18,840
Purchased power expense for hedging and optimization		351,151			835,892			1,171,260			2,254,560
Total electric generation and marketing expense		566,775			1,034,794			1,830,291			2,807,010
Oil and gas operating and marketing expense
Oil and gas operating expense		14,719			15,263			42,864			53,642
Purchased gas expense for hedging and optimization		429,373			293,241			1,243,781			941,312
Total oil and gas operating and marketing expense		444,092			308,504			1,286,645			994,954
Fuel expense		1,097,650			806,598			2,783,570			2,035,285
Depreciation, depletion and amortization expense		149,288			131,001			421,050			373,128
Operating lease expense		25,805			28,439			80,567			84,298
Other cost of revenue		19,187			8,380			68,177			20,501
Total cost of revenue		2,302,797			2,317,716			6,470,300			6,315,176
Gross profit		254,403			338,872			423,406			646,259
Loss (income) from unconsolidated investments in power projects and oil and gas properties		(782	)		(4,110	)		23			(68,584	)
Equipment cancellation and impairment cost		7,820			632			10,187			19,940
Long-term service agreement cancellation charge		7,580			—			7,580			—
Project development expense		3,367			2,979			15,114			14,137
Research and development expense		3,982			2,849			12,921			7,709
Sales, general and administrative expense		58,377			49,426			170,990			142,841
Income from operations		174,059			287,096			206,591			530,216
Interest expense		293,639			198,686			815,357			483,238
Distributions on trust preferred securities		—			15,297			—			46,610
Interest income		(17,185	)		(10,742	)		(39,166	)		(27,780	)
Minority interest expense		9,990			2,569			23,149			10,182
Income from repurchase of various issuances of debt		(167,154	)		(207,238	)		(170,548	)		(214,001	)
Other expense (income)		23,320			9,513			(177,088	)		64,570
Income (loss) before provision (benefit) for income taxes		31,449			279,011			(245,113	)		167,397
Provision (benefit) for income taxes		71,668			41,310			(77,627	)		11,076
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle		(40,219	)		237,701			(167,486	)		156,321

- table continues -

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
	(In thousands, except
	per share amounts)
	(Unaudited)
Discontinued operations, net of tax provision (benefit) of $140,723, $(183), $155,790, and $3,124		62,551			81			89,927			5,550
Cumulative effect of a change in accounting principle, net of tax provision of $—, $—, $—and $450		—			—			—			529
Net income (loss)	$	22,332		$	237,782		$	(77,559	)	$	162,400
Basic earnings (loss) per common share:
Weighted average shares of common stock outstanding		444,380			388,161			425,682			383,447
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle	$	(0.09	)	$	0.61		$	(0.39	)	$	0.40
Discontinued operations, net of tax	$	0.14		$	—		$	0.21		$	0.02
Cumulative affect of a change in accounting principle, net of tax	$	—		$	—		$	—		$	—
Net income (loss)	$	0.05		$	0.61		$	(0.18	)	$	0.42
Diluted earnings per common share:
Weighted average shares of common stock outstanding before dilutive effect of certain convertible securities		444,380			394,950			425,682			388,622
Income (loss) before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle	$	(0.09	)	$	0.60		$	(0.39	)	$	0.40
Dilutive effect of certain convertible securities		—			(0.09	)		—			(0.01	)
Income (loss) before discontinued operations and effect of a change in accounting principle		(0.09	)		0.51			(0.39	)		0.39
Discontinued operations, net of tax		0.14			—			0.21			0.02
Cumulative effect of a change in accounting principle, net of tax		—			—			—			—
Net income (loss)	$	0.05		$	0.51		$	(0.18	)	$	0.41

The financial information presented above and in the Supplemental Data is subject to adjustment until the company files its Form 10-Q with the United States Securities and Exchange Commission for the three and nine months ended September 30, 2004.

- table continues -

CALPINE CORPORATION AND SUBSIDIARIES
Supplemental Data
(unaudited)

CASH FLOW DATA

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
(in thousands)
Cash provided by operating activities	$	224,606		$	58,028		$	236,599		$	171,332
Cash used in investing activities		(221,272	)		(538,778	)		(388,663	)		(1,836,581	)
Cash provided by financing activities		612,934			1,029,175			633,703			2,046,489
Effect of exchange rate changes on cash and cash equivalents		27,523			3,293			14,377			8,946
Net increase in cash and cash equivalents	$	643,791		$	551,718		$	496,016		$	390,186

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
(in thousands)
Cash provided by operating activities	$	224,606		$	58,028		$	236,599		$	171,332
Less: Changes in operating assets and liabilities, excluding the effects of acquisitions		44,679			(229,734	)		(5,255	)		(638,046	)
Less: Additional adjustments to reconcile net income to net cash provided by operating activities, net		(246,953	)		409,488			(308,903	)		629,114
GAAP net income (loss)		22,332			237,782			(77,559	)		162,400
(Income) loss from unconsolidated investments in power projects and oil and gas properties		(782	)		(4,110	)		23			(68,584	)
Distributions from unconsolidated investments in power projects and oil and gas properties		7,566			4,665			22,263			125,680
Subtotal		29,116			238,337			(55,273	)		219,496
Interest expense		293,639			198,686			815,357			483,238
1/3 of operating lease expense		8,602			9,480			26,856			28,099
Distributions on trust preferred securities		—			15,297			—			46,610
Provision (benefit) for income taxes		71,668			41,310			(77,627	)		11,076
Depreciation, depletion and amortization expense		160,000			137,010			470,971			391,870
Interest expense, provision (benefit) for income taxes and depreciation, depletion and income from unconsolidated investments in power projects from discontinued operations		153,517			22,945			218,188			70,698
EBITDA, as adjusted	$	716,542		$	663,065		$	1,398,472		$	1,251,087

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
(in thousands)
EBITDA, as adjusted	$	716,542		$	663,065		$	1,398,472		$	1,251,087
Equipment cancellation and impairment cost		7,820			632			10,187			19,940
Foreign currency transaction (gain) loss		29,036			(8,070	)		24,204			36,234
Unrealized mark-to-market activity loss		23,762			10,930			57,620			18,921
Income from repurchases of various issuances of debt		(167,154	)		(207,238	)		(170,548	)		(214,001	)
Write-off of deferred financing costs (not related to bonds repurchased)		5,976			15,032			25,352			15,032
Long-term service agreement cancellation charge		7,580			—			7,580			—
SFAS No. 123 (stock-based compensation expense)		5,218			3,813			14,508			12,236
Minority interest expense		9,990			2,569			23,149			10,182
Other non-cash and other charges		(1,910	)		—			(2,003	)		3,871
EBITDA, as adjusted, for non-cash and other charges	$	636,860		$	480,733		$	1,388,521		$	1,153,502

- table continues -

SUPPLEMENTARY POWER DATA

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2004		2003		2004		2003
Generation (in MWh, in thousands) (3)		29,390		25,449		72,522		62,069
Average electric price realized (per MWh)	$	59.56	$	55.95	$	60.20	$	57.64
Average spark spread adjusted for benefits of equity gas production (per MWh)	$	21.40	$	23.88	$	21.19	$	23.90

SUPPLEMENTARY EQUIVALENT NATURAL GAS PRODUCTION DATA (4)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2004		2003		2004		2003
(in Bcfe)
Natural Gas Production
United States		9.6		12.3		31.3		40.0
Canada		0.5		3.8		1.4		10.5
Total		10.1		16.1		32.7		50.5
Average daily production rate		110		174		119		185
Average realized price per Mcfe	$	5.98	$	4.84	$	5.88	$	5.33
Average unit cost per Mcfe (excluding interest expense)	$	3.42	$	2.15	$	2.90	$	2.31

CALPINE CONTRACTUAL PORTFOLIO – AS OF SEPTEMBER 30, 2004

	2005			2006			2007			2008			2009
Estimated Generation Capacity
(in millions of MWh)
- Baseload		185.8			210.3			218.0			218.6			218.0
- Peaking		25.5			26.6			27.0			27.0			27.0
Total		211.3			236.9			245.0			245.6			245.0
Contractual Generation
(in millions of MWh)
- Baseload		87.8			66.4			54.1			52.1			49.3
- Peaking		19.6			18.9			18.7			18.0			15.0
Total		107.4			85.3			72.8			70.1			64.3
% Sold
- Baseload		47	%		32	%		25	%		24	%		23	%
- Peaking		77	%		71	%		69	%		67	%		56	%
Total		51	%		36	%		30	%		29	%		26	%
Contractual Spark Spread	$	1,882		$	1,875		$	1,585		$	1,516		$	1,441
(in millions)

- table continues -

	As of			As of
CAPITALIZATION	September 30, 2004			December 31, 2003
Cash and cash equivalents (in billions)	$	1.5		$	1.0
Total debt (in billions)	$	18.4		$	17.7
Debt to capitalization ratio		79	%		78	%
Present value of operating leases (in billions)	$	1.3		$	1.3
Unconsolidated debt of equity method investments (estimated, in billions)(5)		—		$	0.1
(in thousands):
Short-term debt
Notes payable and borrowings under lines of credit, current portion	$	210,603		$	254,292
Notes payable to Calpine Capital Trusts, current portion		636,000			—
Preferred interests, current portion		9,040			11,220
Capital lease obligation, current portion		7,923			4,008
CCFC I financing, current portion		3,208			3,208
Construction/project financing, current portion		62,839			61,900
Convertible Senior Notes Due 2006, current portion		72,126			—
Senior notes and term loans, current portion		198,409			14,500
Total short-term debt		1,200,148			349,128
Long-term debt
Notes payable and borrowings under lines of credit, net of current portion		781,017			873,572
Notes payable to Calpine Capital Trusts, net of current portion		517,500			1,153,500
Preferred interests, net of current portion		138,068			232,412
Capital lease obligation, net of current portion		283,442			193,741
CCFC I financing, net of current portion		783,139			785,781
CalGen/CCFC II financing		2,431,370			2,200,358
Construction/project financing, net of current portion		1,697,540			1,209,505
Convertible Senior Notes Due 2014		617,504			—
Convertible Senior Notes Due 2006, net of current portion		—			660,059
Convertible Senior Notes Due 2023		633,775			650,000
Senior notes, net of current portion		9,339,577			9,369,253
Total long-term debt		17,222,932			17,328,181
Total debt	$	18,423,080		$	17,677,309
Minority interests	$	371,947		$	410,892
Total stockholders’ equity (6)	$	4,645,853		$	4,621,253
Total capitalization	$	23,440,880		$	22,709,454
Debt to capitalization ratio
Total debt	$	18,423,080		$	17,677,309
Total capitalization	$	23,440,880		$	22,709,454
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 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.
(6)	Includes accumulated other comprehensive income (“AOCI”) of $16,456 at September 30, 2004, and $56,594 at December 31, 2003. Excluding AOCI from stockholders’ equity would not change the debt to capitalization ratio for both periods.

###

CALPINE CORPORATION EARNINGS CONFERENCE CALL 3rd QUARTER ENDED SEPTEMBER 30, 2004

CALPINE PARTICIPANTS PETER CARTWRIGHT Chairman, Chief Executive Officer and President BOB KELLY Executive Vice President and Chief Financial Officer PAUL POSOLI Senior Vice President, Calpine Energy Services RICK BARRAZA Senior Vice President, Investor Relations

BUSINESS UPDATE Peter Cartwright Chairman, Chief Executive Officer and President

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 June 30, 2004, which can also be found on our website 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 Form 10-Q with the United States Securities and Exchange Commission for the quarter ended September 30, 2004.

Financial & Operating Results Impacted by Mild Summer Weather Plant Performance Remained Strong High Availability Lower Operating Costs Per mwh Significant Progress on Liquidity & Refinancing Completed Sale of Gas Reserves Redeemed High Tides I and II Continue to Target 2004 EBITDA of $1.7 Billion and Break-Even Earnings BUSINESS UPDATE 3RD QUARTER HIGHLIGHTS

BUSINESS UPDATE 2004 ELECTRICITY CONSUMPTION Source: Edison Electric Institute and Company Data Electricity Consumption in 2004 vs 2003 United States Total 3rd Quarter: .5% United States Total YTD 10/23/04: 1.8% PACIFIC SOUTHWEST SOUTH CENTRAL SOUTHEAST NEW ENGLAND

BUSINESS UPDATE MARKETING AND SALES PROGRAM Continue to Focus Aggressively on New Power Contracts Contracts Executed YTD Through September 30, 2004 67 Contracts (41 YTD 2003) 5,700 mw (4,900 mw YTD 2003) 244.3 Million mwh 5-yr. Weighted Average Life $17 Weighted Average On-Peak Spark Spread Pursuing Contract Opportunities in Excess of 27,000 mw ERCOT FRCC MAPP NEPOOL NYPOOL PJM SERC SPP MAIN WECC 34.9 5 6.7 7 2 3.5 14.8 0.9 4.3 20.9 Contracts Executed YTD Through September 30, 2004

Clear Direction for a Strong, Competitive Market Governor Focused on California's Energy Supply Veto of AB2006 CA PUC Action Requiring Utilities to Secure Additional Power by 3rd Quarter 2006 Recent Utility RFOs Strong Market Fundamentals Numerous Record-Setting Days for Peak Energy Consumption Reserve Margins Declining Potential Plant Retirements Calpine Well-Positioned in California 39 Projects, 3,823 mw in Operation 3 Projects, 1,964 mw in Construction 4 Projects, 3,470 mw Permitted BUSINESS UPDATE CALIFORNIA POWER MARKET

BUSINESS UPDATE CONSTRUCTION PROGRAM 11 Projects, 5,480 mw 6 Projects with Long-Term Contracts 2 Projects Uncontracted in California 3 Projects Uncontracted in Discretionary Construction Phase Future Construction When Long-Term Contracts are in Place When Project Financing is Available (1) Does Not Include Approximately $350 Million of Discretionary Capital for Three Projects 2005 2006 2007 Total Construction Capital (1) $525 $250 $ 50 Estimated Construction Financing 475 250 50 Net Construction Capital to Calpine $ 50 $ 0 $ 0

FINANCIAL & OPERATING RESULTS 3rd QUARTER 2004 Bob Kelly Executive Vice President and Chief Financial Officer

(In millions, except EPS) (In millions, except EPS) (In millions, except EPS) 3rd Quarter Ended Sept. 30, 2004 9 Months Ended Sept. 30, 2004 Revenue $ 2,557.2 $ 6,893.7 GAAP Net Income (Loss) $ 22.3 $ (77.6) GAAP Fully Diluted Earnings Per Share $ 0.05 $ (0.18) Earnings Per Share, Adjusted for Tax Charge $ 0.20 $ (0.03) Operating Cash Flow $ 224.6 $ 236.6 EBITDA, as Adjusted for Non-Cash and Other Charges(1) $ 636.9 $ 1,388.5 EBITDA, as Adjusted for Non-Cash and Other Charges to Interest Expense(2) 2.11x 1.65x 3rd QTR 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.

3rd QTR 2004 FINANCIAL RESULTS SPARK SPREADS 3rd Quarter 3rd Quarter 3rd Quarter 9 Months 9 Months 9 Months 2004 2003 2004 2003 Average Megawatts in Operation Average Megawatts in Operation 26,242 22,079 24,514 20,225 Megawatt-Hours Generated (000s) Megawatt-Hours Generated (000s) 29,390 25,449 72,522 62,069 Megawatt-Hours Delivered (000s) Megawatt-Hours Delivered (000s) 54,848 48,167 138,463 122,955 Spark Spread Spark Spread Total (000s) $ 629,003 $ 607,738 $ 1,536,907 $ 1,483,706 Per mwh $ 21.40 $ 23.88 $ 21.19 $ 23.90

3rd QTR 2004 FINANCIAL RESULTS POWER PLANT STATISTICS 3rd Quarter 3rd Quarter 3rd Quarter 9 Months 9 Months 9 Months 2004 2003 2004 2003 Megawatt-Hours Generated (000s) Megawatt-Hours Generated (000s) 29,390 25,449 72,522 62,069 Plant Availability Factor Plant Availability Factor 97.3% 98.1% 92.7% 91.1% Plant Baseload Capacity Factor Plant Baseload Capacity Factor 56.2% 59.9% 51.3% 54.5% Average Heat Rate (btu / kwh) Average Heat Rate (btu / kwh) 7,140 7,159 7,152 7,202

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Regular Operating Expense 5.34 5.19 5.01 5.1 4.9 4.79 4.51 Major Maintenance Expense 0.27 0.25 0.3 0.38 0.43 0.7 0.65 3rd QTR 2004 FINANCIAL RESULTS PLANT OPERATING EXPENSES 2003 2004 (per mwh) Trailing 12-Month Plant Operating Expenses at an Assumed 70% Capacity Factor(1) $5.16 Record Low

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

POWER MARKETS & CES UPDATE POSITIVE MOVEMENT IN SPARK SPREADS Spark Spreads Trending Up 3rd Quarter 3rd Quarter 3rd Quarter 2nd Quarter 2nd Quarter 2nd Quarter 1st Quarter 1st Quarter 1st Quarter 2004 2003 2004 2003 2004 2003 NP15 $ 19.26 $ 18.56 $ 13.42 $ 8.59 $ 7.71 $ 13.08 ERCOT 12.97 11.90 12.06 15.26 5.39 11.00 Southeast 10.32 7.43 9.54 0.54 1.33 5.95 NEPOOL 12.37 14.33 15.13 9.90 12.82 11.89 Note: Figures Represent Average On-Peak, Day-Ahead Spark Spreads Source: Company Data

POWER MARKETS & CES UPDATE MILD SUMMER WEATHER Source: National Oceanic And Atmospheric Administration

POWER MARKETS & CES UPDATE MARKET FUNDAMENTALS Expect Continued Growth in Electricity Consumption Limited Sources of New Supply Expect Competitive Markets to Act Economically Additional Cost of Coal Emissions

POWER MARKETS & CES UPDATE IMPACT OF MOVE IN NATURAL GAS PRICES Contractual Portfolio Fixed-Price Contracts (25%) - Managed Through Equity Reserves and Gas Hedges Variable Heat Rate Contracts (75%) - Rising Gas Cost Passed Through to Customers Open Portfolio: On-Peak Gas Price / mmbtu Gas Price / mmbtu Gas Price / mmbtu $ 6.00 $ 8.00 Price-Setting Gas-Fired Plant, 9,000 Heat Rate $ 54 $ 72 Modern Calpine Gas-Fired Plant, 7,000 Heat Rate 42 56 Spark Spread / mwh $ 12 $ 16 Current Example 9/30/04 11/02/04 Change NP15 Spark Spread (mwh) $ 15.67 $ 17.72 $ 2.05 PG&E City Gate Gas (mmbtu) $ 6.80 $ 7.60 $ 0.80

FINANCIAL UPDATE Bob Kelly Executive Vice President and Chief Financial Officer

Transactions Completed to Date $ 2,000 Potential Transactions Contract Monetization 500 Project Financing 350 Preferred Interests Deer Park 200 Total 2004 Liquidity Transactions $ 3,050 (In millions) 3rd QTR 2004 FINANCIAL UPDATE UPDATE ON LIQUIDITY TRANSACTIONS

3rd QTR 2004 FINANCIAL UPDATE CAPITAL MARKETS TRANSACTIONS $785 Million First-Priority Senior Secured Notes 9.625% Fixed Rate Proceeds to Repurchase Debt $736 Million Unsecured Convertible Notes 6% Fixed Rate Convertible to Cash & Common With Conversion Price of $3.85 Per Share Utilized Innovative Share Lending Facility Use of Proceeds Fully Redeem High Tides I; $198.5 Million Fully Redeem High Tides II; $285.0 Million Redeem Portion of High Tides III; $115.0 Million

3rd QTR 2004 FINANCIAL UPDATE $736 MILLION UNSECURED CONVERTIBLE NOTES Share Lending Agreement Loaned Stock To Deutsche Bank Facilitate Hedging Activity Stock Returned to Calpine by Year Ten No Impact on Dilutive EPS Net Share Settle Calpine Stock Price Calpine Stock Price Calpine Stock Price Calpine Stock Price Calpine Stock Price Calpine Stock Price Calpine Stock Price Calpine Stock Price Calpine Stock Price $3.00 $4.00 $5.00 $6.00 $7.00 6% Unsecured Convertible Notes (1) - 7.2 44.0 68.5 86.0 Repurchased 4.75% Notes - - - - (2.9) Redeemed High Tides - - (27.5) (27.5) (27.5) Impact to Dilutive Shares Outstanding - - 16.5 41.0 55.6 - % - % 3.6%(2) 8.4%(2) 11.1%(2) (1) Assumes cash used at conversion for $1,000 principal value (2) Based on 445 million shares currently outstanding

3rd QTR 2004 FINANCIAL UPDATE DEBT REPURCHASES (In thousands) (In thousands) (In thousands) (In thousands) (In thousands) (In thousands) (In thousands) 3rd Quarter 3rd Quarter 3rd Quarter 4th Quarter(1) 4th Quarter(1) 4th Quarter(1) Securities Face Amount Amount Paid Face Amount Amount Paid 10.5% Senior Notes Due 2006 $ - $ $ 2,230 $ 7.625% Senior Notes Due 2006 23,845 23,000 8.75% Senior Notes Due 2007 - 10,820 8.5% Senior Notes Due 2008 279,770 58,500 8.375% Senior Notes Due 2008 - 7,750 7.875% Senior Notes Due 2008 50,000 7,000 8.5% Senior Notes Due 2011 - 28,000 4.75% Convertible Senior Notes Due 2023 266,225 - Total Debt 619,840 442,220 137,300 97,605 High Tides I - 198,500 High Tides II - 285,000 High Tides III 115,000 111,550 - Total High Tides 115,000 111,550 483,500 483,500 Total $ 734,840 $ 553,770 $ 620,800 $ 581,105 (1) Includes all repurchases settled prior to 10/31/2004.

3rd QTR 2004 FINANCIAL UPDATE ADDRESSING NEAR-TERM DEBT MATURITIES (1) 2004 2005 2006 2007 2008 Project Financing 36.5 Second Priority 1209.3 Senior Unsecured 186.1 324.5 372.8 1980.2 Debt Repurchased Since 1/1/03 63.9 97.3 28.8 613.8 (In millions) (1) Does not include scheduled principal payments. Includes debt repurchased settled prior to 10/31/2004. Outstanding Senior Unsecured Notes Due 2005-2007 $883.4 Million Project Financing Second Priority Senior Unsecured Debt Repurchased Since 1/1/03

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 10/1-12/31 2004 2005 2006 2007 2008 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 97.6 158.6 462.3 Power Contract Financing 50.5 85.0 - - - - - 85.0 85.0 Gilroy Note 127.3 127.3 1.8 7.8 8.6 9.6 10.6 88.9 127.3 Siemens 13.0 13.0 13.0 - - - - - 13.0 BPA Monetization 58.0 58.0 5.7 22.9 23.4 6.0 - - 58.0 Calpine Commercial Trust 34.5 38.1 2.4 8.4 8.4 8.4 6.3 4.2 38.1 Miscellaneous 20.0 20.0 2.2 14.0 0.6 0.9 0.3 2.0 20.0 Notes Payable $ 991.6 $ 1,029.7 $ 25.1 $ 201.2 $ 196.8 $ 153.1 $ 114.8 $ 338.7 $ 1,029.7 Preferred Interests Auburndale Power Plant $ 79.7 $ 79.7 $ 0.6 $ 1.0 $ 0.7 $ 1.5 $ 3.9 $ 72.0 $ 79.7 Gilroy Energy Center 67.4 67.4 - 7.6 8.8 7.5 8.3 35.2 67.4 Preferred Interests $ 147.1 $ 147.1 $ 0.6 $ 8.6 $ 9.5 $ 9.0 $ 12.2 $ 107.2 $ 147.1 Capital Lease Obligations Hidalgo Energy Center $ 101.8 $ 101.8 $ - $ - $ 1.2 $ 1.3 $ 3.2 $ 96.1 $ 101.8 King City Power Plant 97.3 97.3 3.4 1.2 1.2 1.5 1.4 88.6 97.3 Stony Brook Power Plant 63.8 72.7 - 1.0 1.2 1.5 1.7 67.3 72.7 Agnews Power Plant 27.0 27.0 - 2.8 3.0 3.3 3.7 14.2 27.0 Corporate 0.9 0.9 0.2 0.6 0.1 - - - 0.9 Calpine Natural Gas 0.6 0.6 0.1 0.2 0.2 0.1 - - 0.6 Capital Lease Obligations $ 291.4 $ 300.3 $ 3.7 $ 5.8 $ 6.9 $ 7.7 $ 10.0 $ 266.2 $ 300.3 As of September 30, 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 10/1-12/31 2004 2005 2006 2007 2008 Thereafter Total CCFC I Term Loan Notes Due 2009 $ 378.0 $ 381.1 $ - $ 3.9 $ 3.9 $ 3.9 $ 3.9 $ 365.5 $ 381.1 Floating Rate Notes Due 2011 408.3 415.0 - - - - - 415.0 415.0 CCFC I $ 786.3 $ 796.1 $ - $ 3.9 $ 3.9 $ 3.9 $ 3.9 $ 780.5 $ 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 631.3 640.0 - - - - 3.2 636.8 640.0 Term Loan Notes Due 2010 98.6 100.0 - - - - 0.5 99.5 100.0 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 36.5 36.5 - - - 36.5 - - 36.5 CalGen $ 2,431.4 $ 2,441.5 $ - $ - $ - $ 40.7 $ 12.1 $ 2,388.7 $ 2,441.5 Project Financing Gilroy Energy Center $ 261.2 $ 264.0 $ - $ 38.9 $ 40.1 $ 34.6 $ 37.0 $ 113.4 $ 264.0 Broad River Energy Center 279.9 279.9 4.8 9.9 12.1 14.2 16.6 222.3 279.9 Pasadena Power Plant 282.9 282.9 - 0.7 6.8 13.1 15.7 246.6 282.9 Riverside Energy Center 368.5 368.5 - 3.7 3.7 3.7 3.7 353.7 368.5 Blue Spruce Energy Center 119.8 119.8 - 1.9 3.8 3.8 3.8 106.5 119.8 Rocky Mountain Energy Center 264.9 264.9 - 2.6 2.6 2.6 2.6 254.5 264.9 Aries Power Plant 176.2 176.2 1.3 8.1 9.9 10.6 10.7 135.6 176.2 Otay Mesa Energy Center 7.0 7.0 - - - - - 7.0 7.0 Project Financing $ 1,760.4 $ 1,763.2 $ 6.1 $ 65.8 $ 79.0 $ 82.6 $ 90.1 $ 1,439.6 $ 1,763.2 As of September 30, 2004 (In millions)

APPENDIX B: OUTSTANDING DEBT & PRINCIPAL PAYMENT SCHEDULES (continued) Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Principal Payments Security Balance Sheet Value Outstanding Amount 10/1-12/31 2004 2005 2006 2007 2008 Thereafter Total First Priority Senior Secured Notes 9.625% Senior Secured Notes Due 2014 $ 778.9 $ 785.0 $ - $ - $ - $ - $ - $ 785.0 $ 785.0 First Priority Senior Secured Notes 778.9 785.0 - - - - - 785.0 785.0 Second Priority Senior Secured Notes Term Loan B Notes Due 2007 $ 742.5 $ 742.5 $ 1.9 $ 7.5 $ 7.5 $ 725.6 $ - $ - $ 742.5 Floating Rate Notes Due 2007 495.0 495.0 1.3 5.0 5.0 483.7 - - 495.0 8.5% Senior Notes Due 2010 1,150.0 1,150.0 - - - - - 1,150.0 1,150.0 9.875% Senior Notes Due 2011 392.9 400.0 - - - - - 400.0 400.0 8.75% Senior Notes Due 2013 900.0 900.0 - - - - - 900.0 900.0 Second Priority Senior Secured Notes $ 3,680.4 $ 3,687.5 $ 3.2 $ 12.5 $ 12.5 $ 1,209.3 $ - $ 2,450.0 $ 3,687.5 Convertible Unsecured Senior Notes 4.0% Convertible Senior Notes Due 2006 $ 72.1 $ 72.1 $ - $ - $ 72.1 $ - $ - $ - $ 72.1 6.0% Convertible Senior Notes Due 2014 617.5 736.0 - - - - - 736.0 736.0 4.75% Convertible Senior Notes Due 2023 633.8 633.8 - - - - - 633.8 633.8 Convertible Unsecured Senior Notes $ 1,323.4 $ 1,441.9 $ - $ - $ 72.1 $ - $ - $ 1,369.8 $ 1,441.9 As of September 30, 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 10/1-12/31 2004 2005 2006 2007 2008 Thereafter Total Unsecured Senior Notes 8.25% Senior Notes Due 2005 $ 185.9 $ 186.1 $ - $ 186.1 $ - $ - $ - $ - $ 186.1 7.625% Senior Notes Due 2006 190.8 190.8 - - 190.8 - - - 190.8 10.5% Senior Notes Due 2006 158.9 158.9 - - 158.9 - - - 158.9 8.75% Senior Notes Due 2007 157.0 157.5 - - - 157.5 - - 157.5 8.75% Senior Notes Due 2007 226.1 226.1 - - - 226.1 - - 226.1 7.875% Senior Notes Due 2008 255.4 255.7 - - - - 255.7 - 255.7 8.375% Senior Notes Due 2008 150.9 150.9 - - - - 150.9 - 150.9 8.5% Senior Notes Due 2008 1,645.8 1,646.9 - - - - 1,646.9 - 1,646.9 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 1,172.3 1,196.5 - - - - - 1,196.5 1,196.5 8.875% Senior Notes Due 2011 217.1 218.5 - - - - - 218.5 218.5 Unsecured Senior Notes $ 5,078.7 $ 5,106.8 $ - $ 186.1 $ 349.7 $ 383.6 $ 2,053.5 $ 2,133.9 $ 5,106.8 Notes Payable to Calpine Capital Trust High Tides I (1) $ 276.0 $ 198.5 $ - $ - $ - $ - $ - $ 198.5 $ 198.5 High Tides II (1) 360.0 285.0 - - - - - 285.0 285.0 High Tides III 517.5 402.5 - - - - - 402.5 402.5 Notes Payable to Calpine Capital Trust 1,153.5 886.0 - - - - - 886.0 886.0 Total Debt $ 18,423.1 $ 18,385.1 $ 38.7 $ 483.9 $ 730.4 $ 1,889.9 $ 2,296.5 $ 12,946.2 $ 18,385.1 Scheduled Principal Payments $ 38.7 $ 297.8 $ 308.6 $ 260.5 $ 243.0 Final Principal Payments - 186.1 421.8 1,629.4 2,053.5 Total $ 38.7 $ 483.9 $ 730.4 $ 1,889.9 $ 2,296.5 APPENDIX B: OUTSTANDING DEBT & PRINCIPAL PAYMENT SCHEDULES (continued) As of September 30, 2004 (In millions) (1) Notes were redeemed in full on Oct. 20, 2004

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 751.0 787.0 100.0% 751.0 787.0 Jul-98 231 mw, 240 mw; Jun-00 520 mw, 547 mw Magic Valley Generating Station (CCFC I) Texas Natural Gas 700.0 751.0 100.0% 700.0 751.0 Feb-02 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 465.0 471.0 100.0% 465.0 471.0 May-87 / 50% Jun-97, 50% Apr-98 Hidalgo Energy Center Texas Natural Gas 502.0 502.0 78.5% 394.1 394.1 Jun-00 Clear Lake Power Plant Texas Natural Gas 335.0 412.0 100.0% 335.0 412.0 Jan-85 / 50% Jun-97, 50% Apr-98 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 Total ERCOT 6,700.0 7,475.0 6,592.1 7,367.1 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 143.0 153.0 30.0% 42.9 45.9 Jul-94 / Oct-97 Auburndale Peaking Energy Center Florida Natural Gas - 115.0 100.0% - 115.0 Aug-02 Total FRCC 673.0 877.0 572.9 769.9 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 89.0 118.0 100.0% 89.0 118.0 Jun-91 / 80% Dec-99, 20% Mar-04 Grays Ferry Power Plant (1) Pennsylvania Natural Gas 143.0 148.0 50.0% 71.5 74.0 Jan-98 / 40% Dec-99, 10% Mar-04 Newark Power Plant New Jersey Natural Gas 47.0 58.0 100.0% 47.0 58.0 Nov-90 / 80% Dec-99, 20% Mar-04 Philadelphia Water Project Pennsylvania Natural Gas 22.0 23.0 83.0% 18.3 19.1 Jan-95 / 66.4% Dec-99, 16.6% Mar-04 Total MAAC 862.0 931.0 786.8 853.1 MAIN Riverside Energy Center Wisconsin Natural Gas 518.0 602.0 100.0% 518.0 602.0 Jun-04 RockGen Energy Center Wisconsin Natural Gas - 460.0 100.0% - 460.0 May-01 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 Morris Power Plant Illinois Natural Gas 155.0 177.5 100.0% 155.0 177.5 Nov-98 127.5 mw; Mar-00 50 mw / 86% Dec-99, 14% Mar-04 Total MAIN 673.0 1,752.5 673.0 1,752.5

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 Rumford Power Plant Maine Natural Gas 263.0 263.0 100.0% 263.0 263.0 Dec-00 Tiverton Power Plant Rhode Island Natural Gas 240.0 240.0 100.0% 240.0 240.0 Oct-00 Dighton Power Plant Massachusetts Natural Gas 162.0 168.0 100.0% 162.0 168.0 Jul-99 Androscoggin Energy Center Maine Natural Gas 160.0 160.0 32.3% 51.7 51.7 Jan-00 / Oct-00 Total NEPOOL 1,353.0 1,359.0 1,244.7 1,250.7 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 95.0 105.0 100.0% 95.0 105.0 Feb-95 / Dec-97 Bethpage Power Plant New York Natural Gas 52.0 53.7 100.0% 52.0 53.7 Aug-89 / Dec-97 Bethpage Peaker New York Natural Gas - 48.0 100.0% - 48.0 Jul-02 Stony Brook Power Plant New York Natural Gas 45.0 47.0 100.0% 45.0 47.0 Apr-95 / Dec-97 Total NYPOOL 192.0 253.7 192.0 253.7 SERC Acadia Energy Center Louisiana Natural Gas 1,080.0 1,160.0 50.0% 540.0 580.0 Aug-02 Broad River Energy Center South Carolina Natural Gas - 840.0 100.0% - 840.0 Jun-00 540 mw; Aug-01 300 mw / Oct-00 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 Carville Energy Center (CalGen) Louisiana Natural Gas 455.0 531.0 100.0% 455.0 531.0 Jun-03 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 Columbia Energy Center (CalGen) South Carolina Natural Gas 464.0 641.0 100.0% 464.0 641.0 May-04 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 246.6 246.6 100.0% 246.6 246.6 Jul-01 Pine Bluff Energy Center Arkansas Natural Gas 213.3 213.3 100.0% 213.3 213.3 Sep-01 Total SERC 4,223.9 5,585.9 3,683.9 5,005.9

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 Aries Power Project Missouri Natural Gas 523.0 585.0 100.0% 523.0 585.0 Jun-01 320 mw; Feb-02 196 mw, 271 mw 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 Pryor Power Plant Oklahoma Natural Gas 109.0 124.0 100.0% 109.0 124.0 Oct-88 / 80% Dec-99, 20% Mar-04 Total SPP 1,626.0 1,703.0 1,626.0 1,703.0 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 479.0 601.0 100.0% 479.0 601.0 May-04 South Point Energy Center Arizona Natural Gas 520.0 530.0 100.0% 520.0 530.0 Jun-01 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 Blue Spruce Energy Center Colorado Natural Gas - 300.0 100.0% - 300.0 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 - 180.0 100.0% - 180.0 Mar-03 Gilroy Peaking Energy Center California Natural Gas - 135.0 100.0% - 135.0 Feb-02 Gilroy Power Plant California Natural Gas 112.0 131.0 100.0% 112.0 131.0 Mar-88 / Aug-96 Calgary Energy Centre Alberta Natural Gas 250.0 300.0 30.0% 75.0 90.0 Mar-03 McCabe #5 & #6 California Geothermal 75.0 75.0 100.0% 75.0 75.0 Dec-71 / May-99 Ridge Line #7 & #8 California Geothermal 72.0 72.0 100.0% 72.0 72.0 Jan-72 / May-99 Pittsburg Power Plant California Natural Gas 64.0 71.0 100.0% 64.0 71.0 Jan-65 / Jul-98 Calistoga California Geothermal 70.0 70.0 100.0% 70.0 70.0 Apr-84 / Oct-99 Island Cogeneration British Columbia Natural Gas 230.0 230.0 30.0% 69.0 69.0 May-02 Quicksilver California Geothermal 61.0 61.0 100.0% 61.0 61.0 Jan-85 / May-99 Big Geysers California Geothermal 70.0 70.0 100.0% 70.0 70.0 Jan-80 / 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 Socrates California Geothermal 51.0 51.0 100.0% 51.0 51.0 Jan-83 / May-99 Cobb Creek California Geothermal 53.0 53.0 100.0% 53.0 53.0 Jan-79 / May-99 Greenleaf 2 Power Plant California Natural Gas 50.0 50.0 100.0% 50.0 50.0 Dec-89 / Apr-95 Greenleaf 1 Power Plant California Natural Gas 50.0 50.0 100.0% 50.0 50.0 Mar-89 / Apr-95

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 King City Power Plant California Natural Gas 103.0 115.0 40.0% 41.2 46.0 Apr-89 / Apr-96 Grant California Geothermal 40.0 40.0 100.0% 40.0 40.0 Oct-85 / May-99 King City Energy Center California Natural Gas - 45.0 100.0% - 45.0 Feb-02 Yuba City Energy Center California Natural Gas - 45.0 100.0% - 45.0 Jul-02 Feather River Energy Center California Natural Gas - 45.0 100.0% - 45.0 Dec-02 Lambie Energy Center California Natural Gas - 45.0 100.0% - 45.0 Jan-03 Goose Haven Energy Center California Natural Gas - 45.0 100.0% - 45.0 Jan-03 Creed Energy Center California Natural Gas - 45.0 100.0% - 45.0 Jan-03 Riverview Energy Center California Natural Gas - 45.0 100.0% - 45.0 May-03 Wolfskill Energy Center California Natural Gas - 45.0 100.0% - 45.0 Mar-03 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 26.5 28.6 100.0% 26.5 28.6 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 5,277.5 6,765.6 4,879.7 6,325.6 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 22,830.4 27,952.7 21,458.6 26,489.0 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-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 235.0 305.0 100.0% 235.0 305.0 Jun-05 Fox Energy Center, Phase 2 Wisconsin Natural Gas 245.0 245.0 100.0% 245.0 245.0 Dec-05 Total MAIN 480.0 550.0 480.0 550.0 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 5,158.9 5,768.9 4,870.2 5,480.2

APPENDIX C: PROJECT PORTFOLIO SUMMARY & ASSETS BY REGION OPERATING OPERATING CONSTRUCTION CONSTRUCTION OPERATING + CONSTRUCTION OPERATING + CONSTRUCTION OPERATING + CONSTRUCTION Region Total Net Interest with Peaking % Total Net Interest with Peaking % Total Net Interest with Peaking % 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) 7,367.1 27.8% 250.0 4.6% 7,617.1 23.8% FRCC (Florida Reliability Coordinating Council) FRCC (Florida Reliability Coordinating Council) FRCC (Florida Reliability Coordinating Council) 769.9 2.9% - 0.0% 769.9 2.4% MAAC (Mid-Atlantic Area Council) MAAC (Mid-Atlantic Area Council) MAAC (Mid-Atlantic Area Council) 853.1 3.2% - 0.0% 853.1 2.7% MAPP (Mid-Continent Area Power Pool) MAPP (Mid-Continent Area Power Pool) MAPP (Mid-Continent Area Power Pool) - 0.0% 365.0 6.7% 365.0 1.1% MAIN (Mid-America Interconnected Network) MAIN (Mid-America Interconnected Network) MAIN (Mid-America Interconnected Network) 1,752.5 6.6% 550.0 10.0% 2,302.5 7.2% NPCC-NE (Northeast Power Coordinating Council, New England) NPCC-NE (Northeast Power Coordinating Council, New England) NPCC-NE (Northeast Power Coordinating Council, New England) 1,250.7 4.7% - 0.0% 1,250.7 3.9% 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) 253.7 1.0% 79.9 1.5% 333.6 1.0% SERC (Southeastern Electric Reliability Council) SERC (Southeastern Electric Reliability Council) SERC (Southeastern Electric Reliability Council) 5,005.9 18.9% 1,335.0 24.4% 6,340.9 19.8% SPP (Southwest Power Pool) SPP (Southwest Power Pool) SPP (Southwest Power Pool) 1,703.0 6.4% - 0.0% 1,703.0 5.3% WECC (Western Electricity Coordinating Council) WECC (Western Electricity Coordinating Council) WECC (Western Electricity Coordinating Council) 6,325.6 23.9% 1,964.0 35.8% 8,289.6 25.9% United Kingdom United Kingdom United Kingdom 1,200.0 4.5% - 0.0% 1,200.0 3.8% Mexico Mexico Mexico - 0.0% 236.3 4.3% 236.3 0.0% TOTAL CALPINE 26,489.0 100.0% 5,480.2 100.0% 31,969.1 100.0% # of Projects Total Baseload Capacity (mw) Total Capacity with Peaking (mw) Total Net Interest Baseload (mw) Total Net Interest with Peaking (mw) Total Operating - Natural Gas Total Operating - Natural Gas Total Operating - Natural Gas 73 22,080.4 27,202.7 20,708.6 25,739.0 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 5,158.9 5,768.9 4,870.2 5,480.2 Total Project Portfolio 103 27,989.3 33,721.6 26,328.7 31,969.1 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) 22,637.4 27,754.7 21,379.6 26,407.5

APPENDIX D: CONTRACTUAL PORTFOLIO SUMMARY 149 Contracts / 100 Customers Weighted Average Credit: BBB+ 7-Year Weighted Average Life

APPENDIX D: CONTRACTUAL PORTFOLIO CONTRACT TYPE 2005 2006 2007 2008 2009 Fixed Price 29% 22% 19% 18% 19% Heat Rate 70% 75% 75% 76% 75% Other 1% 3% 6% 6% 6%

APPENDIX D: CONTRACTUAL PORTFOLIO DEFINITIONS The following detailed reports represent several data points for Calpine's power generation portfolio as of September 30, 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 D: CONTRACTUAL PORTFOLIO DEFINITIONS (continued) Contractual Generation This represents in millions of megawatt hours, the baseload and peaking generation under contract. For those contracts that are take or pay, the contractual generation estimate assumes the customers take 100% of the contracted power. Contracts Announced / Signed Subsequent to September 30, 2004 Contracts that have been announced and, or signed subsequent to September 30, 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 D: CONTRACTUAL PORTFOLIO TOTAL 2005 2006 2007 2008 2009 Estimated Generation (In Millions of mwh) - Baseload 185.8 210.3 218.0 218.6 218.0 - Peaking 25.5 26.6 27.0 27.0 27.0 Total 211.3 236.9 245.0 245.6 245.0 Contractual Generation (In Millions of mwh) - Baseload 87.8 66.4 54.1 52.1 49.3 - Peaking 19.6 18.9 18.7 18.0 15.0 Total 107.4 85.3 72.8 70.1 64.3 % Sold - Baseload 47% 32% 25% 24% 23% - Peaking 77% 71% 69% 67% 56% Total 51% 36% 30% 29% 26% Contractual Spark Spread $1,882 $1,875 $1,585 $1,516 $1,441 (In Millions) Data as of 9/30/04

APPENDIX D: CONTRACTUAL PORTFOLIO WECC Estimated Generation (In Millions of mwh) - Baseload 49.5 56.0 58.1 58.2 58.1 - Peaking 6.7 6.9 7.0 7.0 7.0 Total 56.2 62.9 65.1 65.2 65.1 Contractual Generation (In Millions of mwh) - Baseload 30.2 26.2 24.1 24.2 23.4 - Peaking 4.9 4.2 4.1 4.1 4.1 Total 35.1 30.4 28.2 28.3 27.5 % Sold - Baseload 61% 47% 42% 42% 40% - Peaking 74% 61% 58% 58% 58% Total 63% 48% 43% 43% 42% 2005 2006 2007 2008 2009 Data as of 9/30/04

APPENDIX D: CONTRACTUAL PORTFOLIO ERCOT Estimated Generation (In Millions of mwh) - Baseload 54.9 56.3 56.4 56.6 56.4 - Peaking 2.0 2.2 2.2 2.2 2.2 Total 56.9 58.5 58.6 58.8 58.6 Contractual Generation (In Millions of mwh) - Baseload 29.0 19.1 8.6 8.1 8.1 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 29.0 19.1 8.6 8.1 8.1 % Sold - Baseload 53% 34% 15% 14% 14% - Peaking 0% 0% 0% 0% 0% Total 51% 33% 15% 14% 14% 2005 2006 2007 2008 2009 Data as of 9/30/04

APPENDIX D: CONTRACTUAL PORTFOLIO NORTHEAST Estimated Generation (In Millions of mwh) - Baseload 18.2 18.5 18.5 18.5 18.5 - Peaking 0.4 0.4 0.4 0.4 0.4 Total 18.6 18.9 18.9 18.9 18.9 Contractual Generation (In Millions of mwh) - Baseload 6.0 2.4 2.2 1.9 1.8 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 6.0 2.4 2.2 1.9 1.8 % Sold - Baseload 33% 13% 12% 10% 10% - Peaking 0% 0% 0% 0% 0% Total 32% 13% 12% 10% 10% 2005 2006 2007 2008 2009 Data as of 9/30/04 Includes the Following NERC Regions: NEPOOL, NYPOOL, MAAC, NPCC

APPENDIX D: CONTRACTUAL PORTFOLIO SOUTHEAST Estimated Generation (In Millions of mwh) - Baseload 25.4 29.3 31.3 31.4 31.3 - Peaking 8.7 8.8 8.8 8.9 8.8 Total 34.1 38.1 40.1 40.3 40.1 Contractual Generation (In Millions of mwh) - Baseload 9.6 9.8 8.4 7.2 5.4 - Peaking 6.6 6.6 6.6 6.6 6.6 Total 16.2 16.4 15.0 13.8 12.0 % Sold - Baseload 38% 34% 27% 23% 17% - Peaking 76% 74% 74% 74% 74% Total 47% 43% 37% 34% 30% 2005 2006 2007 2008 2009 Data as of 9/30/04 Includes the Following NERC Regions: SERC, FRCC

APPENDIX D: CONTRACTUAL PORTFOLIO MIDWEST Estimated Generation (In Millions of mwh) - Baseload 27.9 39.0 41.8 41.8 41.8 - Peaking 7.7 8.4 8.5 8.6 8.5 Total 35.6 47.4 50.3 50.4 50.3 Contractual Generation (In Millions of mwh) - Baseload 8.1 5.9 8.1 7.9 7.9 - Peaking 7.7 8.1 8.1 7.4 4.4 Total 15.8 14.0 16.2 15.3 12.3 % Sold - Baseload 29% 15% 19% 19% 19% - Peaking 100% 97% 95% 86% 51% Total 45% 29% 32% 30% 24% 2005 2006 2007 2008 2009 Data as of 9/30/04 Includes the Following NERC Regions/Sub-Region: MAPP, MAIN, ECAR, SPP and Entergy

APPENDIX D: 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 4.9 1.9 0.7 0.7 0.7 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 4.9 1.9 0.7 0.7 0.7 % Sold - Baseload 49% 19% 7% 7% 7% - Peaking 0% 0% 0% 0% 0% Total 49% 19% 7% 7% 7% 2005 2006 2007 2008 2009 Data as of 9/30/04 Includes the Saltend Energy Centre

APPENDIX D: CONTRACTUAL PORTFOLIO MEXICO Estimated Generation (In Millions of mwh) - Baseload 0.0 1.1 2.0 2.0 2.0 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 0.0 1.1 2.0 2.0 2.0 Contractual Generation (In Millions of mwh) - Baseload 0.0 1.1 2.0 2.0 2.0 - Peaking 0.0 0.0 0.0 0.0 0.0 Total 0.0 1.1 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 9/30/04 Includes the Valladolid III Project